MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended
December 31, 2010
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis (MD&A), dated February 9, 2011, should be read in conjunction with the audited financial statements for the year ended December 31, 2010.
FORWARD-LOOKING INFORMATION
The MD&A is a review of our financial condition and results of operations. Our financial statements are prepared based upon Canadian Generally Accepted Accounting Principles (GAAP) and all amounts are in Canadian dollars unless specified otherwise. Certain statements contained herein are forward-looking statements, including, but not limited to, statements relating to: the expected increase in production and improved operational 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, operation and maintenance of the Long Lake Project as well as future expansions thereof, and OPTI's relationship with Nexen Inc. (Nexen); the potential reservoir complexities of the Project; the development and timing of well pads and timi ng of wells coming on production; the expected steam-to-oil-ratio (SOR) range for the Project and time expected to reach this range; the expected SOR or our original 90 well pairs; the expected decline in average SOR; the expected continuance of a high level of on-stream time; the potential cost and anticipated impact of additional steam capacity and resulting increase in bitumen production for the Project; the potential cost and anticipated impact of a diluent recovery unit to provide expected operating flexibility; the expected feedstock purchases for the Project; the expected 2011 bitumen production forecast for the Project as provided by the operator and the risk associated with this forecast; the expected increase in Premium Sweet Crude (PSC™) yields; the expected improvement to net field operating margin; the expected increase in the PSC™ premium OPTI receives relative to other synthetic crude oils; the potential advantages to staged steam assisted gravity drainage (SA GD) developments at Kinosis; the potential for a second Upgrader at Kinosis; the potential to approve a development plan for Kinosis and its expected cost; the potential sanctioning of Kinosis and its timing; the expected requirement of additional financial resources to develop future expansions at Kinosis and beyond; the ability of the Company to extend its foreign exchange hedging instruments, or if not extended, the cost associated with settling such instruments; the estimated reserves and resources of all of our lease areas; the expected business impact of International Financial Reporting Standards (IFRS) on OPTI’s financial statements; OPTI's financial outlook, expected netbacks at full production and expected annual free cash flows based on SOR assumptions for the Project; the expected long-term life of our assets at the Project; OPTI’s projected future revenues; OPTI's anticipated financial condition, material obligations and liquidity in 2011 and in the long term; the final outcome of OP TI’s expanded strategic alternatives review; and the impact of a positive outcome on our liquidity and capital resources; the expected likelihood that we will be unable to fund our 2012 financial commitments without a conclusion to our strategic alternatives review; the expected difficulty and expanse of additional funding; OPTI’s expected ability to continue as a going concern and the related factors which create significant doubt about this ability; and our estimated future tax asset. Forward-looking information typically contains statements with words such as “intend,” "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 a ssumptions, 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 f inancing; oil prices and market price for PSC™ and Premium Synthetic Heavy (PSH); foreign currency exchange rates and hedging instruments 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), filed on SEDAR and EDGAR and available at www.sedar.com and http://edgar.sec.gov, for a detailed discussion of these assumptions, risks and uncertainties. The forward-looking statements or information contained in this document are made as of the date hereof and OPTI undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable laws or regulatory policies.
Additional information relating to our Company, including our Senior note indentures and related debt documents are filed on SEDAR at www.sedar.com.
FINANCIAL HIGHLIGHTS
| | | Years ended | |
In millions | | 2010 | | | 2009 | | | 2008 | |
| Net loss | | $ | (274 | ) | | $ | (306 | ) | | $ | (477 | ) (1) |
| Net field operating loss | | | (65 | ) | | | (118 | ) | | | (58 | ) |
| Working capital | | | 64 | | | | 168 | | | | (25 | ) |
Total oil sands expenditures (2) | | | 96 | | | | 148 | | | | 706 | |
| Shareholders’ equity | | $ | 1,039 | | | $ | 1,311 | | | $ | 1,471 | |
Common shares outstanding (basic) (3) | | | 282 | | | | 282 | | | | 196 | |
Notes:
| (1) | Includes $369 million pre-tax asset impairment provision related to working interest sale to Nexen. |
| (2) | Capital expenditures related to Phase 1 and future expansion developments. Capitalized interest and non-cash additions or charges are excluded. |
| (3) | Common shares outstanding at December 31, 2010 after giving effect to the exercise of stock options would be approximately 285 million common shares. |
PROJECT STATUS
Operational results at the Long Lake Project (the Project) for the fourth quarter of 2010 improved relative to the previous quarter as we increased steam injection and bitumen production rates, although bitumen production did not increase as much as we had previously expected.
Fourth quarter bitumen production averaged approximately 28,100 barrels per day (bbl/d) (9,800 bbl/d net to OPTI), slightly higher than the previous quarter average of approximately 26,400 bbl/d (9,200 bbl/d net to OPTI). Steam injection increased month-over-month in response to reliable SAGD surface facilities and continued optimization of wells. Fourth quarter steam levels averaged approximately 157,900 bbl/d compared to 145,700 bbl/d in the previous quarter.
While steam injection rates were at record levels in December 2010, averaging approximately 172,300 bbl/d, we did not see a corresponding improvement in our bitumen production levels. We expected bitumen production to be higher than the December monthly average of approximately 29,100 bbl/d (10,200 bbl/d net to OPTI) in response to the increased steam injection. Although a short term lag in bitumen production can occur, consistently high steam rates without a corresponding increase in bitumen production could indicate greater reservoir complexity. This complexity could indicate the prevalence of high water saturation zones which we may need to heat through. Geologic data and analysis indicated higher water saturation zones make up only 3 to 5 percent of our reservoir by volume. Given recent results, the operator continues to adjust operat ional strategies in an effort to ensure optimal SAGD bitumen production.
January 2011 bitumen production declined from the previous month to average approximately 27,000 bbl/d (9,450 bbl/d net to OPTI) with lower steam injection levels of approximately 155,700 bbl/d. Our production and steam levels in January decreased from December primarily due to a number of electric submersible pump (ESP) failures in the field and some water treatment issues at the plant. These factors resulted in lower steam injection levels during
January, making it difficult to evaluate whether bitumen production will respond to increased steam in the near term. We expect the ESP replacements to be completed in early February, the water treatment issues to improve throughout the rest of the month, and anticipate that steam injection and bitumen production rates will continue to ramp up throughout 2011.
We currently have 85 well pairs receiving steam, with 77 capable of production and 8 in circulation mode. We continue to expect all 90 well pairs to be in production mode by the end of April.
Our recent all-in SOR average is approximately 5.8. The all-in SOR average includes steam to wells that are currently in steam circulation mode and wells early in the ramp-up cycle. Our all-in SOR is higher than previous months due to the increases in steam injection levels. We expect this higher SOR to decrease as bitumen production levels rise in response to higher steam injection levels. We expect our all-in SOR to decline over time as we convert circulating wells to production mode, maintain stable operations, work through any high water saturation zones, add further well pairs and allow our producing wells to mature. While we expect SOR to decline over time, the rate of decline is also affected by surface operations. A lack of surface operations reliability will negatively impact this expected improvement. With additional knowledge o f our reservoir gained through our ramp up to date, we expect that our long-term SOR will range between 3.0 and 4.0. We do not expect to reach this long-term SOR range until 2012 or later. The SOR for our original 90 wells pairs is expected to be in the high end of this range.
During the months of October and December, Upgrader units performed consistently, processing virtually all of our produced bitumen as well as approximately 11,000 (3,800 bbl/d net to OPTI) bbl/d of externally-sourced bitumen. In mid-November, we had a brief Upgrader interruption caused by a gasifier trip, which meant that we were temporarily unable to process all available bitumen through the Upgrader. Despite this interruption, our upgrader on-stream time averaged 90 percent for the fourth quarter, up from our on-stream time average of 81 percent in the third. PSCTM yields increased to an average of 67 percent over the quarter, up from 62 percent in the previous quarter. In January of 2011, the Upgrader performed consistently and processed virtually all of our produced bitumen. We are currently processing virtually all of our bitumen with recent PSC™ yields of approximately 70 percent. We continue to expect yields to increase to the design rate of 80 percent as operations are optimized.
With recent bitumen production levels, our need to supplement our bitumen production to provide enough through-put for the Upgrader is reduced. Therefore in 2011 we expect to purchase externally-sourced bitumen when economically beneficial or when SAGD bitumen production rates are low.
In mid-November 2010, we announced that we expected annual bitumen production volumes to average between 38,000 and 45,000 bbl/d (between approximately 13,000 and 16,000 bbl/d net to OPTI) in 2011, based on information provided by the operator of the Project. Based on operations since that time, including the ESP and water treatment issues and the possibility of additional reservoir complexities, we believe that achieving this forecast is at risk.
The performance of SAGD operations and the Upgrader may differ from our expectations. There are a number of factors related to the characteristics of the reservoir and operating facilities that could cause bitumen and PSC™ production to be lower than anticipated. See “Risk Factors – Operating Risks.”
On December 7, 2010 we announced approval of a $150 million capital program for 2011, with approved spending of $122 million at the Project. One of the key initiatives is the continued development of pads 12 and 13 at Long Lake. We expect to begin drilling in the first quarter of 2011, and anticipate that the 18 new well pairs will be available for bitumen production in 2012. The joint venture partners also approved engineering costs to evaluate additional steam capacity and a Diluent Recovery Unit (DRU). The steam expansion project, if approved, is expected to increase existing steam capacity by 10 to 15 percent by late 2012. The DRU, if approved, is expected to enable improved operating flexibility during periods of Upgrader downtime by allowing us to switch between streams of PSC™ and PSH more effectively. We are also considering increasing the natural gas inlet capacity to allo w us to maintain full steam production rates during period of Upgrader downtime when no syngas is produced, thereby further increasing the operating independence between our SAGD facilities and the Upgrader while maintaining the benefits of integration. Further capital spending to develop these projects requires approval by OPTI’s board of directors.
