MANAGEMENT’S DISCUSSION AND ANALYSIS
For the period ended
September 30, 2010
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis (MD&A), dated October 27, 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 nine month periods ended September 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; 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 not extended, 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; OPTI's anticipated financial condition and liquidity over the next 12 months and in the long term; the final outcome of OPTI’s strategic alternatives proce ss; 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 projecti ons 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.
Our most recent netback information can be found in our MD&A for the year ended December 31, 2009 and our MD&A for the three and six month periods ended June 30, 2010. 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 September 30, 2010 | Nine months ended September 30, 2010 | Year ended December 31, 2009 |
| Net loss | $ (46) | $ (249) | $ (306) |
| Net field operating loss | (20) | (61) | (118) |
| Working capital | 194 | 194 | 168 |
Total oil sands expenditures (1) | 21 | 69 | 148 |
| Shareholders’ equity | $ 1,064 | $ 1,064 | $ 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 September 30, 2010 after giving effect to the exercise of stock options would be approximately 285 million common shares. |
PROJECT STATUS
Long Lake Project operational results for the third quarter of 2010 were impacted by temporary surface issues in August and September. The highest monthly average bitumen production-to-date was achieved in July, averaging approximately 28,700 barrels per day (bbl/d) (10,000 bbl/d net to OPTI), followed by lower production levels in the two months that followed.
During the quarter, bitumen production averaged approximately 26,400 bbl/d (9,200 bbl/d net to OPTI), an increase from the previous quarter average of approximately 24,900 bbl/d (8,700 bbl/d net to OPTI). With process issues resolved and well optimization work completed, recent bitumen production is at a record high of approximately 31,700 bbl/d (11,100 net to OPTI).
Production ramp-up through the third quarter was less than expected for the following reasons. First, as previously announced on August 11, 2010, a combination of unplanned Upgrader maintenance and short-term pipeline restrictions resulted in a temporary reduction in steam injection and bitumen production. The maintenance was
necessary due to an unplanned plant outage at the end of July, which halted the supply of oxygen from our air separation unit to the gasifier. As a result, August syngas production and thus steam generation and bitumen production were affected. SAGD operations remained on-line in a reduced capacity during this time. Second, further plant power outages, related to lightning strikes, inhibited bitumen ramp-up in September. Finally, planned optimization work on SAGD wells meant that a number of producing wells were temporarily shut-in for periods of time throughout the quarter. Optimization work included installation and upsizing of electric submersible pumps (ESPs) as well as acid stimulations on select wells. Affected wells returned quickly to previous bitumen production rates and the optimization work is expected to result in increased pr oduction going forward.
Although our ability to generate steam was temporarily affected, our SAGD surface facilities continue to perform reliably. While steam injection rates were lower in August and September, steam levels increased on aggregate over the third quarter to average approximately 145,700 bbl/d as compared to 137,000 bbl/d in the previous quarter. We expect these rates to continue climbing, as evidenced by recent steam injection of approximately 163,000 bbl/d. We currently have 84 of 91 well pairs receiving steam, comprised of 78 well pairs on production and an additional 6 in circulation mode. We expect that these circulating wells will be converted to production mode in the near term.
Our recent all-in SOR average is approximately 5.2. The all-in SOR average includes steam to wells that are currently in steam circulation mode and wells early in the ramp-up cycle. We continue to expect bitumen production to rise and the corresponding SOR to decrease as remaining wells convert to production mode, stable operations are maintained and producing wells mature.
Achieving high bitumen production is the most important element to the Project’s profitability. Therefore, as announced in our second quarter of 2010 results, we continue to develop SAGD well pads 12 and 13 at Long Lake. Drilling of these 18 new well pairs is expected to occur in 2011 with the wells available for bitumen production in 2012. The joint venture partners also continue to evaluate the addition of two supplementary once-through steam generators. The performance of SAGD operations and the Upgrader may differ from our expectations. There are many factors related to the characteristics of the reservoir and operating facilities that could cause bitumen and PSC™ production to be lower than anticipated.
