TC Energy Corp (TRP) 2010 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2010 fourth quarter results conference call.

I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Corporate Communications. Please go ahead, Mr. Moneta.

Thanks very much and good afternoon, everyone.

I'd like to welcome you to TransCanada's 2010 fourth quarter conference call. With me today are Russ Girling, President and Chief Executive Officer, Don Marchand, Executive Vice President and Chief Financial Officer, Alex Pourbaix, President of Energy and Oil Pipelines, and Glenn Menuz, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and other general issues pertaining to the Company. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com. It can be found in the Investor section, under the heading, Events and Presentations. Following their prepared remarks, we'll turn the call over to the conference coordinator for your questions.

During the question and answer period, we'll take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have any additional questions, please re-enter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Terry, Lee and I would be pleased to discuss them with you following the call.

Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities regulators and with the US Securities Exchange Commission.

And finally, I would also like to point out that during this presentation we'll refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation and amortization, or EBITDA, comparable EBITDA, and funds generated from operations. These measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on our operating performance, liquidity and our ability to generate funds to finance our operations.

With that, I will now turn the call over to Russ.

Thanks, David, and good afternoon, everyone.

TransCanada's pipeline and energy infrastructure assets performed very well in 2010, despite what we thought was a very challenging business environment. For the fourth quarter, comparable earnings were CAD384 million, or CAD0.55 per share. This represents a 15% increase, on a per share basis, over the fourth quarter of 2009. On an annual basis for 2010, comparable earnings were CAD1.4 billion, or CAD1.97 per share. Net income applicable to common shares was CAD1.2 billion, or CAD1.78 per share. In the fourth quarter of 2010, we reported a one-time non-cash valuation provision against the MacKenzie gas project. This reduced net income applicable to common shares by about CAD127 million, or CAD0.18 per share.

On the business side, our businesses continue to generate strong, sustainable and growing cash flows. Funds generated from operations in 2010 were CAD3.3 billion, an 8% increase over 2009. Our solid financial performance and significant progress we've made in moving our capital program forward has enabled our Board of Directors to increase the quarterly dividend by 5%, to CAD0.42 per common share. On an annualized basis, this equates to CAD1.68 per common share and it represents the 11th consecutive year the Board has raised the dividend. TransCanada's strong comparable earnings for the fourth quarter of 2010 demonstrate the stability of our core businesses and the importance of continuing to focus on maximizing the value of existing assets to ensure they continue to operate safely, reliably and deliver solid returns.

We continue to advance our CAD20 billion capital program, a program that is essentially half complete today. In the last number of months, we have brought into operation Base Keystone and the Cushing extension, the Groundbirch, Bison and North Central Corridor natural gas pipelines, and the second phase of our Kibby Wind project in Maine and the Halton Hills generating station in Ontario. In the coming months, our Coolidge generating station in Arizona and the Guadalajara natural gas pipeline in Mexico will come online.

Just last week, we were pleased to announce that the extension of the Cushing -- extension of our Keystone pipeline became operational. As you know, last summer we celebrated the first commercial oil deliveries on the Keystone pipeline system to refineries in Wood River and Patoka, Illinois. With the first two phases of the pipeline operational, we now have a capacity to move about 591,000 barrels a day of crude oil, and I would remind you that we have firm long-term contracts for about 530,000 barrels a day, or about 90% of that capacity.

Our focus on the Keystone front now shifts to the US Gulf Coast expansion, where we remain confident Keystone XL will receive its final environmental impact statement and Presidential permit in mid- to late 2011. This project is shovel ready, so once we have regulatory approval we can start construction, and we expect to have the Keystone pipeline operational in 2013. The key to any pipeline project is shipper commitment, companies recognizing a need to get their oil to market. And these companies with many years of experience have told us that they need access to the largest refining market in the world, which is the US Gulf Coast. And as I've told you previously, the market has spoken and the shippers have signed binding contracts with TransCanada to transport their oil to Texas refineries, contracts that now total approximately 445,000 barrels a day, or about 90% of the line's capacity.

Keystone has many benefits, including 20,000 high paying jobs for American families, and the economic benefits of an initial CAD20 billion for the US economy. And with instability in countries like Egypt, the importance of Keystone XL increasing security in the United States has been reinforced. This view was recently backed by a US Department of Energy study that found Keystone XL will help reduce US imports of foreign oil from sources outside of North America. And last week the project received further support from 30 members of the House of Representatives who sent a letter to Secretary Clinton calling our project, and I quote, an extraordinary opportunity to put Americans back to work, invest billions in the economy and improve the security of this nation. It is TransCanada's view that the Keystone XL project can reduce America's dependence on oil from Venezuela and the Middle East by up to 40%.

