Exhibit 99.2
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the period ended
June 30, 2010
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis (MD&A), dated July 14, 2010, should be read in conjunction with the audited financial statements and accompanying MD&A for the year ended December 31, 2009 and the unaudited financial statements for the three and six month periods ended June 30, 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 and operation of the Long Lake Project as well as future expansions thereof, and OPTI's relationship with Nexen Inc. (Nexen); the development and timing of well pads and timing of wells coming on production; the expected decline in average steam-to-oil-ratio (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 advantages to staged steam assisted gravity drainage (SAGD) developments at Kinosis; the expected increase in Premium Sweet Crude (PSC™) yields; the expected improvement to net field operating margin later in 2010; the expected increase in the PSC™ premium OPTI receives relative to other synthetic crude oils; the ability of the Company to extend its foreign exchange hedging instruments, or if unable to extend, the cost associated with settling such instruments; the expected business impact of International Financial Reporting Standards (IFRS) on OPTI’s financial statements; OPTI's financial outlook, including the estimates of the per barrel netback, annual netback and free cash flow; OPTI's anticipated financial condition and liquidity over the next 12 months and in the long term; and our estimated future tax asset. Forward-looking information typically contains statements with words such as “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 assumptions, inherent risks and uncertainties. A change in any one of these factors could cause actual events or results to differ materially from those projected in the forward-looking information. Although OPTI believes that the expectations reflected in such forward-looking statements are reasonable, OPTI can give no assurance that such expectations will prove to be correct. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by OPTI and described in the forward-looking statements or information. The forward-looking statements are based on a number of assumptions that may prove to be incorrect. In addition to other assumptions identified herein, OPTI has made assumptions regarding, among other things: market costs and other variables affecting operating costs of the Project; the ability of the Long Lake Project joint venture partners to obtain equipment, services and supplies, including labour, in a timely and cost-effective manner; the availability and costs of financing; oil prices and market price for PSC™ 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.
NON-GAAP MEASURES
The MD&A makes reference to terms commonly used in the petroleum and natural gas industry such as netback and free cash flow. In OPTI’s disclosure, netback denotes revenue less royalties and operating costs. Free cash flow as used herein denotes an annualized netback less annual maintenance capital expenses. Any non-GAAP measure related to operating results is noted under “Non-GAAP Financial Measures” which follow our “Results of Operations”.
Additional information relating to our Company, including our AIF, can be found at www.sedar.com and http://edgar.sec.gov.
FINANCIAL HIGHLIGHTS
In millions | | Three months ended June 30, 2010 | | | Six months ended June 30, 2010 | | | Year ended December 31, 2009 | |
| Net loss | | $ | (152 | ) | | $ | (202 | ) | | $ | (306 | ) |
| Net field operating loss | | | (11 | ) | | | (40 | ) | | | (118 | ) |
| Working capital | | | 12 | | | | 12 | | | | 168 | |
Total oil sands expenditures (1) | | | 18 | | | | 48 | | | | 148 | |
| Shareholders’ equity | | $ | 1,109 | | | $ | 1,109 | | | $ | 1,311 | |
Common shares outstanding (basic) (2) | | | 282 | | | | 282 | | | | 282 | |
Notes:
| (1) | Capital expenditures related to Phase 1 and future expansion developments. Capitalized interest and non-cash additions or charges are excluded. |
| (2) | Common shares outstanding at June 30, 2010 after giving effect to the exercise of stock options would be approximately 285 million common shares. |
PROJECT STATUS
The Long Lake Project continues to ramp up over the second quarter of 2010, with consistent and improving operational performance.
Bitumen production continues to grow as a result of consistent steam injection. During the second quarter, bitumen production averaged approximately 24,900 barrels per day (bbl/d) (8,700 bbl/d net to OPTI), up from the previous quarter average of approximately 18,700 bbl/d (6,500 bbl/d net to OPTI). June bitumen production averaged approximately 26,900 bbl/d (9,400 bbl/d net to OPTI) and recent production is approximately 28,500 bbl/d (10,000 bbl/d net to OPTI). Bitumen production was temporarily affected by annually scheduled cogeneration maintenance which occurred during the second quarter.
Our SAGD surface facilities continue to perform reliably and as per design. Steam injection rates rose during the second quarter to average approximately 137,000 bbl/d as compared to 114,000 bbl/d in the previous quarter. These rates continue to climb, with recent steam injection highs of approximately 150,000 bbl/d. We currently have 81 well pairs receiving steam, comprised of 68 on production and an additional 13 in circulation mode. We expect that these circulating wells will be converted to production mode over the next few months.
Our recent all-in SOR average is between 5 and 6, including steam to wells that are currently in steam circulation mode and wells early in the ramp-up cycle. The SOR of our mature producing wells is approximately 4 and improving. Mature producing wells are those that have received steam at a significant aggregate level and for a period of at least one year. As new production wells progress further along in the production cycle, we would expect bitumen production to increase and the corresponding SOR to decline.
To ensure that we maximize bitumen production from our resource base and surface facilities, we continue to develop SAGD well pads 12 and 13 at Long Lake. It is expected that this development will provide 18 new well pairs available for bitumen production in 2012. In addition, the joint venture partners have commenced an evaluation of the potential addition of two supplementary once-through steam generators. Taking advantage of existing surplus water treatment capacity, these boilers may increase our steam capacity 10 to 15 percent. The estimated capital cost for these boilers is approximately $150 million gross ($53 million net to OPTI). If we proceed with this activity, it represents a cost effective investment to ensure we have sufficient steam to maximize value from our existing surface facilities and our reservoir.
Upgrader units continue to perform consistently, processing virtually all of our bitumen production as well as approximately 8,600 bbl/d of externally-sourced bitumen. On-stream time averaged 97 percent in the second quarter as compared to 78 percent in the previous quarter. We continue to use produced syngas as a low cost fuel source in our SAGD operations. PSCTM yields averaged approximately 72 percent over the second quarter as compared to 63 percent in the previous quarter. Yields are expected to increase to the design rate of 80 percent once operations are optimized, with the Upgrader maintaining approximately 50 percent of its bitumen design capacity on a consistent basis.
FUTURE EXPANSIONS
OPTI and Nexen are planning the next development, which is referred to as Kinosis, located in the southern portion of the Long Lake Leases. At Kinosis, we plan to stage our SAGD development prior to building an upgrading facility rather than developing the integrated project simultaneously. We have regulatory approvals for Kinosis SAGD development for up to 140,000 bbl/d of bitumen production and we are evaluating building the SAGD projects in approximately 40,000 bbl/d bitumen stages and intend to sanction the first stage in 2012. Additional stages of Kinosis SAGD will proceed thereafter. A second Upgrader would be built once sufficient bitumen rates from the Kinosis area have been reached and economic conditions support the development of upgrading.
Staged SAGD development, as discussed above, offers several advantages: lower capital intensity for development; a reduction in labour requirements; better construction cost and execution control; and the ability to use PSC volumes from our Long Lake Upgrader for self-supplied diluent to blend with bitumen volumes from expansion projects.
STRATEGIC ALTERNATIVES REVIEW
OPTI’s Board of Directors continues to move forward in its process to explore strategic alternatives for enhancing shareholder value. Strategic alternatives may include capital market opportunities, restructuring the current credit facility, asset divestitures, and/or a corporate sale, merger or other business combination. The ultimate objective of carrying out this review is to determine which alternative(s) might result in superior value for shareholders.