FUTURE EXPANSIONS
OPTI and Nexen continue to evaluate developing SAGD projects in approximately 40,000 bbl/d bitumen stages at Kinosis, the next development. A second Upgrader could be built once sufficient bitumen rates from the Kinosis area have been reached and economic conditions support the development of upgrading. Sanctioning the first stage of Kinosis in 2012 is subject to a number of factors including: improvement in our financial position; ramp-up of performance at Long Lake; the cost estimate to develop Kinosis; the commodity price environment; and stability in the financial markets.
As we announced in December 2010, OPTI is spending approximately $22 million in advancing engineering and detailed execution plans for Kinosis to the end of March 2011. If a development plan is approved by the joint venture partners, then further capital spending on Kinosis may be considered for approval by OPTI’s board of directors this year. Developing smaller SAGD projects is expected to allow us to lower the intensity of our capital expenditure program, reduce labour requirements and provide improved construction cost and execution control.
In 2011, OPTI will invest approximately $6 million for future expansions development at Leismer and Cottonwood.
LIQUIDITY
Our expected material obligations in 2011 include: interest payments on our Senior notes of US$189 million (excluding interest funded by our interest reserve account), our capital budget of $150 million and expected G&A costs of approximately $12 million. These expenditures amount to approximately $351 million. Additionally, we have a variable potential obligation with respect to our foreign exchange hedging instrument of $89 million with a current maturity date of September 2011. We expect to fund these costs with our existing financial resources of $363 million, which includes our $190 million revolving credit facility with a maturity date in December 2011, and our expected positive net field operating margin. In January, we borrowed $90 million under the revolving credit facility. We expect our net field operating margin to be posi tive in 2011; although not significantly positive until we reach higher levels of SAGD bitumen production. Commodity prices, Upgrader utilization, bitumen production and PSC™ yield will all affect our ability to generate positive net field operating margin.
As more fully described under “Liquidity and Capital Resources,” we may determine that our current financial resources are not sufficient in the context of these obligations.
STRATEGIC ALTERNATIVES REVIEW
OPTI’s Board of Directors remains committed to its review of strategic alternatives for the Company to address its overall leverage position. Strategic alternatives may include capital market opportunities, asset divestitures, and/or a corporate sale, merger or other business combination.
As stated under “Project Status,” SAGD production continues to be below expectations. Our strategic alternatives review has been underway since November 2009. Lower than expected bitumen production over the last seven months has negatively impacted our liquidity and has made it more difficult to achieve a transaction under our review. As a result of this performance, our financial commitments and our limited financial resources, OPTI has expanded its strategic alternatives to include seeking advice on capital structure adjustments to address its overall leverage position. Scotia Waterous Inc., TD Securities Inc. and Lazard Frères & Co. LLC, engaged as financial advisors to OPTI, will work in a coordinated manner to review the full range of strategic options available to the Company.
RESERVES AND RESOURCES
OPTI has a 35 percent interest in over 406 sections of land primarily on four leases in the Athabasca oil sands: Long Lake, Kinosis, Leismer and Cottonwood. We believe our existing lands will support approximately 430,000 bbl/d of raw bitumen production (150,000 bbl/d net to OPTI) from all leases including the Long Lake Project development. With a limited delineation program in the 2009/2010 winter drilling season, estimates of total reserve and resource volumes for 2010 did not change significantly from 2009.
The net present value before income taxes discounted at 10 percent (PV-10), under forecast prices and costs for our total proved reserves, has declined from $2,796 million in 2009 to $2,429 million in 2010. Our total company PV-10 under forecast prices and costs for our proved plus probable reserves has declined from $4,120 million in 2009 to $3,981 million in 2010. The 2010 decline calculations are primarily as a result of higher forecast operating costs and higher forecast sustaining capital.
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 and Kinosis leases effective December 31, 2010.
The McDaniel evaluation of our Long Lake reserves recognizes the impact of upgrading on the resources for Long Lake. Most of the raw bitumen from Long Lake will be upgraded and sold as PSC™ and butane, and is shown as synthetic crude oil or butane reserves for Long Lake. Bitumen was sold prior to Upgrader start-up, is planned to be sold during periods of Upgrader downtime, and is shown as bitumen reserves.
The recognition of reserves in the Kinosis area is largely due to the level of delineation of the lease, the regulatory approval for up to 140,000 bbl/d of bitumen production from Kinosis and the stage of the Kinosis development. The
evaluation of the reserves in the Kinosis area includes only the first two 40,000 bbl/d SAGD Kinosis developments, as future SAGD developments and potential future Upgrader developments are not within the timeframe to allow inclusion in the evaluation. As such, these reserves are shown as raw bitumen reserves only. This is a change from 2009 when the reserves were evaluated on an integrated basis. Upon formal sanctioning of the next development at Kinosis by OPTI and its joint venture partner, some of the probable reserves would be categorized as proved reserves.
McDaniel categorizes their estimates as proved, probable and possible reserves over various parts of the Long Lake and Kinosis leases. Proved, probable and possible reserves are booked over the Long Lake Project area (noted as “Long Lake”), and probable and possible reserves are booked over the Kinosis area.
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, 2010.
Summary of Reserve Volumes
As at December 31, 2010
(Volumes in millions of barrels)
| | | Raw Bitumen | | | Sales Volumes | |
| | | | | | PSC™ | | | Bitumen | | | Butane | |
| Proven | | | | | | | | | | | | |
Long Lake(1) | | | 195 | | | | 150 | | | | 7 | | | | 3 | |
| Proven plus probable | | | | | | | | | | | | | | | | |
Long Lake (2) | | | 339 | | | | 262 | | | | 11 | | | | 5 | |
Kinosis (2) | | | 390 | | | | - | | | | 390 | | | | - | |
| Total proven plus probable | | | 729 | | | | 262 | | | | 401 | | | | 5 | |
| Proven plus probable plus possible | | | | | | | | | | | | | | | | |
Long Lake (3) | | | 404 | | | | 314 | | | | 11 | | | | 6 | |
Kinosis(3) | | | 442 | | | | - | | | | 442 | | | | - | |
Total proven plus probable plus possible(3) | | | 846 | | | | 314 | | | | 453 | | | | 6 | |
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. |
In addition to the proved, probable and possible reserves, there are contingent resources associated with the Long Lake and Kinosis areas. 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 leases with a lower density of delineation have volumes that are categorized as contingent resources.
Bitumen resources are 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, 2010 on a 35 percent working interest, before royalties, is shown below:
Summary of Resource Volumes
As at December 31, 2010
(volumes in millions of barrels)
| | | Raw Bitumen (1) | |
| | | Contingent Resources (2) | | Prospective Resources (3) |
Long Lake (4) | | | 150 | | | | - | |
Kinosis (4) | | | 152 | | | | - | |
Leismer (4) | | | 591 | | | | - | |
Cottonwood (5) | | | 207 | | | | 335 | |
| Total | | | 1,100 | | | | 335 | |
| (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 AT FULL PRODUCTION AND ANNUAL FREE CASH FLOWS BASED ON SOR ASSUMPTIONS We have provided below an update to our estimated netbacks and free cash flows for the Project that were last updated in our second quarter MD&A filed on SEDAR on July 15, 2010. The netback calculation at each West Texas Intermediate (WTI) price reflects higher operating costs and has been updated for 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. The estimated annual free cash flows are based on a range of SORs. The long-term performance of our reservoir and respective SOR will be demonstrated over a number of years. Our rationale for providing this sensitivity is to provide a range of outcomes based on SOR, a key variable to our per barrel and annual netbacks. With additional knowledge of our reservoir gained throug h our ramp up to date, we have updated our estimate for SOR for the Project to between 3.0 and 4.0 and have therefore evaluated the impact of SOR within this range. This range captures our current SOR expectations for our existing well pairs at full production. We do not expect to reach full production, or this SOR range, until 2012 or later. The SOR for our original 90 well pairs is expected to be the high end of the range. We show netbacks and resultant free cash flows at full production due to the expected long-term life of our assets. We expect that the netbacks and annual free cash flows generated by our Project to be lower in the initial years following start-up than shown in this outlook due to the lower production volumes during ramp-up and an initially higher SOR. Management approved these netback and annual free cash flow calculations on February 9, 2011. For the per barrel and annual netbacks and annual free cash flows at a SOR of 3.0, we have assumed no additional steam capacity. In the annual ne tbacks and free cash flows for the SOR cases at 3.5 and 4.0, we have assumed that our planned steam expansion project has been approved and constructed. The one-time cost of the steam expansion project was not considered in the annual netback and free cash flow calculations as the capital expenditure impact is not significant over the life of the Project.
This financial outlook is intended to provide investors with a measure of the ability of our Project to generate netbacks and free cash flows assuming full production capacity. This outlook also intends to provide investors with an estimate of how our annual netbacks and resultant free cash flows at full production capacity could be impacted by the specified SOR range. We believe that the per barrel and annual netbacks and resultant free cash flows are the most appropriate financial measures to evaluate future Project performance. Corporate costs (other than corporate G&A expenses), interest, and other non-cash items are excluded from the estimates. The financial outlook may not be suitable for other purposes. The per barrel and annual netback and resultant annual free cash flow calculations as presented are non-GAAP financial measure s. The closest GAAP financial measure to the calculations 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 per barrel and annual netback and resultant free cash flows achieved by the Project could differ materially from these estimates. The material risk factors that we have identified toward achieving these netbacks and free cash flows are outlined under "Forward Looking Information" in our AIF. In particular, long-term SOR may be higher than we assumed, bitumen production may not reach our design rate of 72,000 bbl/d (25,200 bbl/d net to OPTI) or may require significantly more capital to be achieved, 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 fluctuat ion exposure; and our netback will be directly affected by the applicable
royalty regime relating to our business. The key assumptions relating to the netback and free cash flow estimates are set out in the notes beneath the tables.