Moving now to our new projects on the Keystone system, facilities along our Keystone pipeline system will support the flow of American crude oil to market as well. We recently completed the successful open seasons of both our Bakken and Cushing Marketlink projects. Both projects will allow TransCanada to transport approximately 250,000 barrels a day of US crude to refineries in Cushing, and the US Gulf Coast. And finally, we expect total capital costs for the project to be about CAD13 billion US, which is equivalent to the CAD13 billion Canadian at current exchange rates. Approximately one-third of that increase from previous estimates is the result of higher Canadian dollar and its impact on converting Canadian project costs into US dollars. Also, actual cost to complete phases one and two of Keystone rose and our estimated cost for the US Gulf Coast expansion have increased. At December 31, 2010, CAD7.4 billion US had been invested in the project, including CAD1.4 billion in the US Gulf Coast expansion. The remaining CAD5.6 billion is expected to be invested between now and the in-service date of the expansion, which is expected to be in 2013. CAD1.2 billion of that has already been committed. Despite these increases, we still expect to generate an IRR of between 7% and 9% for this project.

Now moving over to the gas pipeline business. The CAD155 million Groundbirch pipeline in Northeast British Columbia has become operational in late December of 2010. Groundbirch connects BC shale gas to our Alberta system. And more positive news in the development of the BC shale gas plays came in just the last couple of weeks, with the announcement by the National Energy Board that it had approved our Horn River project. And like the Groundbirch project, this CAD310 million pipeline will transport shale gas to market. Horn River and Groundbirch combined have shipper commitments to TransCanada's system for nearly 2 billion cubic feet per day by 2014. This additional volume will help offset the recent decline in conventional Western Canadian sedimentary basin volumes and contribute to higher throughput and lower tolls on downstream pipeline systems, including the Canadian main line, in the future.

TransCanada continues to discuss request for further natural gas transmission service from northwest Alberta and Northeast British Columbia. The result is expected to be a need for additional extensions and expansions of the Alberta System, and an increase in shale gas supplies from British Columbia to more than 5 billion cubic feet a day by the end of the decade.

Our Company made further progress on the natural gas side by bringing on the Bison natural gas pipeline. We brought that into service in mid-January. The CAD630 million US project connects the gas supplies in the Powder River Basin in Wyoming, which is one of the only major North American basins which TransCanada was not connected to. Bison will link up northern border pipeline and provide customers with cost competitive access to move their gas to Midwest US markets. The Bison project has long-term contracts for 407 million cubic feet a day, or 100% of its initial design capacity.

On other gas pipeline fronts, construction of our Guadalajara pipeline in Mexico is now 70% complete. The CAD360 million US project is expected to be operational in mid-2011. At 305 kilometers, the 24- and 30-inch diameter gas pipeline will move natural gas from Manzanillo to Guadalajara, which is Mexico's second largest city.

Moving to the main line. We did file an application with the Natural Energy Board in late January for approval of revised interim tolls that would become effective March 1, 2011. The Company's initial interim toll application was rejected by the NEB in December of 2010. The NEB said that it was not appropriate for fundamental changes to be implemented on an interim basis in the face of opposition. Of course, TransCanada was disappointed with that decision, as we felt the application had significant benefits for all shippers. It had the support of many stakeholders, including CAP. Our initial application would have meant all mine line tolls would have been lower or equal to what they would have been under the approved 2007 to 2011 settlement. However, it is important for the dialogue to continue with shippers and other stakeholders to garner additional support for TransCanada's proposals and to develop a long-term arrangement that improves the competitiveness of the Canadian main line and the Western sedimentary basin. The main line continues to be a very important piece of North American gas infrastructure that will be needed for many decades to come. Despite recent declines in volumes, the main line still transported an average of 3.4 billion cubic feet a day in 2010, which is more than any other Alberta export pipeline. And again, in the early part of 2011, Western receipts have been running closer to 4.5 billion cubic feet a day in order to meet increased weather-related demand in eastern markets.

Moving to Alaska, our team, along with our partners ExxonMobil, continue to work hard at advancing the Alaska pipeline project. The project received multiple bids from major industry players and from others for significant volumes. The project team has spent the last number of months discussing potential resolutions to conditions placed on some of the bids by those shippers. We have been doing -- we've been in the field doing comprehensive engineering, environmental and regulatory work to progress the large scale project and our application for FERC approval. We are also doing design work on the gas treatment plant and looking at best ways to construct the pipeline that will withstand extreme weather conditions. So, there's a lot going on in this project, and we remain fully committed to the project with a focus on reaching binding agreements with the shippers to transport Alaska natural gas to market.

On the MacKenzie Valley front, in December 2010 the NEB approved the MacKenzie pipeline project, subject to 264 conditions. As one of the Companies that has invested many years in the project, TransCanada remains committed to bringing MacKenzie Delta gas to market. However, uncertainty remains with respect to the project's ultimate commercial structure, timing of construction, and fiscal discussions with the Federal Government. As a result, TransCanada recorded a valuation provision for its CAD146 million loan to the Aboriginal Pipeline Group. This is consistent with our practice of expensing business development costs in the absence of binding commercial agreements. But as I've told you many times and for some months now, our Company firmly believes that there is a need for MacKenzie gas, Alaska gas, shale gas, and conventional gas for decades to come.