Throughout the month of July, Upgrader units performed consistently, processing virtually all of our produced bitumen as well as approximately 9,900 bbl/d of externally-sourced bitumen. During August, the plant outage meant that we were unable to process all available bitumen through the Upgrader for an extended period of time. In September, the plant upsets caused a reduction in the amount of bitumen production and externally-sourced bitumen feed to the Upgrader. These temporary outages resulted in a decreased on-stream time average of 81 percent in the third quarter as compared to 97 percent in the previous quarter. PSCTM yields were also lower over the quarter, averaging approximately 62 percent as compared to 72 percent in the previous quarter. We are curre ntly processing virtually all of our produced and externally-sourced bitumen with current PSC™ yields of approximately 75 percent. We continue to expect yields to increase to the design rate of 80 percent once operations are optimized.
FUTURE EXPANSIONS
OPTI and Nexen continue to evaluate developing SAGD projects in approximately 40,000 bbl/d bitumen stages at Kinosis, the next development. 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. Depending on many factors, we may sanction the first stage of Kinosis in 2012.
LIQUIDITY
On August 20, 2010, we announced the completion of the issuance of US$100million face value of 9.0% First Lien Senior Secured Notes (US$100 million First Lien Notes) due December 15, 2012 and US$300 million face value of 9.750% First Lien Senior Secured Notes (US$300 million First Lien Notes) due August 15, 2013. The US$100 million First Lien Notes were offered as additional notes under OPTI’s existing US$425 million First Lien Notes (combined, the US$525 million First Lien Notes). The US$100 million First Lien Notes and US$300 million First Lien Notes were issued at a price of 99.5 percent and 96.5 percent respectively, resulting in a yield to maturity of approximately 9.2 percent and 11.2 percent respectively.
The net proceeds to OPTI from this issuance were approximately C$392 million, after deducting certain fees and expenses related to the offerings and adjusting for the offering prices noted above. A portion of the net proceeds was used to fund an interest reserve account of approximately US$87 million relating to the US$300 million First Lien Notes. The purpose of the offerings is to maintain sufficient liquidity through ramp-up of the Project and to allow OPTI to continue with its review of strategic alternatives.
Based primarily on our expectation of a significant increase in bitumen production, we expect our existing financial resources will be sufficient to meet our financial obligations over the next 12 months. 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.
STRATEGIC ALTERNATIVES REVIEW
OPTI’s Board of Directors remains committed to its review of strategic alternatives for the Company. The ultimate objective of carrying out this review is to determine which alternative(s) might result in superior value for stakeholders. OPTI continues to pursue a strategic alternatives outcome 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. 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.
CORPORATE UPDATE
Effective October 1, 2010, OPTI appointed David Bowes to the position of Treasurer. Mr. Bowes has been with OPTI for six years in increasingly senior treasury roles. Concurrent with this appointment, Ms. Kiren Singh, former Vice President and Treasurer, departed OPTI to pursue other opportunities.
OPTI's senior management consists of: Chris Slubicki, President and Chief Executive Officer; Travis Beatty, VP Finance and CFO; Joe Bradford, VP Legal and Administration and Corporate Secretary; and Al Smith, VP Marketing.