OPTI does not intend to disclose developments with respect to the strategic review process unless and until its Board of Directors has approved a definitive transaction or strategic option. There can be no assurance that any transaction will occur, or if a transaction is undertaken, as to its terms or timing.
Any announcements regarding the strategic alternatives review will be disclosed in accordance with all applicable legal and regulatory requirements.
ANNUAL NETBACKS AND FREE CASH FLOWS BASED ON SOR ASSUMPTIONS
We provided our estimated netback for Phase 1 of the Project in our MD&A for the year ended December 31, 2009 as filed on SEDAR and EDGAR on February 9 and 10, 2010, respectively. While there are no changes to our per barrel estimated netback calculation, we have provided an estimated annual netback and an estimated annual free cash flow based on an SOR range. 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 annual netback. We have therefore evaluated the impact of an SOR range of 2.5 to 3.7 on the Project. This SOR range captures the range for virtually all SAGD projects in the Athabasca oil sands. Management approved this annual netback and resultant free cash flow on July 14, 2010. For each assumed SOR, we have evaluated potential optimization and mitigation approaches. At full production, our annual netback is calculated by using the per barrel netback of $54.75 per barrel (/bbl) at a West Texas Intermediate crude oil (WTI) price of US$75.
This financial outlook is intended to provide investors with an estimate of how our annual netback and resultant free cash flow at full production capacity could be impacted by the specified SOR range. We believe the annual netback and resultant free cash flow are 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. We expect annual netback and resultant annual free cash flow generated by our Project to be lower than shown in this outlook in the years following start-up due to the lower production volumes during ramp-up and an initially higher SOR. The annual netback and free cash flow presented are non-GAAP financial measures. The closest GAAP financial measure to the annual netback and free cash flow is cash flow from operations. However, cash flow from operations may include other corporate items that affect cash flow and are independent of the operations of the Project.
The actual annual netback and resultant free cash flow achieved by the Project could differ materially from these estimates. The material risk factors that we have identified toward achieving these annual netbacks and free cash flows are outlined under "Forward Looking Information" in our 2009 AIF. In particular, the SAGD and Long Lake Upgrader facilities may not operate as planned; the operating costs of the Project may vary considerably during the operating period; our results of operations will depend upon the prevailing prices of oil and natural gas which can fluctuate substantially; we will be subject to foreign currency exchange fluctuation exposure; and our annual netback will be directly affected by the applicable royalty regime relating to our business. The key assumptions relating to the annual netback and free cash flow estimate are set out in the notes beneath the tables.
Estimated Future Project Pre-Payout Netbacks (1)
WTI - US$75 (2) | | Per Barrel | | | Annual | |
| | | $/bbl | | | $ in millions/year | |
| Revenue | | $ | 82.27 | | | $ | 590 | |
| Royalties and Corporate G&A | | | (4.10 | ) | | | (29 | ) |
Operating costs(3) | | | | | | | | |
Natural gas(4) | | | (3.15 | ) | | | (23 | ) |
Other variable(5) | | | (2.00 | ) | | | (14 | ) |
| Fixed | | | (15.46 | ) | | | (111 | ) |
| Property taxes and insurance | | | (2.81 | ) | | | (20 | ) |
| Total operating costs | | | (23.42 | ) | | | (168 | ) |
Netback(6) | | $ | 54.75 | | | $ | 393 | |
| | (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, and assume that the Upgrader will have an on-stream factor of 96 percent. These numbers are cash amounts for OPTI’s working interest share 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$6.25/mcf, foreign exchange rates of $1.00 = US$0.90, heavy/light crude oil price differentials of 27 percent of WTI and electricity sales prices of $83.12 per MWh. Revenue includes sale of PSC™, bitumen, butane and electricity. |
| | (3) | Costs are in 2009 dollars. |
| | (4) | Natural gas costs are based on an estimate for an SOR of 3.0. |
| (5) | 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 $20 per tonne of CO2. |
| | (6) | Figures shown above may not sum due to the effects of rounding. |
Per barrel and annual netbacks as shown are prior to abandonment and reclamation costs. We do not include these costs in our netback estimates due to the long term nature of our assets.
Estimated Future Project Pre-Payout Free Cash Flows at a Range of Potential SOR
| In millions ($CDN) | | SOR 2.5 (3) | | | SOR 3.0 (4) | | | SOR 3.7 (5) | |
| | | | | | | | | | | | | |
Annual Netback at WTI – US$75 (1) | | $ | 498 | | | $ | 393 | | | $ | 375 | |
| | | | | | | | | | | | | |
Annual Maintenance Capital (2) | | | (60 | ) | | | (60 | ) | | | (60 | ) |
| Free Cash Flow | | $ | 438 | | | $ | 333 | | | $ | 315 | |
| (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 (20,125 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), (5) and (6) 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 to be approximately $8.00 to $9.00 per barrel of PSC™, assuming full design rate production and long term on-stream expectations. For the SOR cases at 2.5 and 3.7, the annual maintenance capital is not adjusted for the long term maintenance capital expense and one-time capital expenditure for the facility modifications as neither are significant costs over the life of the project. Please refer to notes (3) and (5) below for further information. |
| (3) | For purposes of this calculation, we have assumed an SOR of 2.5 with potential facility modifications. Potential one-time facility modifications of approximately $150 million would be spent; timing of future well pads would be accelerated to support production rates of approximately 92,000 bbl/d (maximum production rate using current steam capacity at 2.5 SOR); and bitumen production in excess of Upgrader inlet capacity (72,000 bb/d of bitumen) would be sold as bitumen blend. Annual maintenance capital is not adjusted as the long term capital maintenance expense and the initial one-time capital expenditure cost impact of facility modifications are not significant over the life of the project. |
| (4) | For purposes of this calculation, we have assumed an SOR of 3.0 with no additional expenditures for facility modifications and all other assumptions are the same as noted under Estimated Future Project Pre-Payout Netbacks. |
| (5) | For purposes of this calculation, we have assumed an SOR of 3.7 with potential facility modifications. Current steam capacity would be increased by facility modifications of approximately $150 million in order to reach design capacity bitumen production rates. Higher operating costs of approximately $18 million per year would |
| | result from incremental natural gas costs. Annual maintenance capital is not adjusted as the long term capital maintenance expense and the initial one-time capital expenditure cost impact of facility modifications are not significant over the life of the project. |
After the one-time investment of $150 million (gross), the increase in free cash flow by $105 million at an SOR of 2.5, relative to the SOR 3.0 case, is primarily attributable to higher sales volumes from PSH. After the one-time investment of $150 million (gross), the reduction in free cash flow of $18 million at an SOR of 3.7, relative to the SOR 3.0 case, is primarily attributable to higher natural gas costs.