Estimated Future Project Pre-Payout Netbacks at Full Production(1)
| | | WTI - US$75(2) | | | WTI - US$100(3) | |
| | | Per Barrel of Products Sold | | | Annual in millions | | | Per Barrel of Products Sold | | | Annual in millions | |
| | | $/bbl | | | $CDN/year | | | $/bbl | | | $CDN/year | |
Revenue(1) | | $ | 76.26 | | | $ | 547 | | | $ | 98.14 | | | $ | 704 | |
| Royalties and corporate G&A | | | (3.88 | ) | | | (28 | ) | | | (6.83 | ) | | | (49 | ) |
Operating costs(4) | | | | | | | | | | | | | | | | |
Natural gas(5) | | | (3.73 | ) | | | (27 | ) | | | (5.12 | ) | | | (37 | ) |
Other variable(6) | | | (2.38 | ) | | | (17 | ) | | | (2.38 | ) | | | (17 | ) |
| Fixed | | | (18.02 | ) | | | (129 | ) | | | (18.02 | ) | | | (129 | ) |
Property taxes and insurance(7) | | | (2.65 | ) | | | (19 | ) | | | (2.65 | ) | | | (19 | ) |
| Total operating costs | | | (26.78 | ) | | | (192 | ) | | | (28.17 | ) | | | (202 | ) |
| Netback | | $ | 45.60 | | | $ | 327 | | | $ | 63.14 | | | $ | 453 | |
| | (1) | The annual and 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 (20,100 bbl/d of PSC™ and 280 bbl/d of butane net to OPTI), and assume 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 "Forward-Looking Statements." |
| | (2) | For purposes of these calculations, with regard to the WTI price scenario of US$75, we have assumed natural gas costs of US$3.75/mmbtu (millions of British thermal units), foreign exchange rates of $1.00 = US$0.96, heavy/light crude oil price differentials of 24 percent of WTI and electricity sales prices of $40.00 per MegaWatt hour (MWh). Revenue includes sales of PSC™, bitumen, butane and electricity. |
| | (3) | For purposes of these calculations, with regard to the WTI price scenario of US$100, we have assumed natural gas costs of US$5.00/mmbtu, foreign exchange rates of $1.00 = US$1.00, heavy/light crude oil price differentials of 22 percent of WTI and electricity sales prices of $52.00 per MWh. Revenue includes sales of PSC™, bitumen, butane and electricity. |
| | (4) | Costs are in 2010 dollars. |
| | (5) | Natural gas costs are based on an estimate for a 3.0 SOR. |
| | (6) | 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. |
| | (7) | Property taxes are based on expected mill rates for 2010. |
On a long-term basis, we estimate sustaining capital costs required to maintain production at design rates of capacity to be approximately $80 million per year (net to OPTI). The increase from the prior estimate of approximately $60 million per year (net to OPTI) is due to an increase in the average annual turnaround sustaining capital costs and an increase in the average annual number of new wells to be drilled throughout the life of the project. The netbacks as shown are prior to abandonment and reclamation costs.
Estimated Future Project Pre-Payout Free Cash Flows at a Range of Potential SOR at Full Production
| | | WTI - US$75 | | | WTI - US$100 | |
| In millions ($CDN) | | SOR 3.0 (3) | | | SOR 3.5 (4) | | | SOR 4.0 (5) | | | SOR 3.0 (3) | | | SOR 3.5 (4) | | | SOR 4.0 (5) | |
| Netback per barrel | | $ | 45.60 | | | $ | 44.81 | | | $ | 39.02 | | | $ | 63.14 | | | $ | 62.05 | | | $ | 54.35 | |
Annual Netback (1) | | $ | 327 | | | $ | 321 | | | $ | 280 | | | $ | 453 | | | $ | 445 | | | $ | 390 | |
Annual Maintenance Capital (2) | | | (80 | ) | | | (80 | ) | | | (80 | ) | | | (80 | ) | | | (80 | ) | | | (80 | ) |
| Free Cash Flow | | $ | 247 | | | $ | 241 | | | $ | 200 | | | $ | 373 | | | $ | 365 | | | $ | 310 | |
| (1) | Annual netback amounts are based on the expected yield for the Project of 57,700 bbl/d of PSC™ and 800 bbl/d of butane (20,100 bbl/d of PSC™ and 280 bbl/d of butane net to OPTI), and assumes that the Upgrader will have an on-stream factor of 96 percent. Notes (2), (3), (4), (6) and (7) in the Estimated Future Project Pre-Payout Netbacks table above apply to each of these Annual Netbacks. These numbers are cash amounts for OPTI’s working interest share only and do not reflect non-cash charges. See “Forward-Looking Statements.” |
| (2) | Annualized Maintenance Capital, based on estimated sustaining capital costs required to maintain production at design rates of capacity, is expected to be approximately $80 million per year. For the SOR cases at 3.5 and 4.0, the long-term annual maintenance capital is not adjusted for the long-term maintenance capital expense or the initial capital expenditure (of approximately $200 million gross) for the potential steam expansion project, as these costs are not significant over the life of the Project. Please refer to notes (4) and (5) below for further information. |
| (3) | For purposes of this calculation, we have assumed an SOR of 3.0 with no additional expenditures for the steam expansion project; all other assumptions are the same as noted under Estimated Future Project Pre-Payout Netbacks. |
| (4) | For purposes of this calculation, we have assumed an SOR of 3.5 with completion of the steam expansion project, where current steam capacity would be increased in order to reach design capacity bitumen production rates. Higher operating costs of approximately $6 million at US$75 WTI and approximately $8 million at US$100WTI would result from incremental natural gas costs. |
| (5) | For purposes of this calculation, we have assumed an SOR of 4.0 with completion of the steam expansion project. With an SOR of 4.0 and the inclusion of additional steam capacity bitumen production is projected to reach rates of approximately 64,500 bbl/d (versus the Project’s design capacity of 72,000 bbl/d) on a gross basis. In this case, the annual netback is decreased by approximately $47 million at US$75 WTI and approximately $63 million at US$100 WTI due to approximately 5,000 bbl/d of feedstock purchases to supplement lower bitumen production levels and incremental natural gas costs. |
After the one-time investment for the potential steam expansion project, the reduction in annual free cash flow of $6 to $8 million at an SOR of 3.5, relative to the SOR of 3.0 case, is primarily attributable to higher expenses for natural gas. After the same one-time investment for the potential steam expansion project, the reduction in annual free cash flow of $47 to $63 million at an SOR of 4.0, relative to the SOR of 3.0 case, is primarily attributable to the reduction in bitumen production and royalties, and higher feedstock purchases, as well as higher natural gas expenses.
RESULTS OF OPERATIONS
| | | Years ended December 31 | |
| $ millions, except per share amounts | | 2010 | | | 2009 | | | 2008 | |
| Revenue, net of royalties | | $ | 250 | | | $ | 143 | | | $ | 198 | |
| Expenses | | | | | | | | | | | | |
| Operating expense | | | 214 | | | | 146 | | | | 84 | |
| Diluent and feedstock purchases | | | 86 | | | | 102 | | | | 164 | |
| Transportation | | | 15 | | | | 13 | | | | 8 | |
| Net field operating margin loss | | | (65 | ) | | | (118 | ) | | | (58 | ) |
| Corporate expenses | | | | | | | | | | | | |
| Interest, net | | | 212 | | | | 150 | | | | 33 | |
| General and administrative | | | 15 | | | | 17 | | | | 18 | |
| Financing charges | | | 16 | | | | 22 | | | | 1 | |
| Realized loss (gain) on hedging instruments | | | 86 | | | | (40 | ) | | | (116 | ) |
| (Loss) earnings before non-cash items | | | (394 | ) | | | (267 | ) | | | 6 | |
| Non-cash items | | | | | | | | | | | | |
| Foreign exchange (gain) loss | | | (127 | ) | | | (294 | ) | | | 373 | |
| Unrealized (gain) loss on hedging instruments | | | (45 | ) | | | 234 | | | | (160 | ) |
| Depletion, depreciation and accretion | | | 52 | | | | 26 | | | | 17 | |
| Impairment related to asset sale | | | - | | | | - | | | | 369 | |
| Loss on disposal of assets | | | - | | | | 1 | | | | - | |
| Future tax expense (recovery) | | | - | | | | 72 | | | | (116 | ) |
| Net loss | | $ | (274 | ) | | $ | (306 | ) | | $ | (477 | ) |
| Loss per share, basic and diluted | | $ | (0.97 | ) | | $ | (1.28 | ) | | $ | (2.43 | ) |
Operational Overview
The results of operations for year ended December 31, 2010, include SAGD and Upgrader results. 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. Revenue for the year ended December 31, 2010 was a combination of PSC™, PSH and power sales. Revenue for the year ended December 31, 2009 consisted of PSH and power sales for entire period and PSCTM only for the second, third and fourth quarters.
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”. On-stream factor is a measure of the proportion of time that the Upgrader is producing PSC™ and it is calculated as the percentage of hours the Hydrocracker Unit in the Upgrader is in operation. When the Upgrader is not in operation, results are adversely affected by the requirement to purchase diluent, which is blended with produced bitumen to generate a sales product called PSH. Revenue per barrel is lower for PSH than for PSC™. The majority of SAGD and Upgrader operating costs are fixed, so we expect that rising SAGD production volumes and a continued high level Upgrader on-strea m factor will lead to improvement in our net field operating margin. This
expected improvement would result from higher PSC™ sales. PSC™ yield represents the volume percentage of PSC™ generated from processing bitumen through the Upgrader.
Our net field operating loss for the year ended December 31, 2010 decreased to a loss of $65 million from a loss of $118 million in the preceding year. During the first six months of 2010 we experienced consistently increasing production volumes and sales, and net field operating margin improvements. During the third quarter, the plant experienced a combination of unplanned Upgrader maintenance, short-term pipeline restrictions and power outages which resulted in downtime of various Upgrader units. In October 2010, we recovered from third quarter interruptions but in November 2010, we experienced another brief Upgrader interruption due to a gasifier trip. In December 2010, we saw improved plant reliability with improving SAGD production levels.
The Upgrader on-stream factor for the year ended December 31, 2010 increased to 86 percent from 39 percent for the April 1, 2009 to December 31, 2009 time period. Our share of PSC™ sales increased to 6,100 bbl/d for the year ended December 31, 2010 compared to 1,800 bbl/d from April 1, 2009 to December 31, 2009 while our share of PSH sales decreased to 2,900 bbl/d for the year ended December 31, 2010 from 5,300 bbl/d in the same period of the preceding year.