RESULTS OF OPERATIONS
| | Three months ended September 30 | Nine months ended September 30 |
| $ millions, except per share amounts | 2010 | 2009 | 2010 | 2009 |
| Revenue, net of royalties | $ 59 | $ 38 | $ 170 | $ 101 |
| Expenses | | | | |
| Operating expense | 54 | 44 | 159 | 111 |
| Diluent and feedstock purchases | 21 | 29 | 60 | 78 |
| Transportation | 4 | 3 | 12 | 9 |
| Net field operating loss | (20) | (38) | (61) | (97) |
| Corporate expenses | | | | |
| Interest, net | 55 | 46 | 154 | 107 |
| General and administrative | 4 | 2 | 11 | 15 |
| Financing charges | 14 | 4 | 15 | 5 |
| Realized loss (gain) on hedging instruments | 3 | (5) | 55 | (40) |
| Loss before non-cash items | (96) | (85) | (296) | (184) |
| Non-cash items | | | | |
| Foreign exchange translation loss (gain) | (77) | (162) | (46) | (258) |
| Net unrealized loss (gain) on hedging instruments | 14 | 82 | (37) | 198 |
| Depletion, depreciation and accretion | 13 | 5 | 36 | 16 |
| Loss on disposal of assets | - | - | - | 2 |
| Future tax recovery | - | (22) | - | (47) |
| Net earnings (loss) | $ (46) | $ 12 | $ (249) | $ (95) |
| Earnings (loss) per share, basic and diluted | $ (0.16) | $ 0.04 | $ (0.88) | $ (0.42) |
Operational Overview
The results of operations for the three and nine month periods ended September 30, 2010, as well as for the three months ended September 30, 2009, include SAGD and Upgrader results. The results of operations for the nine months ended September 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 nine months ended September 30, 2010 was a combination of PSC™, 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 and third 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 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 a continued high level of Upgrader on-stream factor will lead to impr ovements 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 September 30, 2010 increased to a loss of $20 million from a loss of $11 million for the three months ended June 30, 2010. In July, PSC™ and bitumen production levels improved relative to preceding months in the second quarter of 2010. During August, the plant experienced a combination of unplanned Upgrader maintenance and short-term pipeline restrictions. Therefore, we sold PSH rather than PSC™, which also resulted in the requirement for diluent purchases. In September, OPTI commenced selling PSC™ but further power outages resulted in downtime of various Upgrader units. We anticipate that increased production and other operating improvements will lead to a positive net field operating margin.
The Upgrader on-stream factor for the three months ended September 30, 2010 decreased to 81 percent from 97 percent for the three months ended June 30, 2010. PSC™ yields for the three months ended September 30, 2010 decreased to 62 percent from 72 percent for the three months ended June 30, 2010. Our share of PSC™ sales decreased to 4,800 bbl/d for the three months ended September 30, 2010 compared to 7,100 bbl/d in for the three months ended June 30, 2010 while our share of PSH sales increased to 4,800 bbl/d for the three months ended September 30, 2010 from 1,700 bbl/d for the three months ended June 30, 2010. As a result of the lower on-stream factor and lower Upgrader feed rates, diluent purchases were required in August.
Revenue
For the three months ended September 30, 2010 we earned revenue net of royalties of $59 million compared to $38 million for the same period in 2009. For the three months ended September 30, 2010 our share of PSC™ sales averaged 4,800 bbl/d at an average price of approximately $79/bbl compared to 800 bbl/d at an average price of approximately $75/bbl for the same period in 2009. For three months ended September 30, 2010 our share of PSH averaged 4,800 bbl/d at an average price of approximately $53/bbl compared to 5,600 bbl/d at an average price of approximately $62/bbl for the same period in 2009. Due to temporary industry-wide pipeline capacity restrictions, we realized substantially lower market prices on our PSH sales. Our share of bitumen production for three months ended September 30, 2010 averaged 9,000 bbl/d compared to 3,000 bbl/d for the same period in 2009. Our total revenue, net of royalties, diluent and feedstock increased to $38 million for the three months ended September 30, 2010 compared to $9 million for the same period in 2009.
For the nine months ended September 30, 2010, we earned revenue net of royalties of $170 million compared to $101 million for the same period in 2009. Our total revenue, net of royalties, diluent and feedstock was $110 million for the nine months ended September 30, 2010 compared to $23 million for the same period in 2009.
Increases to total revenue, net of royalties, diluent and feedstock for the three and nine month periods ended September 30, 2010, compared to the same periods in 2009, are due to increased bitumen production and higher PSC™ sales in 2010 as a result of a higher Upgrader on-stream time in 2010 as well as higher commodity prices.
For the three and nine month periods ended September 30, 2010 we received pricing for PSCTM in-line with, or slightly better than, other synthetic crude oils.
For the three months ended September 30, 2010 we had power sales of $1 million representing approximately 34,400 megawatt hours (MWh) of electricity sold at an average price of approximately $37/MWh compared to power sales of $1 million for the same period in 2009, which represented approximately 36,800 MWh at an average price of approximately $39/MWh. For the nine months ended September 30, 2010 we had power sales of $6 million compared to $4 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 September 30, 2010 operating expenses were $54 million compared to $44 million for the same period in 2009. Operating expenses increased due to planned well work-overs and increased operating levels.