RESULTS OF OPERATIONS
| | | Three months ended June 30 | | | Six months ended June 30 | |
| $ millions, except per share amounts | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| Revenue, net of royalties | | $ | 61 | | | $ | 34 | | | $ | 111 | | | $ | 63 | |
| Expenses | | | | | | | | | | | | | | | | |
| Operating expense | | | 53 | | | | 39 | | | | 105 | | | | 67 | |
| Diluent and feedstock purchases | | | 15 | | | | 20 | | | | 38 | | | | 49 | |
| Transportation | | | 4 | | | | 3 | | | | 8 | | | | 6 | |
| Net field operating loss | | | (11 | ) | | | (28 | ) | | | (40 | ) | | | (59 | ) |
| Corporate expenses | | | | | | | | | | | | | | | | |
| Interest, net | | | 49 | | | | 42 | | | | 98 | | | | 61 | |
| General and administrative | | | 3 | | | | 7 | | | | 7 | | | | 13 | |
| Financing charges | | | 1 | | | | 1 | | | | 1 | | | | 1 | |
| Realized loss (gain) on hedging instruments | | | 48 | | | | (11 | ) | | | 52 | | | | (35 | ) |
| Loss before non-cash items | | | (112 | ) | | | (67 | ) | | | (198 | ) | | | (99 | ) |
| Non-cash items | | | | | | | | | | | | | | | | |
| Foreign exchange translation loss (gain) | | | 104 | | | | (171 | ) | | | 32 | | | | (96 | ) |
| Net unrealized loss (gain) on hedging instruments | | | (77 | ) | | | 137 | | | | (51 | ) | | | 115 | |
| Depletion, depreciation and accretion | | | 13 | | | | 7 | | | | 23 | | | | 11 | |
| Loss on disposal of assets | | | - | | | | 1 | | | | - | | | | 2 | |
| Future tax expense (recovery) | | | - | | | | (32 | ) | | | - | | | | (25 | ) |
| Net loss | | $ | (152 | ) | | $ | (9 | ) | | $ | (202 | ) | | $ | (106 | ) |
| Loss per share, basic and diluted | | $ | (0.54 | ) | | $ | (0.04 | ) | | $ | (0.72 | ) | | $ | (0.54 | ) |
Operational Overview
The results of operations for the three and six month periods ended June 30, 2010, as well as for the three months ended June 30, 2009, include SAGD and Upgrader results. The results of operations for the six months ended June 30, 2009 include SAGD results for the entire period and Upgrader results from April 1, 2009, which is the date we determined the Upgrader to be ready for its intended use. Revenue for the six months ended June 30, 2010 was a combination of PSCTM, PSH and power sales. Revenue for the same period in 2009 consisted of PSH and power sales for entire period and PSCTM only for the second quarter of 2009.
We define our net field operating margin as revenue related to petroleum products (net of royalties) and power sales minus operating expenses, diluent and feedstock purchases and transportation costs. See “Non-GAAP Financial Measures”. On-stream factor is a measure of the period of time that the Upgrader is producing PSC™ and it is calculated as the percentage of hours the Hydrocracker Unit in the Upgrader is in operation. When the Upgrader is not in operation, results are adversely affected by the requirement to purchase diluent, which is blended with bitumen to produce and sell PSH. PSH revenue per barrel is lower than PSC™ revenue per barrel. The majority of SAGD and Upgrader operating costs are fixed, so we expect that rising SAGD volumes and continued high level of Upgrader on-stream factor will lead to improvements 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 in the three months ended June 31, 2010 decreased to $11 million from a loss of $29 million in the first quarter of 2010 as a result of increasing production and other operating improvements. We anticipate that increased production and other operating improvements will lead to a positive net field operating margin later this year. The Upgrader on-stream factor for the three months ended June 30, 2010 increased to 97 percent as compared to 78 percent in the first quarter of 2010. Upgrader on-stream factor has reached its long term design level. PSC™ yield for the three months ended June 30, 2010 increased to 72 percent as compared to 63 percent in the first quarter of 2010. Our share of PSC™ sales increased to 7,100 bbl/d for the three months ended June 30, 2010 compared to 3,500 bbl/d in the in the first quarter of 2010 while our share of PSH sales decreased to 1,700 bbl/d for the three months ended June 30, 2010 from 3,500 bbl/d in the first quarter of 2010. As a result of the increased on-stream factor and the use of our own PSC™ to blend with bitumen for PSH, diluent purchases are insignificant for the three months ended June 30, 2010.
Revenue
For the three months ended June 30, 2010 we earned revenue net of royalties of $61 million compared to $34 million for the same period in 2009. For the three months ended June 30, 2010, our share of PSC™ sales averaged 7,100 bbl/d at an average price of approximately $77/bbl compared to 1,700 bbl/d at an average price of approximately $66/bbl for the same period in 2009. For three months ended June 30, 2010, our share of PSH averaged 1,700 bbl/d at an average price of approximately $58/bbl compared to 4,400 bbl/d at an average price of approximately $59/bbl for the same period in 2009. Our share of bitumen production for three months ended June 30, 2010 averaged 8,700 bbl/d compared to 5,000 bbl/d for the same period in 2009. Our total revenue, net of royalties, diluent and feedstock increased to $46 million for the three months ended June 30, 2010 compared to $14 million for the same period in 2009. This is primarily due to increased bitumen production, and higher PSC™ sales in 2010 as a result of a higher Upgrader on-stream factor in 2010.
For the six months ended June 30, 2010, we earned revenue net of royalties of $111 million compared to $63 million for the same period in 2009. Our total revenue, net of royalties, diluent and feedstock was $73 million for the six months ended June 30, 2010 compared to $14 million for the same period in 2009. This is primarily due to increased bitumen production and higher PSC™ sales in 2010 as a result of a higher Upgrader on-stream time in 2010.
For the three and six month periods ended June 30, 2010, we received pricing for PSCTM in-line with, or better than, other synthetic crude oils. Due to the premium characteristics of our PSCTM, we expect the premium we receive relative to other synthetic crude oils to increase as the production and availability of marketed PSCTM increases.
For the three months ended June 30, 2010 we had power sales of $3 million representing approximately 29,400 megawatt hours (MWh) of electricity sold at an average price of approximately $88/MWh compared to $1 million for the same period in 2009, which represented 17,200 MWh at an average price of approximately $33/MWh. For the six months ended June 30, 2010 we had power sales of $5 million compared to $2 million for the same period in 2009.
Expenses
* Operating expenses
Our operating expenses are primarily comprised of maintenance, labour, operating materials and services, and natural gas.
For the three months ended June 30, 2010 operating expenses were $53 million compared to $39 million for the same period in 2009. Operating expensed increased due to cogeneration and sulphur plant units annual maintenance performed during the quarter as well as higher operating levels.
For the six months ended June 30, 2010 operating expenses were $105 million compared to $67 million for the same period in 2009. Operating expenses in 2010 are higher as they included SAGD as well as Upgrader operating results, whereas operating expenses in 2009 included SAGD results for the entire period and Upgrader results only from April 1, 2009.
* Diluent and feedstock purchases
For the three months ended June 30, 2010 diluent and feedstock purchases were $15 million compared to $20 million for the same period in 2009. For the three months ended June 30, 2010, diluent purchases were insignificant compared to the three months ended June 30, 2009. For the six months ended June 30, 2010, diluent purchases were 140 bbl/d at an average price of $58/bbl compared to 3,000 bbl/d at an average price of $66/bbl for the same period in 2009. Diluent purchases decreased in 2010 compared to the same periods in 2009 due to a higher Upgrader on-stream factor in 2010 and the use of a portion of our own PSCTM as diluent for PSH sales.
