OPTI Canada Announces Third Quarter 2009 Results
TSX: OPC
The
"We had a good quarter operationally. Our objectives in the third quarter were to complete the planned turnaround and to start-up the final components of the Upgrader, which are the thermal cracker and the solvent deasphalter. Both of these objectives were successfully accomplished and the Project is now positioned to ramp-up with improved PSC(TM) yield and enhanced steam generation capabilities," said Chris Slubicki, President and Chief Executive Officer.
FINANCIAL HIGHLIGHTS
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Three months Nine months Year
ended ended ended
September 30, September 30, December 31,
In millions 2009 2009 2008
(as revised)
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Net earnings (loss) $ 12 $ (95) $ (477)(1)
Total oil sands expenditures(2) 31 128 706
Working capital (deficiency) 10 10 (25)
Shareholders' equity $ 1,523 $ 1,523 $ 1,471
Common shares outstanding
(basic)(3) 282 282 196
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Notes:
(1) Includes $369 million pre-tax asset impairment provision related to
working interest sale to Nexen.
(2) Capital expenditures related to Phase 1 and future phase development.
Capitalized interest, hedging gains/losses and non-cash additions or
charges are excluded.
(3) Common shares outstanding at September 30, 2009 after giving effect
to the exercise of stock options would be approximately 287 million
common shares.
OPERATIONAL UPDATE
Several important operational milestones were achieved in the third quarter. First, the previously announced turnaround at the
Another milestone was the completion of the steam debottleneck project that will increase the SAGD steam design capacity to over 230,000 bbl/d. The debottleneck train will start-up as needed to support SAGD ramp-up.
The final milestone was the successful testing of the solvent deasphalter and thermal cracking units in the Upgrader prior to the turnaround. These units will allow the Operator to transition from gasifying vacuum residue, which contains some lighter parts of the barrel, to gasifying the heaviest part of the barrel called asphaltenes. Once this transition is complete we expect PSC(TM) yields to increase to approximately 80%.
Bitumen production in 2009 has been limited by the ability to produce large amounts of steam consistently and over a sustained period. Bitumen production in the third quarter was lower than in previous quarters due to the previously announced intentional reduction of steam injection in order to address water chemistry issues in advance of the turnaround and downtime associated with the turnaround itself. As such, gross bitumen production in the third quarter averaged approximately 8,800 bbl/d (3,000 bbl/d net to OPTI).
Electric submersible pumps (ESPs) continued to be installed in a number of SAGD wells, which will allow us to have better pressure control and ultimately reduce the overall steam to oil ratio (SOR). We currently have approximately 42 well pairs with ESPs.
We expect that the improvements made to the SAGD facility in 2009 will result in a significant increase in bitumen production through 2010 and position the Project to achieve full design rates. We now expect that the Project will be at or near design rates later than our previous guidance of late 2010 and intend to gather post-turnaround operating experience in consultation with the operator prior to providing updated production guidance. Once the Project reaches full design rates, it is expected to produce 20,000 bbl/d of PSC(TM) net to OPTI for over 40 years.
RESULTS OF OPERATIONS
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Three Months Ended Nine Months Ended
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Sep 30 June 30 Sep 30 Sep 30 Sep 30
$ millions 2009 2009 2008 2009 2008
(as revised) (as revised)
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Revenue, net of
royalties $ 38 $ 34 $ 125 $ 101 $ 125
Expenses
Operating expenses 44 39 37 111 37
Diluent and
feedstock
purchases 29 20 89 78 89
Transportation 3 3 2 9 2
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Net field operating
margin (loss) (38) (28) (3) (97) (3)
Corporate expenses
Interest, net 46 42 18 107 14
General and
administrative 2 7 4 15 12
Financing charges 4 1 - 5 1
Realized loss
(gain) on hedging
instruments (5) (11) (4) (40) (8)
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Earnings (loss)
before non-cash
items (85) (67) (21) (184) (22)
Non-cash items
Foreign exchange
translation loss
(gain) (162) (171) 73 (258) 119
Net unrealized
loss (gain) on
hedging
instruments 82 137 (64) 198 (68)
Depletion,
depreciation and
accretion 5 7 6 16 7
Loss on disposal
of assets - 1 - 2 -
Future tax
(recovery) (22) (32) (4) (47) (13)
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Net earnings (loss) $ 12 $ (9) $ (32) $ (95) $ (67)
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Comparative amounts for the three and nine months ended
We define our net field operating margin as revenue related to petroleum products (net of royalties) and power sales minus operating expenses, diluent and feedstock purchases and transportation costs. See "Non-GAAP Financial Measures". This net field operating margin was a loss of
The results of operations for the nine month period ended
Results related to the
Revenue
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For the three months ended
During the third quarter we received pricing for PSC(TM) in-line with or better than other synthetic crude oils. Due to the premium characteristics of our PSC(TM), we expect to increase the premium we receive relative to other synthetic crude oils as production, and therefore the availability of marketed PSC(TM), increases.