For the nine months ended September 30, 2010 operating expenses were $159 million compared to $111 million for the same period in 2009. Operating expenses in 2010 are higher as they included SAGD and Upgrader operating results for the entire period as well as higher operating levels. 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 September 30, 2010 diluent and feedstock purchases were $21 million compared to $29 million for the same period in 2009. For the three months ended September 30, 2010 diluent purchases were 700 bbl/d at an average price of $85/bbl compared to 3,000 bbl/d at an average price of $73/bbl for to the same period in 2009. For the nine months ended September 30, 2010 diluent purchases were 300 bbl/d at an average price of $83/bbl compared to 3,000 bbl/d at an average price of $63/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 (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.
For the three months ended September 30, 2010 we purchased $16 million of third party bitumen representing approximately 3,300 bbl/d compared to $9 million representing approximately 1,300 bbl/d for the same period in 2009. For the nine months ended September 30, 2010 we purchased $54 million of third party bitumen compared to $28 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 September 30, 2010 transportation expenses were $4 million compared to $3 million for the same period in 2009. For the nine months ended September 30, 2010 transportation expenses were $12 million compared to $9 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 September 30, 2010 net interest expense was $55 million compared to $46 million for the same period in 2009. For the nine months ended September 30, 2010 net interest expense was $154 million compared to $107 million for the same period in 2009. The increase in net interest expense in 2010 was due to the US$425 million First Lien Notes issued in November 2009, 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 period and interest related to the Upgrader only from April 1, 2009. Interest expense includes the accretion of the discount related to the issuance of the Senior notes in 2009 and 2010. The remaining discount of $21 million will be amortized over the terms o f the facilities.
For the three and nine months ended September 30, 2010 the average Canadian dollar exchange rate strengthened resulting in a decrease in Canadian interest costs on our U.S. dollar-denominated debt.
* General and Administrative (G&A) Expense
For the three months ended September 30, 2010 G&A expense was $4 million compared to $2 million for the same period in 2009. For the nine months ended September 30, 2010 G&A expense was $11 million compared to $15 million for the same period in 2009. Included in G&A expense for the nine months ended September 30, 2010 was $3 million related to the strategic alternative process. For the nine months ended September, 30, 2010 G&A expense was lower 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 to Nexen. Included in G&A expense is a non-cash stock-based compensation expense for the three months ended September 30, 2010 of $0.5 million (three months ended September 30, 2009: $0.4 million) and for the nine months ended Sep tember 30, 2010 of $1.3 million (nine months ended September 30, 2009: $0.6 million).
* Financing charges
Financing charges were $14 million for the three months ended September 30, 2010 compared to $4 million for the same period in 2009, and $15 million in the nine months ended September 30, 2010 compared to $5 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 amendment to our revolving debt facility covenants and evaluation of financing alternatives.
* Net realized gain or loss on hedging instruments
For the three months ended September 30, 2010 net realized loss on hedging instruments was $3 million compared to a gain of $5 million for the same period in 2009. For the nine months ended September 30, 2010 net realized loss on hedging instruments was $55 million compared to a gain of $40 million for the same period in 2009. The losses in 2010 relate to the $44 million settlement of foreign exchange hedging instruments in the second quarter and our realized commodity hedging losses. 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 three months ended September 30, 2010 was US$75/bbl and for the nine months ended September 30, 2010 was US$78/bbl. The gains in 2009 were related to our US$8 0/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 September 30, 2010 foreign exchange translation was a $77 million gain compared to a $162 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 third quarter of 2010, the Canadian dollar strengthened from CDN$1.06:US$1.00 to CDN$1.03:US$1.00 resulting in a foreign exchange translation gain.
For the nine months ended September 30, 2010 foreign exchange translation was a $46 million gain compared to a $258 million gain for the same period in 2009. During the 2010 period, the Canadian dollar strengthened from CDN$1.05:US$1.00 to CDN$1.03:US$1.00 resulting in a foreign exchange translation gain. These gains and losses are unrealized.
* Net unrealized gain or loss on hedging instruments
For the three months ended September 30, 2010 net unrealized loss on hedging instruments was $14 million compared to an $82 million loss for the same period in 2009. The net unrealized loss is comprised of a $16 million unrealized loss on our foreign exchange hedging instruments due to the strengthening of the Canadian dollar from CDN$1.06:US$1.00 to CDN$1.03:US$1.00 and a $2 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.