For the three months ended June 30, 2010, we purchased $15 million of third party bitumen representing approximately 3,000 bbl/d compared to $10 million representing approximately 1,600 bbl/d for the same period in 2009. For the six months ended June 30, 2010, we purchased $38 million of third party bitumen compared to $18 million 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 three months ended June 30, 2010, transportation expenses were $4 million compared to $3 million for the same period in 2009. For the six months ended June 30, 2010, transportation expenses were $8 million compared to $6 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 three months ended June 30, 2010, net interest expense was $49 million compared to $42 million for the same period in 2009. For the six months ended June 30, 2010, net interest expense was $98 million compared to $61 million for the same period in 2009. The increase in net interest expense in 2010 was primarily due to interest related to the SAGD facilities and the Upgrader as well as additional interest related to the US$425 First Lien Notes, whereas interest expense in 2009 included interest related to the SAGD facilities for the entire period and interest related to the Upgrader only from April 1, 2009.
For the three months ended June 30, 2010, the average Canadian dollar exchange rate weakened resulting in an increase in Canadian interest costs on our U.S. dollar-denominated debt. For the six months ended June 30, 2010, the effect of foreign exchange rate fluctuation was minimal, as the average Canadian dollar exchange rate has not changed significantly since the beginning of the year.
* General and Administrative (G&A) Expense
For the three months ended June 30, 2010, G&A expense was $3 million compared to $7 million for the same period in 2009. For the six months ended June 30, 2010, G&A expense was $7 million compared to $13 million for the same period in 2009. Included in G&A expense for the six months ended June 30, 2010 was $2 million related to the strategic alternative process. G&A expense was lower in 2010 due to severance payments made during the same period in 2009 related to the re-organization of OPTI after the sale of the 15 percent working interest Nexen. Included in G&A expense is a stock-based compensation expense for the three months ended June 30, 2010 of $0.4 million (three months ended June 30, 2009: $(0.3) million) and for the six months ended June 30, 2010 of $0.9 million (six months ended June 30, 2009: $0.2 million).
* Net realized gain or loss on hedging instruments
For the three months ended June 30, 2010, net realized loss on hedging instruments was $48 million compared to a gain of $11 million for the same period in 2009. For the six months ended June 30, 2010, net realized loss on hedging instruments was $52 million compared to a gain of $35 million for the same period in 2009. The losses in 2010 relate to the $44 million settlement of foreign exchange hedging instruments and our realized commodity hedging losses. The commodity losses were a result of our 2010 hedging instruments of 3,000 bbl/d at strike prices between US$64/bbl and US$67/bbl when the average WTI price for the three and six month periods were US$78/bbl. The gains in 2009 were related to our US$80/bbl crude oil puts and our US$77/bbl crude oil hedging instruments.
Non-cash items
* Foreign exchange gain or loss
For the three months ended June 30, 2010, foreign exchange translation was a $104 million loss compared to a $171 million gain for the same period in 2009. The gain or loss is comprised of the re-measurement of our U.S. dollar-denominated long-term debt and cash. During the second quarter of 2010, the Canadian dollar weakened from CDN$1.02:US$1.00 to CDN$1.06:US$1.00 resulting in a foreign exchange translation loss.
For the six months ended June 30, 2010, foreign exchange translation was a $32 million loss compared to a $96 million gain for the same period in 2009. During the 2010 period, the Canadian dollar weakened from CDN$1.05:US$1.00 to CDN$1.06:US$1.00 resulting in a foreign exchange translation loss. These gains and losses are unrealized.
* Net unrealized gain or loss on hedging instruments
For the three months ended June 30, 2010, net unrealized gain on hedging instruments was $77 million compared to a $137 million loss for the same period in 2009. The net unrealized gain is comprised of a $67 million unrealized gain on our foreign exchange hedging instruments due to the weakening of the Canadian dollar from CDN$1.02:US$1.00 to CDN$1.06:US$1.00 and a $10 million unrealized gain on our commodity hedges due to the maturing of the instruments during the period and a decrease in the future price of WTI from approximately US$81/bbl at the beginning of the period to approximately US$75/bbl at June 30, 2010. The loss for the corresponding period in 2009 relates to a strengthening of the Canadian dollar and an increase in the future price of WTI during the period.
For the six months ended June 30, 2010, net unrealized gain on hedging instruments was $51 million compared to a $115 million loss for the same period in 2009. The net unrealized gain is comprised of a $39 million unrealized gain on our foreign exchange hedging instruments due to the weakening of the Canadian dollar from CDN$1.05:US$1.00 to CDN$1.06:US$1.00 and a $12 million unrealized gain on our commodity hedges due to the maturing of the instruments during the period. The loss for the corresponding period in 2009 relates to a strengthening of the Canadian dollar and an increase in the future price of WTI during the period.
* Depletion, depreciation and amortization (DD&A)
For the three months ended June 30, 2010, DD&A was $13 million compared to $6 million for the same period in 2009. For the six months ended June 30, 2010, DD&A was $23 million compared to $11 million for the same period in 2009. DD&A for 2010 relates to both SAGD facilities and Upgrader facilities whereas for 2009 DD&A was for the SAGD facilities and the Upgrader facilities from April 1, 2009 only. Additionally, production volumes have increased in 2010 which resulted in higher DD&A costs compared to 2009.
* Loss on disposal of assets
For the three and six month periods ending June 30, 2010, loss on disposal of assets was nil compared to $1 million and $2 million respectively for the corresponding periods 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 recovery
For the three and six months ended June 30, 2010, future tax recovery was nil compared to $32 million and $25 million respectively for the corresponding periods in 2009. For the three and six month periods ended June 30, 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 has approximately $3.8 billion of available Canadian tax pools at December 31, 2009.
CAPITAL EXPENDITURES
The table below identifies expenditures incurred by us in relation to the Project, other oil sands activities and other capital expenditures.
| $ millions | | Three months ended June 30, 2010 | | | Six months ended June 30, 2010 | | | Year ended 2009 | |
| The Long Lake Project – Phase 1 | | | | | | | | | |
| Sustaining capital | | $ | 12 | | | $ | 36 | | | $ | 83 | |
| Capitalized operations | | | - | | | | - | | | | 19 | |
| Total Long Lake Project | | | 12 | | | | 36 | | | | 102 | |
| Expenditures on future phases | | | | | | | | | | | | |
| Engineering and equipment | | | 4 | | | | 9 | | | | 21 | |
| Resource acquisition and delineation | | | 2 | | | | 3 | | | | 25 | |
| Total oil sands expenditures | | | 18 | | | | 48 | | | | 148 | |
| Capitalized interest | | | - | | | | - | | | | 29 | |
| Other capital expenditures | | | - | | | | - | | | | (19 | ) |
| Total capital expenditures | | $ | 18 | | | $ | 48 | | | $ | 158 | |
For the three months ended June 30, 2010, we incurred capital expenditures of $18 million.
As with all SAGD projects, new well pads must be drilled and tied-into the SAGD central facility to maintain production at design rates over the life of the Project. For three months ended June 30, 2010, we had sustaining capital expenditures of $12 million. These capital expenditures include: our ongoing investment in resource delineation for future Phase 1 well pads (including coreholes, four-dimensional seismic and the tie-in of two water source wells); the installation of 8 electric submersible pumps in producing wells for better well control and enhanced bitumen extraction; and oil removal filters for oil and particulate removal from the produced water stream for improved water treatment. We also completed civil and engineering work on two additional well pads.
For the three months ended June 30, 2010, we incurred expenditures of $4 million for engineering and $2 million for resource delineation for future phases.