In the three months ended
For the nine months ended
Expenses, gains and losses
--------------------------
* Operating expenses
For all three and nine month periods, operating expenses were primarily comprised of natural gas, maintenance, labour and operating materials and services.
Operating expenses were
Operating expenses were
* Diluent and feedstock purchases
Diluent and feedstock purchases were
Diluent and feedstock purchases were
* Transportation
Transportation expenses were
Transportation expenses were
* Net interest expense
Net interest expense was
Net interest expense was
* General and Administrative (G&A)
G&A expense was
G&A expense was
* Financing charges
Financing charges were
Financing charges were
* Loss on disposal of assets
Loss on disposal of assets was $nil million for the three months ended
For the nine months ended
* Foreign exchange gain or loss
The gain or loss is comprised of the re-measurement of our U.S. dollar-denominated long-term debt and cash. Foreign exchange translation was a
For the nine months ended
* Net realized gain or loss on hedging instruments
Net realized gain on hedging instruments was
For the nine months ended
* Net unrealized gain or loss on hedging instruments
Net unrealized gain or loss on hedging instruments was an
For the nine months ended
For the remainder of 2009, our commodity hedges are comprised of a 6,000 bbl/d put option at a net price of approximately US$76/bbl and a 500 bbl/d swap at US$77/bbl. For 2010, our commodity hedges are comprised of WTI commodity price swaps for 3,000 bbl/d at strike prices between US$64/bbl and US$67/bbl.
* Depletion, depreciation and amortization
Depletion, depreciation and amortization (DD&A) was
For the nine months ended
* Future tax (recovery)
Future tax recovery is primarily related to the future tax benefit derived from losses before tax, net of a valuation allowance in respect of non-capital losses which are expected to expire unutilized. Future tax recovery was
CAPITAL EXPENDITURES
The table below identifies expenditures incurred by us in relation to the Project, other oil sands activities and other capital expenditures.
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Three months Nine months
ended ended
September 30, September 30, Year ended
$ millions 2009 2009 2008
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Long Lake Project - Phase 1
Upgrader & SAGD $ 3 $ 22 $ 480
Sustaining capital 20 50 60
Capitalized operations - 18 32
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Total Long Lake Project 23 90 572
Expenditures on future phases
Engineering and equipment 6 16 64
Resource acquisition and
delineation 2 22 70
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Total oil sands expenditures 31 128 706
Capitalized interest - 29 139
Other capital expenditures - (19) 35
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Total cash expenditures 31 138 880
Non-cash capital charges - - 4
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Total capital expenditures $ 31 $ 138 $ 884
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For the three months ended
As with all SAGD projects, new well pads must be drilled and tied into the SAGD central facility in order to maintain production at design rates over the life of the Project. In the third quarter, we had sustaining capital expenditures of
For the three months ended
SUMMARY FINANCIAL INFORMATION
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In millions
(except per 2009 2008 2007
share ---------------------------------------------------------------
amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
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Revenue $ 38 $ 34 $ 29 $ 69 $ 126 $ - $ - $ -
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Net
earnings
(loss) 12 (9) (97) (410) (32) (29) (6) 32
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Earnings
(loss)
per
share,
basic and
diluted $ 0.04 $(0.04) $(0.50) $(2.09) $(0.16) $(0.14) $(0.03) $ 0.16
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The disclosure and analysis with respect to summary financial information has been updated to reflect the retroactive adoption of CICA Handbook section 3064 "Goodwill and Intangible Assets" on
Prior to the third quarter of 2008, earnings have been influenced by fluctuating foreign exchange translation gains and losses primarily related to re-measurement of our U.S. dollar-denominated long-term debt, fluctuating realized and unrealized gains and losses on hedging instruments, and fluctuating future tax expense. During the fourth quarter of 2007, we had a