For the nine months ended September 30, 2010 net unrealized gain on hedging instruments was $37 million compared to a $198 million loss for the same period in 2009. The net unrealized gain is comprised of a $14 million unrealized gain on our commodity hedges due to the maturing of the instruments during the period and a $23 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 realized cash outflow due to the settlement of foreign exchange hedging instruments offset by a loss due to the strengthening of the Canadian dollar from CDN$1.05:US$1.00 to
CDN$1.03:US$1.00. 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 accretion (DD&A)
For the three months ended September 30, 2010 DD&A was $13 million compared to $5 million for the same period in 2009. For the nine months ended September 30, 2010 DD&A was $36 million compared to $16 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 nine month periods ending September 30, 2010, loss on disposal of assets was nil, compared to nil 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 nine months ended September 30, 2010, future tax recovery was nil, compared to $22 million and $47 million respectively for the corresponding periods in 2009. For the three and nine month periods ended September 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 had 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 September 30, 2010 | Nine months ended September 30, 2010 | Year ended 2009 |
| The Long Lake Project – Phase 1 | | | |
| Sustaining capital | $ 19 | $ 55 | $ 83 |
| Capitalized operations | - | - | 19 |
| Total Long Lake Project | 19 | 55 | 102 |
| Expenditures on future expansions | | | |
| Engineering and equipment | 2 | 11 | 21 |
| Resource acquisition and delineation | - | 3 | 25 |
| Total oil sands expenditures | 21 | 69 | 148 |
| Capitalized interest | - | - | 29 |
| Other capital expenditures | - | - | (19) |
| Total capital expenditures | $ 21 | $ 69 | $ 158 |
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. For three months ended September 30, 2010 we had sustaining capital expenditures of $19 million. These capital expenditures include: the installation of additional ESPs in producing wells for better well control and enhanced bitumen extraction; operations optimization projects; and oil removal filters for oil and particulate removal from the produced water stream for improved water treatment. We also completed the tie-in of the Pad 11 warm-up separator and made progress on civil and engineering work on two additional well pads.
SUMMARY FINANCIAL INFORMATION
| | | | 2010 | | | | 2009 | | | | 2008 | |
In millions (unaudited) (except per share amounts) | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | |
| Revenue | | $ | 59 | | | $ | 61 | | | $ | 50 | | | $ | 43 | | | $ | 38 | | | $ | 34 | | | $ | 29 | | | $ | 69 | |
| Net earnings (loss) | | | (46 | ) | | | (152 | ) | | | (50 | ) | | | (212 | ) | | | 12 | | | | (9 | ) | | | (97 | ) | | | (410 | ) |
Earnings (loss) per share, basic and diluted | | $ | (0.16 | ) | | $ | (0.54 | ) | | $ | (0.18 | ) | | $ | (0.75 | ) | | $ | 0.04 | | | $ | (0.04 | ) | | $ | (0.50 | ) | | $ | (2.09 | ) |
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.
During the fourth quarter of 2008 we generated revenue and incurred operating expenditures associated with early stages of SAGD operation. 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 offset by unrealized losses on hedging i nstruments 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.
SHARE CAPITAL
At October 20, 2010, OPTI had 281,749,526 common shares and 2,761,500 common share options outstanding. The common share options have a weighted average exercise price of $4.42 per share.
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2010 we had approximately $521 million of financial resources, consisting of $341 million of cash on hand and $180 million of undrawn credit capacity remaining under our revolving credit facility. Our cash and cash equivalents are invested exclusively in money market instruments issued by major Canadian banks. In addition, we have 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 of which $10 million is outstanding at September 30, 2010. In October, the remaining amounts owing on the revolving credit facility were repaid.
Expected remaining cash outflows for 2010 include approximately $50 million of the total capital budget of $119 million and US$94 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, a loss of $11 million in the second quarter and a loss of $20 million on the third quarter of 2010. In order for the net field operating margin to become positive, 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 i ncrease in bitumen production, we expect our existing financial resources will be sufficient to meet our financial obligations over the next 12 months. 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.