SUMMARY FINANCIAL INFORMATION
| | | 2010 | | | 2009 | | | 2008 | |
In millions (unaudited) (except per share amounts) | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | |
| Revenue | | $ | 61 | | | $ | 50 | | | $ | 43 | | | $ | 38 | | | $ | 34 | | | $ | 29 | | | $ | 69 | | | $ | 126 | |
| Net earnings (loss) | | | (152 | ) | | | (50 | ) | | | (212 | ) | | | 12 | | | | (9 | ) | | | (97 | ) | | | (410 | ) | | | (32 | ) |
Earnings (loss) per share, basic and diluted | | $ | (0.54 | ) | | $ | (0.18 | ) | | $ | (0.75 | ) | | $ | 0.04 | | | $ | (0.04 | ) | | $ | (0.50 | ) | | $ | (2.09 | ) | | $ | (0.16 | ) |
Quarterly results for 2010 and 2009 represent our 35 percent working interest in the Project, whereas quarterly results for 2008 represent our then 50 percent working interest.
In the third and fourth quarters of 2008, we generated revenue and incurred operating expenditures associated with early stages of SAGD operation. During the third quarter of 2008, we had a $64 million unrealized gain on hedging instruments offset by a $73 million dollar foreign exchange loss. During the fourth quarter of 2008, we had a pre-tax asset impairment for accounting purposes related to our working interest sale of $369 million and a future tax expense recovery of $116 million primarily related to this impairment, a $254 million foreign exchange translation loss, and $105 million realized gain as well as a $28 million unrealized gain on hedging instruments.
Operations during 2009 and 2010 represent initial stages of our operations at relatively low operating volumes. Our operating results are expected to improve as SAGD production increases and the Upgrader produces higher volumes of PSCTM.
Net loss of $97 million in the first quarter of 2009 was associated with operating expenses in the early stages of SAGD operations that operated at relatively low volumes which lead to a net field operating loss of $31 million. In addition, we had a $75 million foreign exchange loss offset by a net realized and unrealized gain on hedging instruments of $46 million. Net 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, which was offset by unrealized losses on hedging instruments related to our foreign exchange and commodity hedges and our net field operating loss. The net loss of $212 million in the fourth quarter for 2009 includes a net field operating loss of $21 million, interest expense of $43 million, an unrealized loss on our hedges of $36 million offset by a foreign exchange gain of $36 million, and a future tax expense of $119 million that resulted from the recognition of a future tax asset valuation allowance.
During the third quarter of 2009 OPTI issued 86 million common shares, 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.
SHARE CAPITAL
At July 9, 2010, OPTI had 281,749,526 common shares and 2,804,500 common share options outstanding. The common share options have a weighted average exercise price of $4.43 per share.
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 2010, we had approximately $267 million of financial resources, consisting of $117 million of cash on hand and $150 million under our revolving credit facility. Our cash and cash equivalents are invested exclusively in money market instruments issued by major Canadian banks. Our long-term debt consists of US$1,750 million of Secured Notes and US$425 million First Lien Notes (collectively, our “Senior Notes”) and a $190 million revolving credit facility of which $40 million has been drawn.
Expected remaining cash outflows for 2010 include approximately $70 million of the total capital budget of $119 million and US$90 million interest payments are due with respect to our Senior Notes. Our financial resources will also be affected by net field operating margin. Our net field operating margin was a loss of $29 million in the first quarter of 2010 and a loss of $11 million in the second quarter. In order for the net field operating margin to become positive for the remainder of 2010, some or all of the following will be required: a continued 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. Based primarily on our expectation of a significant increase in bitumen production and extension of our foreign exchange hedging instruments, we expect our existing financial resources are sufficient to meet our obligations for the remainder of 2010. Our financial resources for 2011 will be evaluated with consideration of current and projected net field operating margin, projected interest costs and our expectation for the cost of joint venture capital programs in 2011. We may determine that we require additional financial resources based on this evaluation.
During the quarter ended June 30, 2010, OPTI extended $75 million of its $330 million foreign exchange hedging instruments that matured in April 2010. The remaining $255 million of the foreign exchange hedging instruments were settled by a cash payment of $44 million. Including the foreign exchange hedging instruments that had previously been extended in the fourth quarter of 2009, we have $620 million of foreign exchange hedging instruments outstanding at an average rate of CDN$1.19:US$1.00 with a maturity date of December 31, 2010. OPTI intends to extend these instruments past the current maturity date. If the instruments cannot be extended, the resulting cash settlement will be a function of the foreign exchange rate in effect at the maturity date. The cash settlement of our foreign exchange hedging instruments at the June 30, 2010 foreign exchange rate of CDN$1.06:US$1.00 would be
$76 million. The actual future cash settlement could be materially different, as a $0.01 change in the foreign exchange rate will affect this obligation by approximately $6 million.
For the three months ended June 30, 2010, cash used by operating activities was $168 million, cash provided by financing activities was $38 million and cash used by investing activities was $28 million. These cash flows, combined with a translation gain on our U.S. dollar denominated cash of $3 million, resulted in a decrease in cash and cash equivalents during the period of $155 million.
During the second quarter of 2010 we used our cash on hand and our revolving credit facility to fund our capital expenditures and operational activities. In the remainder of 2010, our primary sources of funding include our existing cash, the remaining undrawn balance under the revolving credit facility and expected future revenue.
We have initiated a process to explore strategic alternatives for enhancing shareholder value. This process is designed to assess a range of strategic alternatives that may include capital markets opportunities, restructuring the current credit facility, asset divestitures, and/or a corporate sale, merger or other business combination. A primary objective of this process is to reduce our overall leverage and position the Company for future phase development. If a transaction is completed in 2010, it would be expected to have a material impact on our liquidity and capital resources. There can be no assurance that any transaction will occur or, if a transaction is undertaken, as to its terms or timing.
Our rate of production increase will have a significant impact on our financial position through 2010 and beyond. Our net field operating margin in the first and second quarter of 2010 and in 2009 is a loss. It is important for our business to increase production to a point where we generate positive net field operating margins. Failure to improve bitumen production rates, and ultimately PSCTM sales, will result in continued net field operating losses and difficulty in obtaining new sources of debt and equity.
If production levels and rates-of-increase in 2010 are less than expected, or we are required to settle our remaining foreign exchange hedging instruments at unfavourable foreign exchange rates, we may determine that we require additional capital to maintain adequate liquidity.
For 2010 we have mitigated our exposure to commodity pricing as we have hedged 3,000 bbl/d with fixed price swaps at strike prices between US$64 and US$67 per barrel (risks associated with our hedging instruments are discussed in more detail under “Financial Instruments”). The majority of our operating and interest costs are fixed. Aside from changes in the price of natural gas, our operating costs will neither decrease nor increase significantly as a result of fluctuations in WTI prices other than with respect to royalties to the Provincial Government of Alberta, which increase on a sliding scale at WTI prices higher than CDN$55/bbl. Collectively, this means that the variability of our financial resources will primarily be influenced by production rates and resulting PSCTM sales, operating expenses and by foreign exchange rates.
Our revolving credit facility requires adherence to a debt to capitalization covenant that does not allow our debt to capitalization ratio to exceed 70 percent, as calculated on a quarterly basis. The ratio is calculated based on the book value of debt and equity. The book value of debt is adjusted for the effect of any foreign exchange derivatives issued in connection with the debt that may be outstanding. Our book value of equity is adjusted to exclude the $369 million increase to deficit as a result of the asset impairment associated with the working interest sale to Nexen and to exclude the $85 million increase to the January 1, 2009 opening deficit as a result of new accounting pronouncements effective on that date. Accordingly, at June 30, 2010, for the purposes of this ratio calculation, our debt would be increased by the amount of our foreign exchange hedge liability in the amount of $76 million and our deficit would be reduced by $455 million. With respect to U.S. dollar denominated debt, for purposes of the total debt to capitalization ratio, the debt is translated to Canadian dollars based on the average exchange rate for the quarter. The total debt to capitalization is therefore influenced by the variability in the measurement of the foreign exchange 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 the second quarter of 2010 is 60 percent.