In the third and fourth quarters of 2008, we generated revenue and incurred operating expenditures associated with early stages of SAGD operation. During the fourth quarter of 2008, we had a pre-tax asset impairment for accounting purposes related to our working interest sale of
The first, second and third quarters of 2009 represent initial stages of operation at relatively low operating volumes and therefore our operating results associated with these activities are expected to improve as SAGD production increases and the Upgrader produces higher volumes of PSC(TM). Refer also to explanations in results of operations regarding realized and unrealized gains and losses related to foreign exchange translation and hedging instruments under the headings "Net realized gain or loss on hedging instruments" and "Net unrealized gain or loss on hedging instruments", above.
Earnings of
SHARE CAPITAL
At
LIQUIDITY AND CAPITAL RESOURCES
At
For the three months ended
During the third quarter of 2009, we used existing cash and net proceeds from our equity issuance to reduce the balance of our revolving credit facility. For the remainder of 2009, cash and availability under our revolving credit facilities are expected to fund our expenditures.
Our rate of production increase after the recently completed turnaround will have a significant impact on our financial position through 2010 and beyond. Primarily due to the plant turnaround completed in the third quarter, our net field operating margin in the most recent quarter is a loss. It is important for our business to increase production to a point where we generate positive net field operating margin. Failure to significantly increase bitumen production from current rates, and ultimately PSC(TM) sales, will result in continued net field operating losses, difficulty in obtaining new credit and capital, and will limit the amount of new borrowings and may accelerate timing of repayments on our revolving credit facility. We will monitor the initial production levels as these will impact the rate and timing of production increases in 2010. Based on these initial production levels and rates of increase, we may determine that we require additional capital to maintain adequate liquidity through the ramp-up of the Project.
Our debt facilities contain a number of provisions that serve to limit the amount of debt we may incur. With respect to our revolving credit facility, the key maintenance covenants are with respect to the ratio of debt outstanding under the revolving credit facility to earnings before interest, taxes and depreciation (EBITDA), and total debt to capitalization. Maintenance covenants are important as they are ongoing conditions that must be satisfied to comply with the terms of the revolving credit facility.
The revolving credit facility debt to EBITDA covenant, which is measured quarterly, was amended in the third quarter of 2009 and now commences in the first quarter of 2010. Under this covenant, this ratio must be lower than 3.5:1 commencing for the quarter ended
In the first quarter of 2010 and subsequent quarters, our compliance with the covenant as currently structured will depend on our operating performance. Although commodity pricing has an impact, the most important factor in determining whether or not we will generate sufficient EBITDA to meet this covenant will be the amount of PSC(TM) revenue we generate. We will need to achieve a significant increase in bitumen production from current levels, which at this point is not assured, to generate sufficient PSC(TM) revenue and therefore EBITDA to meet the covenant. Other risks related to compliance with the EBITDA covenant include commodity pricing, operating costs and capital expenditures. Commodity pricing is a less significant risk in 2010, as we have hedged 3,000 bbl/d with 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"). Should operating or capital costs be greater than anticipated, we would require additional SAGD and PSC(TM) volumes in order to meet this covenant. The majority of our operating and interest costs are fixed. Aside from changes in the price of natural gas, our costs will neither decrease nor increase significantly as a result of fluctuations in WTI prices other than with respect to royalties to the Provincial Government of Alberta, which increase on a sliding scale at WTI prices higher than CDN$55/bbl.