OPTI has US$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. During the third quarter, we entered into a new transaction to purchase Canadian dollars and sell U.S. dollars. These instruments have a notional amount of US$200
million at a rate of approximately CDN$1.06:US$1.00 with an expiry in December 2010. The instruments effectively offset changes in value of US$200 million of the US$620 million of the forward contracts and result in a net fixed payment of $26 million in December 2010. The remaining US$420 million matures in December 2010 and if these hedges are not extended, the resulting cash settlement will be a function of the foreign exchange rate in effect at the maturity date. OPTI may extend the remaining US$420 million instruments past the current maturity date. The cash settlement of our foreign exchange hedging instruments at the September 30, 2010 foreign exchange rate of CDN$1.03:US$1.00 would be $92 million. The actual future cash settlement could be materially different, as a $0.01 change in the foreign exchange rate will change this obligat ion by approximately $4 million.
For the three months ended September 30, 2010 cash used by operating activities was $35 million, cash provided by financing activities was $378 million and cash used by investing activities was $112 million. These cash flows, combined with a translation loss on our U.S. dollar denominated cash of $7 million, resulted in an increase in cash and cash equivalents during the period of $224 million.
During the third quarter of 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 $40 million of the $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$300 million First Lien Notes. 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 stakeholder value. A primary objective of this process is to reduce our overall leverage and position the Company for future phase development. 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.
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 the first three quarters of 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.
If production levels and rates of increase in 2011 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, as amended in August 2010, 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 September 30, 2010, for the purposes of this ratio calculation, our debt wo uld be increased by the amount of our foreign exchange hedge liability in the amount of $92 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 third quarter of 2010 is 65 percent.
In respect of each new borrowing under the $190 million revolving credit facility, we must satisfy certain conditions precedent prior to making a new borrowing. These include confirmations that the representations and warranties in our loan documents are correct on the date of the new borrowing, that no event of default has occurred and that there has not been a change or development that would constitute a material adverse effect.
With respect to our 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. If our 2010 reserve report has a material reduction in the present value of cash flows, we may be restricted from issuing new senior debt and/or borrowing undrawn amounts under our credit facility. In each case, the debt ca pacity is related to new facilities or new borrowing under our revolving credit facility and will not affect our existing Senior Notes.
We have annual interest payments of US$47 million each year until maturity on the US$525 million First Lien Notes in 2012, interest payments of US$29 million each year until maturity on the US$300 million First Lien Notes in 2013 and annual interest payments of US$142 million each year until maturity on 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 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
expansions will require significant financial resources. We expect to require additional financial resources to develop the future expansions.
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 September 30, 2010.
| | Moody's | S&P |
| OPTI Corporate Rating | Caa2 | CCC+ |
| Revolving Credit Facility | B1 | B |
| First Lien Notes – US$525 million | B2 | B |
| First Lien Notes – US$300 million | B3 | B |
| Secured Notes – US$1,000 million | Caa3 | B- |
| Secured Notes – US$750 million | Caa3 | B- |
Moody’s assigned a B3 rating to the new US$300 million First Lien Notes. Moody’s ratings remained unchanged for all other existing ratings. The outlook remains negative according to Moody’s.
S&P assigned a B rating to the new US $300 million First Lien Notes. S&P lowered the ratings on the $525 million First Lien Notes (consisting of the existing US$425 million First Lien Notes and the new US$100 million First Lien Notes) from B+ to B, lowered the ratings on the US$1,000 million Secured Notes and the US$750 million Secured Notes from B to B-, and lowered OPTI’s corporate rating from B- to CCC+. S&P has upgraded their outlook from negative to stable.
A security recommendation 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 three months ended September 30, 2010 the measurement amount of the interest and principal on our Senior Notes decreased due to a lower Canadian dollar equivalent associated with a stronger Canadian dollar.