In respect of each new borrowing under the $190 million revolving credit facility, we must satisfy certain conditions precedent prior to making a new borrowing. These include confirmations that the representations and warranties in our loan documents are correct on the date of the new borrowing, that no event of default has occurred and that there has not been a change or development that would constitute a material adverse effect. During the second quarter, OPTI borrowed $40 million under the revolving credit facility.
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 discounted at 10 percent. Based on our 2009 reserve report, we have sufficient capacity under this test to incur additional debt beyond our existing $190 million revolving credit facility and existing Senior Notes. Other considerations, such as restrictions under the First Lien Notes and $190 million revolving credit facility, are expected to be more constraining than this limitation.
We have annual interest payments of US$38 million each year until maturity of the US$425 million First Lien Notes in 2012 and annual interest payments of US$142 million each year until maturity of the US$1,750 million Secured Notes in 2014. On a long term basis, we estimate our share of capital expenditures required to sustain production of Phase 1 at or near planned capacity for the Project will be approximately $60 million per year prior to the effects of inflation. We expect to fund these payments from future operating cash flow and from existing financial resources. The development of future phases will require significant financial resources. We expect to require additional financial resources to develop the future expansion phases.
While capital market conditions for new equity and debt improved considerably during late 2009 and in 2010, they remain relatively volatile. There can be no assurance that market conditions will allow OPTI to access additional capital if we desire to do so. 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 earlier than we have estimated. Should the Company require any additional funding, it may be difficult and expensive to obtain.
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 June 30, 2010.
| | Moody's | S&P |
| OPTI Corporate Rating | Caa2 | B- |
| Revolving Credit Facility | B1 | B+ |
| First Lien Notes – US$425 million | B2 | B+ |
| Secured Notes – US$1,000 million | Caa3 | B |
| Secured Notes – US$750 million | Caa3 | B |
For the second quarter of 2010 there was no change in the credit ratings from Moody’s or S&P and a negative outlook continues by both rating agencies.
A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the rating organization.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
During the three months ended June 30, 2010 the measurement amount of our long-term debt increased by $104 million due to a higher Canadian dollar equivalent amount for our Senior Notes (principal and interest) associated with a weaker Canadian dollar.
The following table shows our contractual obligations and commitments related to financial liabilities at June 30, 2010.
| In $ millions | | Total | | | 2010 | | | | 2011–2012 | | | | 2013–2014 | | | Thereafter | |
Accounts payable and accrued liabilities(1) | | $ | 59 | | | $ | 59 | | | $ | - | | | $ | - | | | $ | - | |
| Hedging instruments (foreign exchange) | | | 76 | | | | 76 | | | | - | | | | - | | | | - | |
| Hedging instruments (commodity) | | | 7 | | | | 7 | | | | - | | | | - | | | | - | |
Long-term debt (Senior Notes - principal)(2) | | | 2,315 | | | | - | | | | 452 | | | | 1,863 | | | | - | |
Long-term debt (Senior Notes - interest)(3) | | | 780 | | | | 96 | | | | 383 | | | | 301 | | | | - | |
Long-term debt (Revolving facility principal)(4) | | | 40 | | | | - | | | | 40 | | | | - | | | | - | |
Capital leases(5) | | | 66 | | | | 2 | | | | 6 | | | | 6 | | | | 52 | |
Operating leases and other commitments(5) | | | 70 | | | | 5 | | | | 21 | | | | 16 | | | | 28 | |
Contracts and purchase orders(6) | | | 4 | | | | 4 | | | | - | | | | - | | | | - | |
| Total commitments | | $ | 3,417 | | | $ | 249 | | | $ | 902 | | | $ | 2,186 | | | $ | 80 | |
Notes:
| | (1) | Excludes accrued interest expense related to the Senior Notes. These costs are included in (3). |
| | (2) | Consists of principal repayments on the Senior Notes, translated into Canadian dollars using an exchange rate of CDN$1.06 to US$1.00 as at June 30, 2010. |
| | (3) | Consists of scheduled interest payments on the Senior Notes, translated into Canadian dollars using an exchange rate of CDN$1.06 to US$1.00 as at June 30, 2010. |
| | (4) | As at June 30, 2010, we have borrowed $40 million on our $190 million revolving credit facility. We are contractually obligated for interest payments on borrowings and standby charges in respect to undrawn amounts under the revolving credit facility, which are not reflected in the above table as amounts cannot reasonably be estimated due to the revolving nature of the facility and variable interest rates. We do not consider such amounts material. |
| | (5) | Consists of our share of future payments under our product transportation agreements with respect to future tolls during the initial contract term. |
| | (6) | Consists of our share of commitments associated with contracts and purchase orders in connection with the Long Lake Project and our other oil sands activities associated with future phases. |
OFF-BALANCE-SHEET ARRANGEMENTS
We have no off-balance-sheet arrangements.
TRANSACTIONS WITH RELATED PARTIES
We have no transactions with related parties.
CONTROLS AND PROCEDURES
Internal Control over Financial Reporting
The Chief Executive Officer and the Chief Financial Officer of OPTI are responsible for establishing and maintaining internal control over financial reporting (ICFR), as such term is defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings. The control framework our officers used to design OPTI's ICFR is the Internal Control -- Integrated Framework (COSO Framework) published by The Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Under the supervision of the Chief Executive Officer and the Chief Financial Officer, OPTI conducted an evaluation of the effectiveness of our ICFR as at December 31, 2009 based on the COSO Framework. Based on this evaluation, these officers concluded that as of December 31, 2009, OPTI's ICFR provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. There has not been any change in OPTI’s internal control over financial reporting during the three months ended June 30, 2010 that has materially affected, or is reasonably likely to materially affect OPTI’s internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
Our critical accounting estimates are consistent with those noted in our 2009 annual MD&A as filed on SEDAR and EDGAR on February 9 and 10, 2010, respectively.
NEW ACCOUNTING PRONOUNCEMENTS
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 is currently evaluating the impact of these new standards. The implementation of IFRS may result in a significant impact on our accounting policies, measurement and disclosure.
OPTI’s IFRS implementation project consists of three primary phases which will be completed by a combination of in-house resources and external consultants.
| | · | Initial diagnostic phase – Involves preparing a Preliminary Impact Assessment to identify key areas that may be impacted by the transition to IFRS. Each potential impact identified during this phase is ranked as having a high, moderate or low impact on our financial reporting and the overall difficulty of the conversion effort. |
| | · | Impact analysis, evaluation and solution development phase – Involves the selection of IFRS accounting policies by senior management and the review by the audit committee, the quantification of the impact of changes on our existing accounting policies on our opening IFRS balance sheet and the development of draft IFRS financial statements. |
| | · | Implementation and review phase – Involves training key finance and other personnel and implementation of the required changes to our information systems and business policies and procedures. It will enable us to collect the financial information necessary to prepare IFRS financial statements and obtain audit committee approval of IFRS financial statements. |
OPTI has completed the initial diagnostic phase and the impact analysis, evaluation and solution development phase is on going at quarter-end.