During the fourth quarter of 2010, our net field operating loss decreased to $4 million from $20 million in the third quarter of 2010. The on-stream factor in the fourth quarter increased to 90 percent from 81 percent in the third quarter. PSC™ yields for the fourth quarter increased to 67 percent from 62 percent for third quarter. Our share of PSC™ sales in the fourth quarter increased to 9,000 bbl/d at an average price of $85/bbl from 4,800 bbl/d at an average price of $79/bbl in the previous quarter. PSH sales decreased to 1,400 bbl/d at an average price of $70/bbl from 4,800 bbl/d at an average price of $53/bbl. Power sales volumes decreased to 33,700 MWH from 34,400 MWH in the third quarter, however the average selling price increased to $46/MWH from $37/MWH. During the fourth quarter, diluent and feedstock purchases incr eased to $26 million from $21 million in the third quarter. For the three months ended December 31, 2010 diluent purchases were 550 bbl/d at an average price of $84/bbl compared to 700 bbl/d at an average price of $85/bbl for the previous quarter. Third party bitumen purchases during the fourth quarter increased to 3,800 bbl/d from 3,300 bbl/d in the third quarter. Operating expenses remained constant in the fourth quarter of 2010 as compared to the previous quarter.
Revenue
For the year ended December 31, 2010 we earned revenue net of royalties of $250 million compared to $143 million for the same period in 2009. For the year ended December 31, 2010 our share of PSC™ sales averaged 6,100 bbl/d at an average price of approximately $81/bbl compared to 1,800 bbl/d at an average price of approximately $73/bbl from April 1, 2009 to December 31, 2009. For the year ended December 31, 2010 our share of PSH averaged 2,900 bbl/d at an average price of approximately $62/bbl compared to 5,300 bbl/d at an average price of approximately $54/bbl for the same period in 2009. Our share of bitumen production for the year ended December 31, 2010 averaged 8,540 bbl/d compared to 4,400 bbl/d for the same period in 2009.
Our total revenue, net of royalties, diluent and feedstock expenses increased to $164 million for the year ended December 31, 2010 compared to $41 million for the same period in 2009. Increases to total revenue, net of royalties,
diluent and feedstock for the year ended December 31, 2010, compared to 2009, are due to increased bitumen production and higher PSC™ sales as a result of a higher Upgrader on-stream time and higher PSC™ yield in 2010 as well as higher prices received for PSC™ and PSH.
For the year ended December 31, 2010 we received pricing for PSCTM in-line with, or slightly better than, other synthetic crude oils. Pricing for PSH is at a discount in comparison to the pricing for PSCTM as PSH is a heavy crude. PSH pricing was further impacted in the third and fourth quarters of 2010 due to temporary industry-wide pipeline capacity restrictions, which resulted in lower than expected market prices on our PSH sales.
For the year ended December 31, 2010 we had power sales of $7 million representing approximately 146,200 megawatt hours (MWh) of electricity sold at an average price of approximately $51/MWh, compared to power sales of $5 million for the same period in 2009, which represented approximately 102,800 MWh at an average price of approximately $49/MWh.
Expenses
* Operating expenses
For the year ended December 31, 2010 operating expenses were $214 million compared to $146 million for the same period in 2009. Operating expenses are higher in 2010 as they include both SAGD and Upgrader results whereas 2009 operating expenses include a full year of SAGD results and only nine months of Upgrader results as the Upgrader was not considered ready for its intended use for accounting purposes until April 1, 2009.
Our operating expenses are primarily comprised of maintenance, labour, operating materials and services, and chemicals and natural gas. For the year ended December 31, 2010, we purchased an average of 24,400 gigajoules per day (GJ/d) of natural gas at an average price of $3.84/GJ compared to 22,100 GJ/d at an average price of $3.85/ GJ for the same period in 2009. Operating expenses in 2010 also increased due to annual maintenance at our cogeneration and sulphur plant units, downhole maintenance including ESP replacements and planned well work-overs and overall higher operating levels.
* Diluent and feedstock purchases
For the year ended December 31, 2010 diluent and feedstock purchases were $86 million compared to $102 million for the same period in 2009. Diluent purchases are used for blending with bitumen to produce PSH. For the year ended December 31, 2010 diluent purchases of $10 million represented 380 bbl/d at an average price of $84/bbl compared to purchases of $57 million representing 2,400 bbl/d at an average price of $67/bbl for the same period in 2009. Diluent purchases decreased in 2010 compared to 2009 due to a higher Upgrader on-stream factor in 2010 (which results in sales of PSC™ and does not require diluent) and the use of a portion of our own PSCTM as diluent for PSH sales.
In 2009 and 2010, we purchased third party bitumen to achieve certain minimum operating thresholds for efficiencies in the Upgrader which helps improve PSCTM yields. With higher SAGD production levels, the requirement to purchase third party barrels for this purpose is substantially lower. In 2011, we expect to purchase third party barrels and to
upgrade into PSC™ only during periods when we have stable Upgrader operations and when pricing conditions support the difference between the cost of such third party barrels and our expectations for PSC™ sales pricing.
For the year ended December 31, 2010 we purchased $76 million of third party bitumen representing approximately 3,400 bbl/d at an average price of $61/bbl compared to $45 million representing approximately 2,000 bbl/d at an average price of $61/bbl for the same period in 2009. The increase in third party bitumen purchases in 2010 is due to a higher on-stream factor of the Upgrader.
* Transportation
For the year ended December 31, 2010 transportation expenses were $15 million compared to $13 million for the same period in 2009. Transportation expenses were primarily related to pipeline costs associated with PSCTM and PSH sales. The increase in transportation expenses in 2010 was a result of the increase in pipeline volume commitments.
Corporate expenses
* Net interest expense
For the year ended December 31, 2010 net interest expense was $212 million compared to $150 million for the same period in 2009. The increase in 2010 was due to interest expense for the full year for the US$425 million First Lien Notes issued in November 2009 and for the new US$100 million First Lien Notes and the new US$300 million First Lien Notes both issued in August 2010. Interest expense in 2009 included interest related to the SAGD facilities for the entire year and interest related to the Upgrader only from April 1, 2009. Interest expense also includes the amortization of the discount related to the issuance of the Senior notes in 2009 and 2010. The remaining discount of $18 million will be amortized over the terms of the facilities.
For the year ended December 31, 2010 the increase in interest expense was marginally offset by the strengthening of the average Canadian dollar exchange rate, resulting in a decrease in recorded interest costs on our U.S. dollar-denominated debt.
* General and Administrative (G&A) Expense
For the year ended December 31, 2010 G&A expense was $15 million compared to $17 million for the same period in 2009. Included in G&A expense for 2010 was $4 million related to the strategic alternatives review and our employee retention program. For the year ended December 31, 2010 G&A expense was lower due to severance payments made in 2009 related to the re-organization of OPTI after the sale of the 15 percent working interest to Nexen. Included in G&A expense is a non-cash stock-based compensation expense for the year ended December 31, 2010 of $2 million compared to $1 million in 2009.
* Financing charges
For the year ended December 31, 2010, financing charges were $16 million compared to $22 million for the same period in 2009. Financing charges in 2010 relate to the issuance of the US$100 million First Lien Notes and the US$300 million First Lien Notes, and the amendment to our revolving debt facility. Financing charges in 2009 relate to the amendments to our revolving debt facility and the issuance of the US$425 million first Lien Notes.
* Net realized gain or loss on hedging instruments
For the year ended December 31, 2010 net realized loss on hedging instruments was $86 million compared to a gain of $40 million for the same period in 2009. The losses in 2010 relate to the settlements of foreign exchange hedging instruments of $44 million in the second quarter and $25 million in the fourth quarter and our realized commodity hedging losses of $16 million. The commodity losses were a result of our 2010 commodity hedging instruments of 3,000 bbl/d at strike prices between US$64/bbl and US$67/bbl when the average West Texas Intermediate (WTI) price for the year ended December 31, 2010 was US$79/bbl. The gains in 2009 were related to our US$80/bbl crude oil puts and our US$77/bbl crude oil hedging instruments. OPTI currently has no commodity hedges.
Non-cash items
* Foreign exchange gain
For the year ended December 31, 2010 foreign exchange translation was a $127 million gain compared to a $294 million gain for the same period in 2009. The gain is comprised of the re-measurement of our U.S. dollar-denominated long-term debt and cash. During 2010, the Canadian dollar strengthened from CDN$1.05:US$1.00 to CDN$0.99:US$1.00 resulting in a foreign exchange translation gain. The gains on the re-measurement of the debt are unrealized.
* Net unrealized gain or loss on hedging instruments
For the year ended December 31, 2010 net unrealized gain on hedging instruments was $45 million compared to a $234 million loss for the same period in 2009. The net unrealized gain is comprised of a $20 million unrealized gain on our commodity hedges due to the maturing of the instruments during the period and a $25 million unrealized gain on our foreign exchange hedging instruments. The foreign exchange hedging instrument gain is a result of the reclassification of the $44 million and $25 million realized cash outflows due to the settlements of foreign exchange hedging instruments during the year offset by a loss due to the strengthening of the Canadian dollar from CDN$1.05:US$1.00 to CDN$0.99:US$1.00. The loss for the corresponding period in 2009 relates to a strengthening of the Canadian dollar resulting in a loss on the foreign exchan ge hedging instruments and an increase in the future price of WTI during the year resulting in a loss on the commodity hedges.
* Depletion, depreciation and accretion (DD&A)
For the year ended December 31, 2010 DD&A was $52 million compared to $26 million in 2009. DD&A for 2010 relates to both SAGD facilities and Upgrader facilities whereas DD&A for 2009 was based in a full year of SAGD operations and nine months of the Upgrader from April 1, 2009. Additionally, production volumes have increased in 2010 which resulted in higher DD&A costs compared to 2009.