The total debt to capitalization covenant requires that we do not exceed a ratio of 70 percent as calculated on a quarterly basis. The covenant is calculated based on the book value of debt and equity. The book value of debt is adjusted for the effect of any foreign exchange derivatives issued in connection with the debt that may be outstanding. Our capitalization is adjusted to exclude the
In respect of each new borrowing under the
With respect to our 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 2008 reserve report, as adjusted for our new working interest in the joint venture, we have sufficient capacity under this test to incur significant additional debt beyond our existing
We have semi-annual interest payments of US$71 million in June and December of each year until maturity of the 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
Access to capital markets for new equity and debt have improved considerably during 2009. However, there can be no assurance that these positive market conditions will continue nor that they will provide a constructive market for OPTI to access additional capital if we are required to do so. Delays in ramp-up of SAGD production, operating issues with the SAGD or Upgrader operations or deterioration of commodity prices could result in additional funding requirements earlier than we have estimated. Should the Company require such funding, it may be difficult to obtain such financing.
CREDIT RATINGS
OPTI maintains a company rating and a rating for its revolving credit facility and Senior Notes with Moody's Investor Service (Moody's) and Standard and Poor's (S&P). Please refer to the table below for the respective ratings.
Moody's S&P
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OPTI Corporate Rating Caa1 B-
Revolving Credit Facility B1 B+
8.25% Notes Caa1 B
7.875% Notes Caa1 B
The Moody's ratings were confirmed in
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
The following table shows our contractual obligations and commitments related to financial liabilities at
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Remaining 2010 - 2012 -
In $ millions Total 2009 2011 2013 Thereafter
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Accounts payable
and accrued
liabilities(1) $ 80 $ 80 $ - $ - $ -
Long-term debt (Notes
- principal)(2) 1,874 - - - 1,874
Long-term debt
(Notes - interest)(3) 836 76 304 304 152
Long-term debt
(Revolving)(4) 135 - 135 - -
Capital leases(5) 69 1 6 6 56
Operating leases and
other commitments(6) 74 3 20 20 31
Contracts and purchase
orders(7) 9 9 - - -
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Total commitments $ 3,077 $ 169 $ 465 $ 330 $ 2,113
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Notes:
(1) Excludes accrued interest expense related to the Notes.
(2) Consists of principal repayments on the Notes, translated into
Canadian dollars using an exchange rate of CDN$1.07 to US$1.00 at
September 30, 2009.
(3) Consists of scheduled interest payments on the Notes, translated into
Canadian dollars using an exchange rate of CDN$1.07 to US$1.00 at
September 30, 2009.
(4) Consists of $135 million drawn on the revolving credit facility. The
repayment represents only the final repayment of the facility at its
scheduled maturity in 2011. In addition, 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. In addition, such interest amounts are not material
relative to our other commitments.
(5) Consists of our share of future payments under our product
transportation agreements with respect to future tolls during the
initial contract term.
(6) Consists of our share of payments under our product transportation
agreements with respect to future tolls during the initial contract
term.
(7) 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.
NETBACKS
We have provided below an update to our estimated netback for Phase 1 of the Project that was last updated in our MD&A filed on SEDAR on
This financial outlook is intended to provide investors with a measure of the ability of our Project to generate netbacks assuming full production capacity. We believe that the ability of the Project to generate cash to fund interest payments and invest in capital expenditures is a key advantage of our Project and important to our investors. We believe the netback measure is the most appropriate financial gauge to demonstrate this ability as corporate costs (other than corporate G&A expenses), interest, and other non-cash items are excluded from the calculation. The financial outlook may not be suitable for other purposes. We expect netbacks generated by our Project to be lower than shown in this outlook in the initial years following start-up due to the lower production volumes during ramp-up and an initially higher SOR. The netback calculation as presented is a non-GAAP financial measure. The closest GAAP financial measure to the netback calculation is cash flow from operations. However, cash flow from operations includes many other corporate items that affect cash and are independent of the operations of the Project.