Business 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 2011 and there may be other differences identified as we evaluate IFRS.
IFRS requires us to conduct an asset impairment test at the date of adoption of IFRS on January 1, 2011 if indicators of impairment exist. The test for impairment under IFRS requires the use of a discounted cash flow model to determine fair value, whereas Canadian GAAP uses 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, IFRS permits subsequent recovery of such write downs in future periods to the extent that fair value increases.
The absence of a full-cost standard equivalent in IFRS may lead to certain capitalized exploration and development costs under Canadian GAAP being recorded to opening retained deficit. In relation to oil and gas assets, IFRS only provides guidance up to the point that technical feasibility and commercial viability of extracting the resource is demonstrated, the exploration and evaluation phase. IFRS is in line with Canadian GAAP for the accounting for this phase but expenditures beyond this phase must be considered with the capitalization criteria for Property, Plant and Equipment (PP&E) and/or Intangible assets. OPTI’s initial assessment indicates that our development expenditures meet the recognition criteria in relation to PP&E, and no material impact on the measurement of PP&E is expected. The IASB has issued an IFRS 1 exemption for entities using the full cost method from retrospective application of IFRS for oil and gas assets. In addition IFRS requires that significant parts of an asset are recognized and depreciated separately where as Canadian GAAP has not specifically required this. Our current policy of depreciation is in line with the IFRS requirements and therefore no impact is anticipated for this.
Canadian GAAP includes specific standards that prescribe the method for the calculation of depletion which does not exist under IFRS. Canadian GAAP, under full-cost accounting, oil and gas assets are depleted using the unit-of-production method using remaining proved reserves. We are evaluating our accounting policy for depletion to possibly include proved and probable reserves, to determine if this more accurately reflects the usage of our resource assets.
Under Canadian GAAP, transaction costs that are directly attributable to long-term debt can be either netted off the associated debt and amortized into income using the effective interest method or expensed as incurred. We have chosen a policy under Canadian GAAP to expense these costs as incurred. Under IFRS, these costs must be netted off the associated debt and amortized into income using the effective interest method. This is expected to result in a decrease to our opening deficit and a decrease to our long-term debt.
Canadian GAAP includes specific guidance with respect to asset retirement obligations whereas under International Accounting Standards (IAS) asset retirement obligations are included under IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”. The threshold for recognition of a provision under IFRS is lower than under Canadian GAAP As a result a decommissioning liability for the Upgrader must be determined and recorded. Currently under Canadian GAAP, no liability has been recorded for the Upgrader as the present value cannot be reasonably determined as the asset has an indeterminable useful life. In addition, IFRS requires the use of the current market-based discount rate to be applied to the liability at each reporting date rather than the historical rate used when the liability was initially set-up. We do not expect that either of these impacts will be significant.
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 are currently evaluating policies with respect to flow-through shares measurement.
IFRS 1 provides the framework for the first-time adoption of IFRS and specifies that an entity shall apply the principles under IFRS retrospectively. Certain optional exemptions and mandatory exceptions to retrospective application are provided under IFRS. We are completing our analysis of IFRS 1 with respect to the elective exemptions available.
NON-GAAP FINANCIAL MEASURES
The term net field operating margin (loss) does not have any standardized meaning according to Canadian GAAP. It is therefore unlikely to be comparable to similar measures presented by other companies. We have presented this measure on a consistent basis from period to period and plan to do so in the future. We consider net field operating margin (loss) to be an important indicator of the performance of our business as a measure of the performance of the Project and our ability to fund interest payments and invest in capital expenditures. The most comparable Canadian GAAP financial measure is earnings (loss) before taxes. For the periods noted, the following is a reconciliation of loss before taxes to net field operating loss.
| $ millions | | Three months ended June 30, 2010 | | | Six months ended June 30, 2010 | | | Year ended 2009 | |
| Loss before taxes | | $ | (152 | ) | | $ | (202 | ) | | $ | (234 | ) |
| Interest, net | | | 49 | | | | 98 | | | | 150 | |
| General and administrative | | | 3 | | | | 7 | | | | 17 | |
| Financing charges | | | 1 | | | | 1 | | | | 22 | |
| Loss on disposal of assets | | | - | | | | - | | | | 1 | |
| Foreign exchange loss (gain) | | | 104 | | | | 32 | | | | (294 | ) |
| Net realized loss (gain) on hedging instruments | | | 48 | | | | 52 | | | | (40 | ) |
| Net unrealized loss (gain) on hedging instruments | | | (77 | ) | | | (51 | ) | | | 234 | |
| Depletion, depreciation and accretion | | | 13 | | | | 23 | | | | 26 | |
| Net field operating loss | | $ | (11 | ) | | $ | (40 | ) | | $ | (118 | ) |
FINANCIAL INSTRUMENTS
The Company considers its risks in relation to financial instruments in the following categories:
Credit Risk
Credit risk is the risk that a counterparty to a financial instrument will not discharge its obligations, resulting in a financial loss to the Company. The Company has policies and procedures in place that govern the credit risk it will assume. We evaluate credit risk on an ongoing basis including an evaluation of counterparty credit rating and counterparty concentrations measured by amount and percentage. Our objective is to have no credit losses.
The primary sources of credit risk for the Company arise from the following financial assets: (1) cash and cash equivalents; (2) accounts receivable; and (3) hedging instruments. The Company has not had any credit losses in the past and the risk of financial loss is considered to be low given the counterparties used by the Company. As at June 30, 2010, the Company has no financial assets that are past due or impaired due to credit-risk-related defaults.
Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet obligations associated with financial liabilities. Our financial liabilities are comprised of accounts payable and accrued liabilities, hedging instruments, long-term debt and obligations under capital leases. The Company frequently assesses its liquidity position and obligations under its financial liabilities by preparing regular financial forecasts. Our liquidity risk is increased by our relatively high levels of long-term debt and historical net field operating losses. We mitigate liquidity risk by maintaining a sufficient cash balance, maintaining sufficient current and projected liquidity to meet expected future payments based upon reasonable production and pricing assumptions and ensuring we have adequate sources of financing available through bank credit facilities and complying with debt covenants. Our financial liabilities arose primarily from the development of the Project. As at June 30, 2010 the Company has met all of the obligations associated with its financial liabilities. As noted under “Liquidity and Capital Resources,” continued access to our revolving credit facility is a liquidity risk.
Market Risk
Market risk is the risk that the fair value (for assets or liabilities considered to be held for trading and available for sale) or future cash flows (for assets or liabilities considered to be held-to-maturity, other financial liabilities, and loans and receivables) of a financial instrument will fluctuate because of changes in market prices. We evaluate market risk on an ongoing basis. We assess the impact of variability in identified market risks on our medium-term cash requirements and impact with respect to covenants on our credit facilities. At June 30, 2010, we had mitigation programs to reduce market risk related to foreign exchange and commodity price changes. The primary market risks related to our commodity contracts relate to future estimated prices for WTI.
For the six months ended June 30, 2010 we have estimated the following changes to reported net income as a result of changes in market rates as noted. An increase of $1.00/bbl in WTI would have resulted in approximately $0.8 million decrease in our net loss with an offsetting increase in our net loss of approximately $0.4 million as a result of
the increase in the value of our commodity liabilities (assuming the WTI change occurred in a range where the WTI price per barrel is greater than the strike price of our commodity swap), a $0.10/GJ increase in the price of natural gas would have resulted in approximately a $0.3 million increase in our net loss, a 1.0 percent increase in interest rates would have resulted in approximately a nil increase in our net loss and a $0.01 increase in the Canadian to U.S. exchange rate would decrease our net loss by approximately $11 million considering the impact on our Senior Notes and related interest and our foreign exchange hedging instruments.