* Loss on disposal of assets
For the year ending December 31, 2010, loss on disposal of assets was nil compared to $1 million for the same period in 2009. The loss on disposal of assets in 2009 was primarily for information technology write-offs and costs incurred related to the working interest sale to Nexen.
* Future tax expense
For the year ended December 31, 2010, future tax expense was nil, compared to $72 million for the same period in 2009. For the year ended December 31, 2010, based on the recurrence of net field operating losses, we determined we do not meet the “more likely than not” criteria required for recognition of future tax assets and have therefore recognized a valuation allowance against our future tax assets. We will assess the need for this valuation allowance each reporting period. Recoveries in 2009 were primarily due to the benefit derived from losses from operations. OPTI had approximately $4.1 billion of available Canadian tax pools at December 31, 2010.
CAPITAL EXPENDITURES
The table below identifies expenditures incurred in relation to the Project, other oil sands activities and other capital expenditures.
| | | Years ended December 31 | |
| $ millions | | 2010 | | | 2009 | | | 2008 | |
| The Long Lake Project – Phase 1 | | | | | | | | | |
| Sustaining capital | | $ | 80 | | | $ | 83 | | | $ | 540 | |
| Capitalized operations | | | - | | | | 19 | | | | 32 | |
| Total Long Lake Project | | | 80 | | | | 102 | | | | 572 | |
| Expenditures on future expansions | | | | | | | | | | | | |
| Engineering and equipment | | | 12 | | | | 21 | | | | 64 | |
| Resource acquisition and delineation | | | 4 | | | | 25 | | | | 70 | |
| Total oil sands expenditures | | | 96 | | | | 148 | | | | 706 | |
| Capitalized interest | | | - | | | | 29 | | | | 139 | |
| Other capital expenditures | | | - | | | | (19 | ) | | | 45 | |
| Total cash expenditures | | | 96 | | | | 158 | | | | 890 | |
| Non-cash capital charges | | | 1 | | | | - | | | | 11 | |
| Total capital expenditures | | $ | 97 | | | $ | 158 | | | $ | 901 | |
For year ended December 31, 2010 we had sustaining capital expenditures of $80 million. As with all SAGD projects, new well pads must be drilled and tied-in to the SAGD central facility to maintain production at design rates over the life of the Project. The majority of the expenditures related to: improving water treatment through the addition of oil removal filters for oil and particulate removal from the produced water stream; progress on engineering and construction of two additional well pads 12 and 13; and the installation of additional ESPs in producing wells for better well control and enhanced bitumen extraction. We also drilled coreholes for development of future well pads, completed the tie-in of two saline water wells for increased water supply for steam generation ramp-up, completed the tie-in of the Pad 11 warm-up separator, and executed various operations optimization projects.
In 2010 we incurred $16 million on future expansions comprising $12 million for engineering and equipment and $4 million for resource delineation. These expenditures related primarily to the SAGD and Upgrader development at Kinosis.
OPTI and Nexen continue to evaluate developing SAGD projects in approximately 40,000 bbl/d bitumen stages at Kinosis. Depending on many factors, we may sanction the first stage of Kinosis in 2012. Additional stages of Kinosis SAGD would proceed thereafter, and a second Upgrader could be built once sufficient bitumen rates from Kinosis have been reached and economic conditions support the development of upgrading. Once the evaluation is complete, and should a new development plan be approved, OPTI would assess the book value of the Kinosis assets for impairment. If a new development plan is approved and the engineering completed to date cannot be utilized, this may result in an impairment of $75 million to $150 million.
The $1 million non-cash capital charges related to asset retirement costs.
SELECTED ANNUAL INFORMATION
In millions (except per share amounts) | | 2010 | | | 2009 | | | 2008 | |
| Total revenue | | $ | 250 | | | $ | 144 | | | $ | 198 | |
| Net loss | | | (274 | ) | | | (306 | ) | | | (477 | ) |
| Net loss per share, basic and diluted | | | (0.97 | ) | | | (1.28 | ) | | | (2.43 | ) |
| Total assets | | | 3,973 | | | | 3,824 | | | | 4,472 | |
| Total long-term liabilities | | | 2,570 | | | | 2,300 | | | | 2,656 | |
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. In 2010, revenue was comprised of a combination of PSCTM, PSH and power sales.
Net loss has been influenced by increasing interest expense, fluctuating foreign exchange translation gains and losses primarily related to re-measurement of our U.S. dollar denominated long-term debt and fluctuating realized and unrealized gains and losses 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, interest expense of $150 million, a $ 40 million realized gain on hedging instruments, a $294 million foreign exchange translation gain, a $234 million unrealized loss on hedging instruments, and a future tax expense of $72 million. During 2010, we had a net field operating loss of $65 million, interest expense of $212 million, an $86 million realized loss on hedging instruments, a $127 million foreign exchange translation gain, and a $45 million unrealized gain on hedging instruments.
Our total assets decreased in 2009 from 2008 as a result of the proceeds from the asset sale in January 2009 offset by capital expenditures on the Project and future expansion development. Total assets increased in 2010 as a result of capital expenditures on the Project and future expansion development. Increases in long-term financial liabilities in 2009 from 2008, 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. Increase in long-term liabilities in 2010 is a result of the issuance of US$100 million First Lien Notes and US$300 million First Lien Notes offset by a decrease in the measurement amount of the interest and principal due to a strengthening Canadian dollar from CDN$1.05:US$1.00 to CDN$0.99:US$1.00. In January 2011 we have drawn $90 million on our revolving credit facility.
SUMMARY FINANCIAL INFORMATION
| In millions (unaudited) | | 2010 | | | 2009 |
| (except per share amounts) | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | |
| Revenue | | $ | 81 | | | $ | 59 | | | $ | 61 | | | $ | 50 | | | $ | 43 | | | $ | 38 | | | $ | 34 | | | $ | 29 | |
| Net (loss) earnings | | | (26 | ) | | | (46 | ) | | | (152 | ) | | | (50 | ) | | | (212 | ) | | | 12 | | | | (9 | ) | | | (97 | ) |
| (Loss) earnings per share, basic and diluted | | $ | (0.09 | ) | | $ | (0.16 | ) | | $ | (0.54 | ) | | $ | (0.18 | ) | | $ | (0.75 | ) | | $ | 0.04 | | | $ | (0.04 | ) | | $ | (0.50 | ) |
Operations during 2009 and 2010 represent initial stages of our operations at relatively low operating volumes. Our operating results are expected to improve as SAGD production increases and the Upgrader produces higher volumes of PSCTM.
Net loss of $97 million in the first quarter of 2009 was associated with operating expenses in the early stages of SAGD operations that operated at relatively low volumes which led to a net field operating loss of $31 million. In addition, we had a $75 million foreign exchange loss offset by a net realized and unrealized gain on hedging instruments of $46 million. Net loss of $9 million in the second quarter of 2009 was comprised of a net field operating loss of $28 million, net interest expense of $42 million, unrealized loss on our hedging instruments of $137 million offset by a foreign exchange translation gain of $171 million, and a future tax recovery of $32 million. Net earnings of $12 million in the third quarter of 2009 were primarily due to a $162 million foreign exchange translation gain offset by unrealized losses on hedging in struments related to our foreign exchange and commodity hedges, and our net field operating loss. The net loss of $212 million in the fourth quarter for 2009 includes a net field operating loss of $21 million, interest expense of $43 million, an unrealized loss on our hedges of $36 million offset by a foreign exchange gain of $36 million, and a future tax expense of $119 million that resulted from the recognition of a future tax asset valuation allowance.
During the third quarter of 2009 OPTI issued 86 million common shares, by way of public offering, increasing the total issued and outstanding common shares from approximately 196 million to 282 million. This reduces our earnings or loss per share by approximately 30 percent in the quarters subsequent to this common share issuance.
During the first quarter of 2010 we had a net field operating loss of $29 million, $49 million in interest expenses and a $26 million unrealized loss on hedging instruments offset by a foreign exchange gain of $72 million. During the second quarter of 2010 we had a net field operating loss of $11 million, $49 million in interest expenses, a $48 million loss on hedging instruments and a $104 million foreign exchange loss offset by a $77 million unrealized gain in hedging instruments. During the third quarter of 2010 we had a net field operating loss of $20 million, $55 million in
interest expenses, and $14 million in financing charges, offset by a $77 million unrealized foreign exchange gain. During the fourth quarter of 2010 we had a net field operating loss of $4 million, $59 million in interest expense, and $30 million in realized hedging losses offset by a $81 million unrealized foreign exchange gain.
SHARE CAPITAL
At February 9, 2010, OPTI had 281,749,526 common shares and 3,471,500 common share options outstanding. The common share options have a weighted average exercise price of $3.63 per share.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2010 we had approximately $363 million of financial resources, consisting of $173 million of cash on hand and $190 million of credit capacity under our revolving credit facility. Our cash and cash equivalents are invested exclusively in money market instruments issued by major Canadian banks. In addition, at December 31, 2010 we had US$87 million in an interest reserve account associated with our US$300 million First Lien Notes. Our long-term debt consists of US$1,750 million of Secured Notes, US$525 million First Lien Notes and US$300 million First Lien Notes (collectively, our “Senior Notes”) and a $190 million revolving credit facility. In January 2011, we borrowed $90 million on our revolving credit facility.
During the fourth quarter of 2010, US$420 million of the US$620 million foreign exchange hedging instruments were extended to September 30, 2011 at an average rate of CDN$1.22:US$1.00 and US$200 million of foreign exchange hedging instruments were settled for a net fixed payment of $25 million. The potential cash outflow for the US$420 million maturing in September 2011 will be a function of the foreign exchange rate in effect at the maturity date. OPTI may seek an extension of the remaining US$420 million instruments past the current maturity date, among other factors, to preserve liquidity. The accounting measurement of our foreign exchange hedging instruments at the December 31, 2010 foreign exchange rate of CDN$0.99:US$1.00 is $89 million. The actual future cash settlement could be materially different, as a $0.01 change in the foreig n exchange rate will change this obligation by approximately $4 million.