The actual netbacks achieved by the Project could differ materially from these estimates. The material risk factors that we have identified toward achieving these netbacks are outlined under "Forward Looking Information" in our AIF. In particular, the SAGD and
Estimated Future Project Post-Payout Netbacks(1)
WTI - WTI - WTI -
US$60(2) US$75(3) US$90(4)
----------- ----------- -----------
$/bbl $/bbl $/bbl
----------- ----------- -----------
Revenue(1) $ 76.44 $ 87.34 $ 96.48
Royalties and Corporate G&A (3.28) (4.36) (5.55)
Operating costs(5)
Natural gas(6) (3.51) (4.00) (4.41)
Other variable(7) (2.00) (2.00) (2.00)
Fixed (15.46) (15.46) (15.46)
Property taxes and insurance(8) (2.81) (2.81) (2.81)
----------- ----------- -----------
Total operating costs (23.78) (24.27) (24.68)
Netback $ 49.38 $ 58.71 $ 66.25
Notes:
(1) The per barrel amounts are based on the expected yield for the
Project of 57,700 bbl/d of PSC(TM) and 800 bbl/d of butane, and
assume that the Upgrader will have an on-stream factor of 96 percent.
These numbers are cash costs only and do not reflect non-cash
charges. See "Note Regarding Forward-Looking Statements".
(2) For purposes of this calculation, with regard to the WTI price
scenario of US$60, we have assumed natural gas costs of US$6.00/mcf,
foreign exchange rates of $1.00 = US$0.775, heavy/light
crude oil price differentials of 32 percent of WTI and electricity
sales prices of $92.66 per MWh. Revenue includes sale of PSC(TM),
bitumen, butane and electricity.
(3) For purposes of this calculation, with regard to the WTI price
scenario of US$75, we have assumed natural gas costs of US$7.50/mcf,
foreign exchange rates of $1.00 = US$0.850, heavy/light
crude oil price differentials of 30 percent of WTI and electricity
sales prices of $105.61 per MWh. Revenue includes sale of PSC(TM),
bitumen, butane and electricity.
(4) For purposes of this calculation, with regard to the WTI price
scenario of US$90, we have assumed natural gas costs of US$9.00/mcf,
foreign exchange rates of $1.00 = US$0.925, heavy/light
crude oil price differentials of 28 percent of WTI and electricity
sales prices of $116.45 per MWh. Revenue includes sale of PSC(TM),
bitumen, butane and electricity.
(5) Costs are in 2009 dollars.
(6) Natural gas costs are based on our long-term estimate for a SOR of
3.0.
(7) Includes approximately $1.00/bbl for greenhouse gas mitigation costs
based on an approximate average 20 percent reduction of CO2 emissions
at a cost of $20 per tonne of CO2.
(8) Property taxes are based on expected mill rates for 2009.
We estimate sustaining capital costs required to maintain production at design rates of capacity to be approximately
Based on US$60WTI and the other assumptions set out in the notes above, we expect our operating costs plus royalties and corporate G&A expenses to be
CONFERENCE CALL
OPTI
(800) 814-4860 (North American Toll-Free)
(416) 644-3419 (Alternate)
Please reference the OPTI
A replay of the call will be available until
This call will also be webcast, and can be accessed on OPTI Canada's website under "Presentations and Webcasts" in the "For Investors" section. The webcast will be available for replay for a period of 30 days. The webcast may alternatively be accessed at: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=2852960.
ABOUT OPTI
OPTI
FORWARD-LOOKING INFORMATION
Certain statements contained herein are forward-looking statements, including, but not limited to, statements relating to: the expected production performance of the
Readers should be aware that the list of assumptions, risks and uncertainties set forth herein are not exhaustive. Readers should refer to OPTI's current Annual Information Form (AIF), which is available at www.sedar.com, for a detailed discussion of these assumptions, risks and uncertainties. The forward-looking statements or information contained in this document are made as of the date hereof and OPTI undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable laws or regulatory policies.
Additional information relating to our Company, including our AIF, can be found at www.sedar.com.
%CIK: 0001177446
For further information: OPTI Canada Inc., (403) 249-9425
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