The following sections describe these risks in relation to the Company’s key financial instruments.
* Cash and Cash Equivalents
The Company has cash deposits and money market investments with Canadian banks. Counterparty selection is governed by the Company’s treasury policy, which limits concentration of investments and requires that all instruments be rated as investment grade by at least one rating agency. As at June 30, 2010 the amount in cash and cash equivalents was $117 million and the maximum exposure to a single counterparty was $28 million with a major Canadian bank.
As at June 30, 2010, the remaining terms on investments made by the Company are less than 28 days with interest fixed over the period of investment. Maturity dates for investments are established to ensure cash availability for working capital requirements, operating activities and interest payments. Investments are held to maturity and the maturity value does not deviate with changes in market interest rates.
Our cash balances are currently invested exclusively in money market instruments with major Canadian banks in the form of banker’s acceptances, bearer deposit notes, and term deposits. These instruments are widely offered by banks we deal with and are considered direct obligations of the banks that offer them. We manage our exposure to these banks in two primary ways: by limiting the amount invested with a single issuer or guarantor and by investing for relatively short periods of time. We do not expect any investment losses based on these money market investments.
* Accounts Receivable and Deposits
As at June 30, 2010, accounts receivable and deposits were $34 million. Our accounts receivable include amounts due from Nexen related to operating activities and Nexen Marketing related to marketing activities. As at June 30, 2010, our accounts receivable due from Nexen includes $16 million related to marketing activities. We have deposits of $11 million for operating expenses related to advances on joint venture expenses required under our joint venture agreement with Nexen. The Company’s credit risk in regard to accounts receivable therefore relates primarily to the risk of default by Nexen, which has an investment-grade corporate rating from Moody’s Investor Service, and by financial institutions with an investment grade rating. Therefore, we estimate our risk of credit loss as low. Prepaid insurance and property tax costs of $7 million are amortized into earnings over the period of prepayment.
* Accounts Payable and Accrued Liabilities
As at June 30, 2010, accounts payable and accrued liabilities were $66 million. Accounts payable and accrued liabilities are comprised primarily of $58 million due in respect of development and operation of the Project, $7 million due in respect of interest on our Senior Notes and $1 million related to corporate expenses including hedging instruments. Payment terms on development and operation of the Project are typically 30 to 60 days from receipt of invoice and generally do not bear interest. Payments are due on the Senior Notes semi-annually in June and December. The Company has met its obligations in respect of these liabilities.
* Debt and Obligations under Capital Lease
As at June 30, 2010, long-term debt was $2,344 million and obligations under capital leases were $20 million. The terms of the Company’s debt and obligations under capital lease are described in the notes to our financial statements as at June 30, 2010. The Company has met its obligations in respect of these liabilities. The Company accounts for its borrowings under all of its long-term debt and obligations under capital lease on an amortized cost basis.
The $190 million revolving credit facility is a variable interest rate facility with borrowing rates and duration established at the time of the initial borrowing and subsequent extension. The extent of the exposure to interest rate risk depends on the amount outstanding under the facility. As at June 30, 2010, $40 million has been drawn under the revolving credit facility.
Our Senior Notes are comprised of US$2,175 million of debt which has fixed U.S. dollar semi-annual interest payments. Changes in the exchange rate between the Canadian dollar and U.S. dollar impact the carrying value of the Senior Notes. A CDN$0.01 change in the exchange rate will impact the carrying value of the Senior Notes by approximately $22 million. A CDN$0.01 change in the exchange rate will change our annual interest costs by approximately $2 million. The exposure to exchange rate fluctuations has been partially mitigated by the instruments described under “Foreign Exchange Hedging Instruments.” These changes also influence our compliance with debt covenants as described under ”Liquidity and Capital Resources.”
* Hedging Instruments
The Company periodically uses instruments to hedge certain of the Company’s projected operational or financial risks. In the past, such instruments have involved the use of interest rate swaps, cross-currency interest swaps, currency-forward contracts and crude oil put options and swaps. Hedging instruments outstanding are described in the notes to our financial statements as at June 30, 2010. These instruments are designated as held-for-trading and are measured at fair value at each financial statement date.
Foreign exchange hedging instruments
OPTI is exposed to foreign exchange rate risk on our long-term U.S. dollar-denominated debt. At June 30, 2010, we have US$620 million of foreign exchange hedging 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$1.19 to US$1.00. Changes
in the exchange rate between Canadian and U.S. dollars change the value of these instruments. These hedging instruments currently expire in December 2010. With respect to our U.S. dollar-denominated debt, the instruments provide protection against a decline in the value of the Canadian dollar below CDN$1.19 to US$1.00 on a portion of our debt. The foreign exchange hedging instruments at June 30, 2010 are a liability of $76 million. During the quarter, we settled a US$255 million notional amount of these instruments with a payment of $44 million. The foreign exchange hedging instruments are measured by the present value of the difference between the settlement amounts of the instruments as measured in Canadian dollars. The counterparties to the foreign exchange hedging instruments are major Canadian and international banks and lenders under OPTI’s revolving credit facility. Our exposure to non-payment from any single institution at June 30, 2010, is approximately 40 percent of the value of these hedging instruments.
Prior to the expiry of the foreign exchange hedging instruments in December 2010, OPTI may choose to settle or to 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. Based on the active market for the underlying market variables used in the valuation, we do not believe other market assumptions could result in a materially different valuation than the one we have determined. This conclusion is supported by an internal evaluation. As of June 30, 2010, the value of the foreign exchange hedging instruments would change by approximately $6 million for each $0.01 change in the foreign exchange rate between U.S. and Canadian dollars. This change would have a corresponding impact on earnings (loss) before taxes in 2010.
Commodity hedging instruments
We have established commodity hedging contracts to mitigate the Company’s exposure of future operations to decreases in the price of its synthetic crude oil. The Company has commodity price swaps to mitigate a portion of the exposure. As at June 30, 2010 the Company has WTI price swaps that provide for 3,000 bbl/d at strike prices between US$64/bbl and US$67/bbl of crude oil through to December 31, 2010. The value of these financial instruments as at June 30, 2010 was a liability of $7 million. The counterparties to the commodity hedges are major Canadian banks and lenders under OPTI’s revolving credit facility. Our exposure to non-payment from any single institution is approximately 38 percent of the value of the commodity asset with a major Canadian bank.
The fair value of the commodity hedges is determined by calculating the present value of the existing contract as measured in Canadian dollars in reference to established market rates, primarily future estimated prices for WTI and period-end foreign exchange rates. Based on the active market for the underlying market variables used in the evaluation, we do not believe other market assumptions with respect to these variables could result in a materially different valuation than the one we have determined. This conclusion is supported by an internal comparison completed by OPTI to compare the valuation provided by each counterparty to the contract. The value of the remaining commodity hedges would change by approximately $0.6 million for each US$1/bbl change in future estimated prices for WTI. This change would have a corresponding impact on our earnings (loss) before taxes.
We view the credit risk of these counterparties as low due to the amounts hedged and the diversification of the instrument with a number of banks.
RISK FACTORS
Our risk factors are consistent with our 2009 annual MD&A dated February 8, 2010.