Expected cash outflows for 2011 include a capital budget of $150 million which includes $122 million primarily directed at initiatives to increase production and ensure the long-term reliability of the Project, $22 million for engineering and detailed execution plans for Kinosis to the end of March and $6 million for development of Leismer and Cottonwood. Additional cash outflows include US$218 million in interest payments due with respect to our Senior Notes (including interest funded by our interest reserve account) and the potential cash settlement of our foreign exchange hedging instruments. Our financial resources will also be affected by net field operating margin. Our net field operating margin was a loss of $65 million in 2010 although it improved from a loss of $29 million in the first quarter of 2010 to a loss of $4 million in the fourth quarter of 2010. In order for the net field operating margin to become positive, some or all of the following will be required: increase in bitumen volumes; continued high on-stream factor; stable or increasing commodity prices (in particular, WTI); a PSC™ yield approaching our design rate of 80 percent; and stable operating costs. We do not expect that our net field operating margin will be sufficiently positive in 2011 to cover all of our commitments.
For the year ended December 31, 2010 cash used by operating activities was $374 million, cash provided by financing activities was $397 million and cash used by investing activities was $193 million. These cash flows, combined with a translation loss on our U.S. dollar denominated cash of $15 million, resulted in a decrease in cash and cash equivalents during the year of $185 million. During 2010 we used our cash on hand and net proceeds from the issuance of US$100 million First Lien Notes and US$300 million First Lien Notes to fund our capital expenditures and operational activities, to repay $50 million borrowed on our revolving credit facility and to fund an interest reserve account of approximately US$87 million to fund the semi-annual interest payments relating to the US$30 0 million First Lien Notes. In 2011, our primary sources of funding include our existing cash, the remaining undrawn balance under the revolving credit facility and expected future revenue.
We have annual interest payments of US$47 million each year until maturity on the US$525 million First Lien Notes due in 2012. In addition, we have annual interest payments of US$29 million each year until maturity on the US$300 million First Lien Notes due in 2013, which will be funded by our US$87 million interest reserve account, and annual interest payments of US$142 million each year until maturity on the US$1,750 million Secured Notes due in 2014. On a long-term basis, we estimate our share of capital expenditures required to sustain production at or near planned capacity for the Project will be approximately $80 million per year prior to the effects of inflation.
With respect to our Secured 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 and costs discounted at 10 percent. Based on our 2010 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 considerations, such as restrictions under the First Lien Notes and $190 million revolving credit facility, are expected to be more constraining than this limitation.
Our revolving credit facility matures in December 2011. The facility requires adherence to a debt-to-capitalization covenant that does not allow our debt-to-capitalization ratio to exceed 75 percent, as calculated on a quarterly basis. The ratio is calculated based on the book value of debt and equity. The book value of debt is adjusted for the effect of any foreign exchange derivatives issued in connection with the debt that may be outstanding. Our book value of equity is adjusted to exclude the $369 million increase to deficit as a result of the asset impairment associated with the working interest sale to Nexen and to exclude the $85 million increase to the January 1, 2009 opening deficit as a result of new accounting pronouncements effective on that date. Accordingly, at December 31, 2010, for the purposes of this ratio calculation, o ur debt would be increased by the amount of our foreign exchange hedge liability in the amount of $90 million and our deficit would be reduced by $455 million. With respect to U.S. dollar denominated debt and foreign exchange hedging instruments, for purposes of the total debt-to-capitalization ratio, the debt and foreign exchange hedging instruments are 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 hedging instruments, which is subject to mark-to-market variability and average foreign exchange rate changes during the quarter. The total debt-to-capitalization calculation for at December 31, 2010 is 64 percent.
In November 2009 we initiated a review to explore strategic alternatives for enhancing stakeholder value. If such a transaction is completed, 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. In January 2011, OPTI expanded its strategic alternatives to include seeking advice on capital structure adjustments to address its overall leverage position.
OPTI has limited financial resources. With its current capital structure and nature of operations, we have limited capacity to reduce costs. To preserve and maintain liquidity, management has borrowed a portion of the revolving credit facility, as well as approved a conservative capital expenditures program for 2011. Consideration of future expenditures will be evaluated balancing the interests of improving the Project and other assets and preserving liquidity.
In mid-November 2010, we announced that we expected annual bitumen production volumes to average between 38,000 and 45,000 bbl/d (between approximately 13,000 and 16,000 bbl/d net to OPTI) in 2011, based on information provided by the operator of the Project. Based on operations since that time, including the ESP and water treatment issues and the possibility of additional reservoir complexities, we believe that achieving this forecast is at risk. By achieving these forecast levels of production, extending our foreign exchange hedging instruments and maintaining full access to our revolving credit facility, among other factors, we expect to have sufficient financial resources to meet our financial obligations in 2011. Failure to achieve forecast bitumen production levels, failure to extend our foreign exchange hedging instruments or failu re to maintain full access to the revolving credit facility, are the primary risks to our liquidity in 2011. We may determine that our financial resources are insufficient. It is unlikely that we can fund our 2012 financial commitments without a conclusion to our expanded strategic alternatives review. We have significant maturities of debt that would need to be refinanced, in 2012, 2013 and 2014.
The development of future expansions, such as Kinosis, will require significant financial resources. Subject to approvals by the board, at Kinosis, we have announced a proposed staged SAGD development in approximately 40,000 bbl/d bitumen stages prior to building an upgrading facility. In addition, the 2011 capital budget includes engineering costs to evaluate additional steam capacity and a Diluent Recover Unit (DRU) for the Project. Although there has been a consideration of a Kinosis development sanctioning in 2012 and construction of the steam expansion project and DRU at the Project, we expect to require the conclusion of the expanded strategic alternatives review before we could proceed with construction of these projects. We expect to require additional financial resources to develop the future expansions.
The continued access to our revolver is a key financial risk in 2011. 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. Our ability to make further borrowings on the facility is governed by compliance with the terms and conditions set forth in the revolving credit facility agreement. These include confirmations that the representations and warranties in our loan documents are correct on the date of the new borrowing, that no event of default has occurred and that there has not been a change or development that would constitute a material adverse effect. Certain payment related defaults on our Senior notes and our joint venture agreement with Nexen are considered events of default under our revolving credit facility. More generall y, the evaluation of events that would constitute a material adverse effect is
dependent on the facts in question. There may be individual or collective events whereby we determine that such an event has occurred and we are unable to make new borrowings on the revolver.
Our rate of production increase will have a significant impact on our financial position in the next 12 months and beyond. Our net field operating margin in 2010 and in 2009 was 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. Delays in ramp-up of SAGD production, operating issues with the SAGD or Upgrader operations, deterioration of commodity prices and/or inability to extend foreign exchange hedging instruments could result in additional funding requirements that are greater and earlier than we h ave estimated. Although OPTI was able to raise new debt and equity in 2009 and 2010, market conditions remain relatively volatile. There can be no assurance that market conditions will allow OPTI to access additional capital if we desire to do so. Should the Company require any additional funding, it will likely be difficult and expensive to obtain. In addition, certain covenants in our existing credit indentures and revolving credit facility limit the amount of additional debt we can incur.
For 2011 we have exposure to commodity pricing as we have not entered into any commodity hedges (risks associated with our hedging instruments are discussed in more detail under “Financial Instruments”). The majority of our operating and interest costs are fixed. Aside from changes in the price of natural gas, our operating costs will neither decrease nor increase significantly as a result of fluctuations in WTI prices other than with respect to royalties to the Government of Alberta, which increase on a sliding scale at WTI prices higher than CDN$55/bbl. Collectively, this means that the variability of our financial resources will primarily be influenced by production rates and resulting PSCTM sales, operating expenses and by foreign exchange rates .
CREDIT RATINGS
OPTI maintains a corporate 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 as at February 9, 2011.
| | S&P | Moody's |
| OPTI Corporate Rating | CCC- | Caa3 |
| Revolving Credit Facility | CCC+ | B2 |
| First Lien Notes – US$525 million | CCC+ | B3 |
| First Lien Notes – US$300 million | CCC+ | Caa1 |
| Secured Notes – US$1,000 million | CCC | Ca |
| Secured Notes – US$750 million | CCC | Ca |
On December 14, 2010, S&P lowered OPTI’s corporate rating from CCC+ to CCC-, lowered the rating on the revolving credit facility from B to CCC+, lowered the ratings on the US$525 million and US$300 million First-Lien
Notes from B to CCC+, and lowered the ratings on the US$1,000 million and US$750 million Secured Notes from B- to CCC. S&P has also downgraded their ratings outlook from stable to negative.
On February 2, 2011, Moody’s lowered OPTI’s corporate rating from Caa2 to Caa3, lowered the rating on the revolving credit facility from B1 to B2, lowered the ratings on the US$525 million notes from B2 to B3, lowered the ratings on the US$300 million First-Lien Notes from B3 to Caa1, and lowered the ratings on the US$1,000 million and US$750 million Secured Notes from Caa3 to Ca. Moody’s negative rating outlook remains unchanged.
A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision and withdrawal at any time by the rating organization.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
During the year ended December 31, 2010 our long-term debt increased by $270 million due to the issuance of US$100 million First Lien Notes and US$300 million First Lien Notes offset by a decrease in the measurement amount for accounting purposes of the interest and principal due to a strengthening Canadian dollar from CDN$1.05:US$1.00 to CDN$0.99:US$1.00. In addition, in January 2011 we borrowed $90 million on our revolving credit facility.