The following table shows our contractual obligations and commitments related to financial liabilities at September 30, 2010.
| In $ millions | Total | 2010 | 2011–2012 | 2013–2014 | Thereafter |
Accounts payable and accrued liabilities(1) | $ 63 | $ 63 | $ - | $ - | $ - |
| Hedging instruments (foreign exchange) | 92 | 92 | - | - | - |
| Hedging instruments (commodity) | 5 | 5 | - | - | - |
Long-term debt (Senior Notes - principal)(2) | 2,650 | - | 849 | 1,801 | - |
Long-term debt (Senior Notes - interest)(3) | 867 | 97 | 449 | 321 | - |
Long-term debt (Revolving facility principal)(4) | 10 | - | 10 | - | - |
Capital leases(5) | 65 | 1 | 6 | 6 | 52 |
Operating leases and other commitments(5) | 68 | 3 | 21 | 16 | 28 |
Contracts and purchase orders(6) | 4 | 4 | - | - | - |
| Total commitments | $ 3,824 | $ 265 | $ 1,335 | $ 2,144 | $ 80 |
| | (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$1.03 to US$1.00 as at September 30, 2010. |
| | (3) | Consists of scheduled interest payments on the Senior Notes, translated into Canadian dollars using an exchange rate of CDN$1.03 to US$1.00 as at September 30, 2010. |
| | (4) | As at September 30, 2010, we have borrowed $10 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 September 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
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 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 and the implementation and review phase are ongoing 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.
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, 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. This is expected to result in an increase to our asset retirement obligation with an associated increase in our PP&E and opening deficit.
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 September 30, 2010 | Nine months ended September 30, 2010 | Year ended 2009 |
| Loss before taxes | $ (46) | $ (249) | $(234) |
| Interest, net | 55 | 154 | 150 |
| General and administrative | 4 | 11 | 17 |
| Financing charges | 14 | 15 | 22 |
| Loss on disposal of assets | - | - | 1 |
| Foreign exchange gain | (77) | (46) | (294) |
| Net realized loss (gain) on hedging instruments | 3 | 55 | (40) |
| Net unrealized loss (gain) on hedging instruments | 14 | (37) | 234 |
| Depletion, depreciation and accretion | 13 | 36 | 26 |
| Net field operating loss | $ (20) | $ (61) | $(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) interest reserve account; (3) accounts receivable; and (4) 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 September 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 faciliti es and complying with debt covenants. Our financial liabilities arose primarily from the development of the Project. As at September 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 September 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 nine months ended September 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 $1.5 million decrease in our net loss with an offsetting increase in our net loss of approximately $0.5 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 $0.5 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 $16 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 September 30, 2010 the amount in cash and cash equivalents was $341 million and the maximum exposure to a single counterparty was $85 million with a major Canadian bank.
As at September 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.
* Interest reserve account
As at September 30, 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. Under the indenture we are allowed to invest these funds in specific investment instruments. We currently invest these funds in U.S. Treasury bills which provide a highly rated and secure investment alternative to ensure security of principle invested.
* Accounts Receivable and Deposits
As at September 30, 2010, accounts receivable and deposits were $32 million. Our accounts receivable include amounts due from Nexen related to operating activities and Nexen Marketing related to marketing activities. As at September 30, 2010, our accounts receivable due from Nexen includes $14 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 September 30, 2010, accounts payable and accrued liabilities were $124 million. Accounts payable and accrued liabilities are comprised primarily of $62 million due in respect of development and operation of the Project, $61 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 September 30, 2010, long-term debt was $2,639 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 September 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 September 30, 2010, $10 million has been drawn under the revolving credit facility.
Our 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. 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 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 September 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 September 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. During the quarter ended September 30, 2010, OPTI entered into a new transaction to purchase Canadian dollars and sell U.S. dollars. These instruments have a notional amount of US$200 million at a rate of approximately
CDN$1.06 to US$1.00 with an expiry in December 2010. The instruments effectively offset changes in value of US$200 million of the US$620 million of the forward contracts and result in a net fixed payment of $26 million in December 2010. 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 September 30, 2010 are a liability of $92 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 Canadi an 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 September 30, 2010, is approximately 37 percent of the value of these hedging instruments if the instruments are in a gain position relative to the Company.
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 September 30, 2010, the value of the foreign exchange hedging 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 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 September 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 September 30, 2010 was a liability of $5 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 $0.3 million for each US$1/bbl change in future estimated prices for WTI. This change would have a corresponding impact o n 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.