The following table shows our contractual obligations and commitments related to our financial liabilities at December 31, 2010.
| In $ millions | | Total | | | 2011 | | | | 2012–2013 | | | | 2014–2015 | | | Thereafter | |
Accounts payable and accrued liabilities(1) | | $ | 75 | | | $ | 75 | | | $ | - | | | $ | - | | | $ | - | |
| Hedging instruments (foreign exchange) | | | 89 | | | | 89 | | | | - | | | | - | | | | - | |
Long-term debt (Senior Notes - principal)(2) | | | 2,562 | | | | - | | | | 821 | | | | 1,741 | | | | - | |
Long-term debt (Senior Notes - interest)(3) | | | 745 | | | | 217 | | | | 387 | | | | 141 | | | | - | |
Long-term debt (Revolving facility principal)(4) | | | - | | | | - | | | | - | | | | - | | | | - | |
Capital leases(5) | | | 64 | | | | 3 | | | | 6 | | | | 6 | | | | 49 | |
Operating leases and other commitments(5) | | | 64 | | | | 10 | | | | 21 | | | | 7 | | | | 26 | |
Contracts and purchase orders(6) | | | 5 | | | | 5 | | | | - | | | | - | | | | - | |
| Total commitments | | $ | 3,604 | | | $ | 399 | | | $ | 1,235 | | | $ | 1,895 | | | $ | 75 | |
| | (1) | Excludes accrued interest expense related to the Senior Notes. These costs are included in (3). |
| | (2) | Consists of principal repayments on the Senior Notes, translated into Canadian dollars using an exchange rate of CDN$0.99 to US$1.00 as at December 31, 2010. |
| | (3) | Consists of scheduled interest payments on the Senior Notes, translated into Canadian dollars using an exchange rate of CDN$0.99 to US$1.00 as at December 31, 2010. |
| | (4) | As at December 31, 2010, we have an undrawn $190 million revolving credit facility. In January 2011, we have drawn $90 million on this 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 relative to our total commitments. We do not consider such amounts material. |
| | (5) | Consists of our share of future payments under our product transportation agreements with respect to future tolls during the initial contract term. |
| | (6) | Consists of our share of commitments associated with contracts and purchase orders in connection with the Long Lake Project and our other oil sands activities associated with future expansions. |
OFF-BALANCE-SHEET ARRANGEMENTS
We have no off-balance-sheet arrangements.
TRANSACTIONS WITH RELATED PARTIES
We have no transactions with related parties.
CONTROLS AND PROCEDURES
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, 2010, 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 requ ired 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 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 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, 2010, 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, 2010.
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.
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 calculation of future cash flows based on reserves is dependent on a number of estimates including: production volumes which include estimates and projections of assessment of engineering data, projected future rates of production, characteristics of bitumen reservoirs, commodity prices, foreign exchange rates, operating costs and sustaining capital expenditures. Future cash flows are also affected by estimates for 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 price s 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.
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.
Going concern
The preparation of financial statements in accordance with Canadian GAAP requires the use of certain critical accounting estimates and requires management to exercise its judgment in the process of applying the Company’s accounting policies. These areas are disclosed in note 2 to the financial statements.
Since inception, the Company has incurred significant losses from operations and negative cash flows from operating activities, and has an accumulated deficit at December 31, 2010 of $988 million. OPTI has significant debt and contractual commitments, as outlined in the notes to the financial statements, that will necessitate cash outflows. OPTI has limited financial resources and significant levels of fixed costs in terms of our interest payments and the majority of our operating costs. Based in large part on achieving forecast levels of SAGD production and full access to our revolving credit facility, we expect to have sufficient financial resources to meet our obligations in 2011. Failure to achieve forecast bitumen production levels, changes in resource prices or foreign exchange rates and full access to the revolving credit fac ility are the primary risks to our liquidity in 2011. Many of these factors are outside of the control of management. OPTI may require funding from capital markets or alternative sources. There can be no assurances that OPTI will be successful securing additional resources. These factors create significant doubt about OPTI’s ability to continue as a going concern and therefore OPTI may be unable to realize its asset and discharge its liabilities in the normal course of operations. OPTI’s board of directors initiated a review to explore strategic alternatives to address the Company’s overall leverage position. Strategic alternatives may include capital market opportunities, asset divestitures, and/or a corporate sale, merger or other business combinations. In January 2011, OPTI expanded its strategic alternatives to include seeking advice on capital structure adjustments to address its overall leverage position. There can be no assurances the OPTI will be successful in these activities.
The financial statements have been prepared on the basis that OPTI will continue to operate as a going concern, which means we expect to realize our assets and settle liabilities and commitments in the normal course of business. The report of the independent auditors dated February 9, 2011 is not qualified. The statements do not reflect adjustments in the carrying values of assets and liabilities reported, revenue or expenses, and the classification used on the statement of financial position that would be necessary if the going concern assumption was not appropriate. Such adjustments would be material.
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 expansions. 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 developmen ts, 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 impact future accretion expense and future earnings.
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 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 engi neers, does not sufficiently outweigh negative factors, such as our net field operating loss in 2010 and 2009. 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 $228 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 may result in increased depletion, reduced earnings and reduced net book value of SAGD assets if such a revision resulted in an accounting impairment. 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 may resul t in increased depreciation, reduced earnings and a reduced net book value of SAGD and Upgrader facilities.
NEW ACCOUNTING PRONOUNCEMENTS
International Financial Reporting Standards (IFRS)
The Canadian Accounting Standards Board announced that existing Canadian GAAP will 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’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 and the implementation and review phase are ongoing at December 31, 2010.
Measurement Impact of IFRS
Based on our evaluation to date and 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, the accounting for decommissioning obligations and the treatment of flow-through shares. We are also assessing the exemptions to full restatement available under IFRS. Our IFRS analysis will not be complete until March 2011 and there may be other differences identified.
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 anticipate using the oil and gas exemption, the share based payment exemption, the lease exemption, the decommissioning liability exemption and the borrowing cost exemption as outlined in Appendix D in IFRS 1 “First-time adoption of IFRS”.
IFRS requires us to conduct an asset impairment test at the date of adoption of IFRS on January 1, 2010 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 both undiscounted and 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 post-transition, IFRS permits subsequent recovery of such write downs in future periods to the extent that fair value increases. Upon adoption of IFRS on January 1, 2010, OPTI does not expect to have an asset impairment.
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 in IFRS 6 “Exploration for and Evaluation of Mineral Resources”, which creates a new category of long-term assets, identified as exploration and evaluation assets (E&E). IFRS is consistent 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 assessment indicates that our development expenditu res meet the recognition criteria in relation to PP&E, and no impact on the measurement of PP&E is expected. Approximately $250 million to $275 million is expected to be re-classified to E&E assets from PP&E as of January 1, 2010.
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 which allows cost previously capitalized under full-cost accounting to be used as the opening cost basis under IFRS. OPTI anticipates that it will utilize this exemption for its oil and gas assets previously accounted for under the full-cost standard. In addition IFRS requires that significant parts of an asset are recognized and depreciated separately whereas 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 expect our accounting policy for depletion to be based on proved and probable reserves. As we anticipate utilizing the oil and gas exemption this change would be effective for periods after January 1, 2010 commencing with comparatives as reported in March 2011.
Under Canadian GAAP, transaction costs that are directly attributable to long-term debt can be either netted off the associated debt and amortized into income using the effective interest method or expensed as incurred. We have chosen a policy under Canadian GAAP to expense these costs as incurred. Under IFRS, these costs must be netted off the associated debt and amortized into income using the effective interest method. This is expected to result in a decrease to our opening deficit and a decrease to our long-term debt of approximately $40 million to $50 million at January 1, 2010.
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. 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. Under IFRS, only under extremely rare circumstances where no reliable estimate can be made, a liability is not recognized. This is expected to result in increase in the decommissioning liability in relation to the Upgrader of approximately $5 million to $10 million with a corresponding increase to t he related asset at January 1, 2010. 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. The discount rate to be used is the pre-tax risk-free rate that reflects current market assessments as opposed to a credit-adjusted risk free rate as required under Canadian GAAP. This is expected to result in an increase to our decommissioning obligation of approximately $10 million to $15 million with an associated increase in our PP&E of approximately $7 million to $10 million and opening deficit of approximately $3 million to $5 million at January 1, 2010.
Flow-through shares are a Canadian tax incentive which is the subject of specific guidance under Canadian GAAP, however there is no specific guidance under IFRS. We anticipate adopting a policy with respect to flow-through shares whereby the proceeds from the offering are to be allocated between the sale of the shares and the sale of the tax benefit. The allocation is made based on the difference between the quoted market price of the existing shares and the amount an investor pays for the flow through shares. A liability is then established for this difference that is reversed upon renunciation of the tax benefit. The difference between this liability and the deferred tax liability is
recorded as an income tax expense. This would result in a re-classification between deficit and common shares at January 1, 2010 of approximately $40 million to $50 million.
Under Canadian GAAP, our policy is to capitalize interest that was directly related to our long-term debt for major development projects and as such we capitalized directly attributable interest on the Project until commencement of commercial operations. Under IFRS, interest that is directly attributable to the acquisition, construction or production of a qualifying asset should be capitalized as well as any interest on funds borrowed generally for the purposes of obtaining qualifying assets. As a result interest on general borrowings for future expansion development assets should be capitalized. As we anticipate using the borrowing cost exemption, this change would be effective for periods after January 1, 2010 commencing with comparatives as reported in March 2011.
IFRS requires the expense relating to employee options to be recognized individually for each vesting tranche over the applicable vesting period whereas under Canadian GAAP, the expense was recognized on a straight line method over the total service period. This change is anticipated to result in an increase to contributed surplus and opening deficit of approximately $1 million to $2 million at January 1, 2010.
Under Canadian GAAP, when there are changes to the substantially enacted tax rates, the future tax impact is recorded directly into earnings. IFRS requires that all deferred taxes be recognized into income except when the transaction that gave rise to the deferred tax is recognized directly into equity, such as the case with share issuance costs, the deferred taxes including changes in tax rates should be recorded into equity. This is anticipated to result in a re-classification between deficit and common shares at January 1, 2010 of approximately $1 million to $2 million.
NON-GAAP FINANCIAL MEASURES
The term net field operating margin (loss) does not have any standardized meaning according to Canadian GAAP. It is therefore unlikely to be comparable to similar measures presented by other companies. We have presented this measure on a consistent basis from period to period and plan to do so in the future. We consider net field operating margin (loss) to be an important indicator of the performance of our business as a measure of the performance of the Project and our ability to fund interest payments and invest in capital expenditures. The most comparable Canadian GAAP financial measure is earnings (loss) before taxes. For the periods noted, the following is a reconciliation of loss before taxes to net field operating loss.
| | | Years ended December 31, | |
| $ millions | | 2010 | | | 2009 | | | 2008 | |
| Loss before taxes | | $ | (274 | ) | | $ | (234 | ) | | $ | (593 | ) |
| Interest, net | | | 212 | | | | 150 | | | | 33 | |
| General and administrative | | | 15 | | | | 17 | | | | 18 | |
| Financing charges | | | 16 | | | | 22 | | | | 1 | |
| Impairment related to asset sale | | | - | | | | - | | | | 369 | |
| Loss on disposal of assets | | | - | | | | 1 | | | | - | |
| Foreign exchange (gain) loss | | | (127 | ) | | | (294 | ) | | | 373 | |
| Net realized loss (gain) on hedging instruments | | | 86 | | | | (40 | ) | | | (116 | ) |
| Net unrealized (gain) loss on hedging instruments | | | (45 | ) | | | 234 | | | | (160 | ) |
| Depletion, depreciation and accretion | | | 52 | | | | 26 | | | | 17 | |
| Net field operating loss | | $ | (65 | ) | | $ | (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 OPTI. OPTI has policies and procedures in place that govern the credit risk it will assume. OPTI evaluates credit risk on an ongoing basis including an evaluation of counterparty credit rating and counterparty concentrations measured by amount and percentage. OPTI’s objective is to have no credit losses.
The primary sources of credit risk arise from the following financial assets: (1) cash and cash equivalents; (2) interest reserve account; (3) accounts receivable; and (4) derivative instruments. OPTI 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, 2010, OPTI has no financial assets that are past due or impaired due to credit-risk-related defaults.
* Cash and Cash Equivalents
OPTI has cash deposits and money market investments with Canadian banks. Counterparty selection is governed by the OPTI’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, 2010 the amount in cash and cash equivalents was $173 million and the maximum exposure to a single counterparty was $39 million with a major Canadian bank.
As at December 31, 2010, the remaining terms on investments made by OPTI are less than 29 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.
*Interest reserve account
As at December 31, 2010, there was US$87 million held in an interest reserve account to fund the semi-annual interest payments on the US$300 million First Lien Notes until maturity in 2013. OPTI is permitted to invest these funds in specific investment instruments. These funds are currently invested in U.S. Treasury bills which provide a highly rated and secure investment alternative to ensure security of principle invested.
*Accounts Receivable and Deposits
OPTI’s accounts receivable include amounts due from Nexen related to operating activities and Nexen Marketing related to marketing activities as well as deposits for operating expenses related to advances on joint venture expenses required under the joint venture agreement with Nexen. OPTI’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.
*Derivative Instruments
OPTI periodically uses instruments to hedge certain of the projected 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. Currently OPTI only holds foreign exchange derivatives to which the counterparties are major Canadian and international banks and lenders under OPTI’s revolving credit facility. Our exposure to non-payment from any single institution at December 31, 2010, is approximately 37 percent of the value of these derivative instruments if the instruments are in a gain position relative to the Company.
Liquidity Risk
Liquidity risk is the risk that OPTI will not be able to meet obligations associated with financial liabilities. OPTI’s financial liabilities are comprised of accounts payable and accrued liabilities, derivative instruments, long-term debt and obligations under capital leases. OPTI frequently assesses its liquidity position and obligations under its financial liabilities by preparing regular financial forecasts. Liquidity risk is increased by OPTI’s high levels of long-term debt and historical net field operating losses. OPTI mitigates 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 adequate sources of financing are available through bank credit facilities and co mplying with debt covenants. OPTI’s financial liabilities arose primarily from the development of the Project. As at December 31, 2010 OPTI has met all of the obligations associated with its financial liabilities.
See Note 6 in the notes to the December 31, 2010 financial statements for information regarding the amount of available credit facilities and contractual maturities of OPTI’s long-term debt. OPTI was in compliance with its debt covenants at December 31, 2010. See Note 2a in the notes to the December 31, 2010 financial statements regarding going concern uncertainty.
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. OPTI evaluates market risk on an ongoing basis. OPTI assesses the impact of variability in identified market risks on the medium-term cash requirements and impact with respect to covenants on the credit facilities. At December 31, 2010, OPTI had mitigation programs to reduce market risk related to foreign exchange price changes. During 2010, OPTI had mitigation programs to reduce market risk related to commodity price changes but these programs were ended December 31, 2010. The primary market risks related to the commodity contracts related to future estimated prices for WTI.
*Interest rate risk
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 and subsequent extension. The extent of the exposure to interest rate risk depends on the amount outstanding under the facility. At December 31, 2010, the facility remained undrawn. In January 2011, $90 million was drawn under this facility.
The Senior Notes are comprised of US$2,575 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 and the measurement amount of interest expense. A CDN$0.01 change in the exchange rate will impact the carrying value of the Senior Notes by approximately $26 million. A CDN$0.01 change in the exchange rate will change OPTI’s annual interest costs by approximately $2 million.
*Foreign exchange derivative instruments
OPTI is exposed to foreign exchange rate risk on our long-term U.S. dollar-denominated debt. At December 31, 2010, we have US$420 million of foreign exchange derivative instruments to manage a portion of the exposure to the foreign exchange fluctuations on the Company’s long-term debt at a rate of approximately CDN$1.22 to US$1.00. Changes in the exchange rate between Canadian and U.S. dollars change the value of these instruments. These derivative instruments currently expire in September 2011. The instruments offset changes in the measurement amount of the US debt. The foreign exchange derivative instruments at December 31, 2010 are a liability of $89 million.
Prior to or at the expiry of the foreign exchange derivative instruments in September 2011, OPTI may choose to settle or extend to a later settlement date. If we are unable or choose not to extend the term of these instruments, we expect to pay or receive, based on the mark-to-market of this contract, at the time of the settlement. As of December 31, 2010, the value of the foreign exchange derivative instruments would change by approximately $4 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 2011.
*Commodity derivative instruments
During 2010, we had established commodity derivative contracts to mitigate OPTI’s exposure of future operations to decreases in the price of its synthetic crude oil. OPTI had commodity price swaps to mitigate a portion of the exposure. During the year OPTI had WTI price swaps that provided for 3,000 bbl/d at strike prices between US$64/bbl and US$67/bbl of crude oil that expired on December 31, 2010. The counterparties to the commodity derivatives were major Canadian banks and lenders under OPTI’s revolving credit facility. No new commodity derivative contracts were entered into for 2011.
*Sensitivities
For the year ended December 31, 2010 estimated changes to reported net income as a result of changes in market rates are as noted. An increase of $1.00/bbl in WTI would have resulted in approximately $2 million decrease in our net loss (2009: $1 million decrease) with an offsetting increase in our net loss of approximately nil (2009: $1 million increase) as a result of the increase in the value of our commodity liabilities (assuming the WTI change occurred in a range where the WTI price per barrel is greater than the strike price of the commodity swap), a $0.10/GJ increase in the price of natural gas would have resulted in approximately a $1 million increase in net loss (2009: $1 million increase), a 1.0 percent increase in interest rates would have resulted in approximately a $1 million increase in net loss (2009: $1 million i ncrease) and a $0.01 increase in the Canadian to U.S. exchange rate would decrease net loss by approximately $16 million (2009: $10 million decrease) considering the impact on the Senior Notes and related interest and the foreign exchange derivative instruments.
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 expansion development 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 2011; poor operating results, requirement for major repairs or improvements to our facilities or low commodity prices. Potential volatility in the financial sector and in the overall economy means 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 sufficient for 2011, 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$89/bbl and a low of approximately US$40/bbl.
The Long Lake Upgrader produces a fully upgraded product called PSCTM. The price we receive for PSC™ is dependent on the demand for it and is primarily 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 is be affected by regional factors such as supply of other synthetic and conventional crude oils. Although we expect PSCtm to continue 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.
During the Long Lake ramp 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 is mixed with diluent and sold as a bitumen blend. The blend is priced significantly lower than conventional light oil or PSCtm. We may also purchase third party bitumen and upgrade this bitumen into PSCtm using our Upgrader. While we expect such 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 would 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$1.27:US$1.00 in February 2009 to CDN$0.99:US$1.00 in Decemb er 2010.
* 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 increa sing 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 are dependent 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 expansions. 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 expansions, we will forego our working interest in such expansions and the associated lands. We may recover only those costs spent to date which may be less than the fair market value of the foregone working interest.
See the “COJO Agreements and the Technology Agreement” section in our AIF for a description of default provisions of the joint venture agreement.
* 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 o f 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 bey ond existing forecasted levels at prevailing market rates. This would cause our operating costs to increase and reduce our earnings.
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 expansion developments and we expect to require additional debt or equity financing to obtain the funds necessary to complete future expansions. The cost or availability of additional financing may not make future expansions 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. Furthermore, we may also be responsible for costs associated with the abandonment of the Project and reclamation of the Project lands.
The Project and completed future expansions 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.
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 Expansion Developments
We have announced multi-staged expansion developments, including plans to increase total bitumen production by 360,000 bbl/d (126,000 bbl/d net to OPTI). The development of these expansions 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 expansions are higher than anticipated, these future expansions may be deferred or cancelled. The execution of these future expansions 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 expansions, 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 expansions.
* 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 2011 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.
Strategic Alternatives Review 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. As stated under “Project Status,” SAGD production continues to be below expectations. Our strategic alternatives review has been underway since November 2009. Lower than expected bitumen production over the last seven months has negatively impacted our liquidity and has made it more difficult to achieve a transaction under our review. As a result of this performance, our financial commitments and our limited financial resources, OPTI has expanded its strategic alternatives to include seeking advice on capital structure adjustments to address its overall leverage position. There can be no assurance that any transaction will occur or, if a transaction is undertaken, as to its terms or timing. The Company remains highly leveraged and a capital structure adjustment of the balance sheet may be required in order for the company to meet its obligations and to be able to participate in future development. If a capital structure adjustment is pursued, there is a risk that it could be executed on terms that could be highly detrimental to existing equity holders.