North American produces and consumes approximately 75 Bcf a day of natural gas. With annual decline rate of 20%, 15 Bcf a day must be replaced each year. So, every five years we must replace the entire North American supply. While conventional gas and shale gas will account for a significant amount of future production, there is still more than enough room for Northern gas, from both MacKenzie and Alaska, to meet customer needs over the longer term.

I would like to move now over to the energy side and highlight the progress that we've made on our key energy projects. Construction of the 575-megawatt Coolidge generating station is approximately 95% complete, with commissioning approximately 80% finished. The CAD500 million US project is anticipated to be in service in the second quarter of 2011. TransCanada has a 20-year agreement to sell 100% of the power produced at Coolidge to the local utility. On the wind front, construction continues on the five stage, 590-megawatt Cartier Wind Energy project in Quebec. The project and Phase I of the Gros-Morne wind farm are expected to be operational in December of 2011. Gros-Morne Phase II is expected to be operational in December of 2012. These are the fourth and fifth Quebec-based wind farms of the Cartier energy project which is 62% owned by TransCanada. All of the power produced at the Cartier wind farms is sold to Hydro-Quebec under a 20-year power purchase contract.

Moving to Bruce. Refurbishment work on Bruce power units -- A Units 1 and 2 reached a significant milestone in December of 2010, as Atomic Energy Canada wrapped up a substantial portion of its work on Unit 2, and is on schedule to complete work on you Unit 1 by the second quarter of 2011. Bruce expects to load fuel into Unit 2 in the second quarter of 2011, synchronize to the electric grid by the end of 2011, and begin operations in the first quarter of 2012. Unit 1 should see fuel loading start in the third quarter of 2011, first synchronization of the generator in the first quarter of 2012, and commercial operations are expected to begin in the third quarter of 2012. TransCanada's share of total capital cost is expected to be CAD2.4 billion.

So in conclusion, 2010 was a difficult but very successful year for our Company. Our core businesses produced solid financial and operating results in a challenging environment, and we made significant progress on our CAD20 billion capital program. We're about halfway through that program, with approximately CAD10 billion of our assets either having already started commercial operations or about to come into service in the coming months. All of these projects will contribute towards TransCanada's earnings and cash flows for many years to come. And we will operate these assets, as we do with all TransCanada infrastructure, safely and reliably and with great respect for the environment and the communities in which we operate.

I will now turn the call over to Don Marchand, who will provide additional details on our fourth quarter financial results. Don?

Thanks, Russ, and good afternoon, everyone.

As you know, earlier today we released our fourth quarter results and announced a 5% increase in the common share dividend. This was the 11th consecutive year the Board of Directors has raised the dividend.

Before I expand on the details of our fourth quarter, I would like to draw your attention to a few key themes. First, TransCanada's diverse set of high quality infrastructure assets contributed to higher comparable earnings cash flow quarter-over-quarter, even though a portion of our business continued to be impacted by lower power prices and natural gas storage spreads. However, TransCanada's low cost base load generation and unregulated storage capacity are well positioned to benefit as power prices and spreads recover.

Second, I'll reiterate Russ' comments earlier. We continue to advance our CAD20 billion capital program that will further contribute to earnings, cash flow and dividend growth in the future. About two-thirds, or CAD14 billion, is now invested in the program, and about CAD10 billion of these projects have either begun or about to commence operations. Phases I and II of Keystone, including the Cushing extension, the Halton Hills, Kibby Wind and Coolidge power generating stations, and the Bison, Groundbirch and Guadalajara natural pipelines are expected to generate significant EBITDA in 2011 as they enter full commercial service. And third, TransCanada's financial position and access to capital remains strong. We successfully funded our large construction program in 2010 through internally generated cash flow, and long-term capital at very attractive pricing.

Looking to 2011 and 2012, in addition to our growing, internally generated cash flow, we are well positioned to opportunistically fund the remainder of our capital program, which may include senior debt, drop downs to our sponsored MLP TC pipelines LP, portfolio management, the dividend reinvestment program, hybrid securities and/or preferred shares. I would now like to take the next 10 minutes to elaborate on these themes and our fourth quarter 2010 results.

Comparable earnings in the period were CAD384 million, or CAD0.55 per share, compared to CAD328 million, or CAD0.48 per share in 2009, an increase of 15% on a per share basis. A combination of earnings from newly commissioned assets and improvements in some of our existing core businesses contributed to the increase in fourth quarter, 2010. Specifically, the startup of Halton Hills and Kibby Wind Phase II, increased plant availability at Bruce A, a higher contribution from US Power, higher return on equity and a larger rate base for the Alberta System, lower Alaska pipeline project development costs, and lower net interest expense as a result of the capitalization of interest related to the Company's large capital growth program. These increases were, to some extent, offset by lower realized power prices for Bruce B and Western Power, and a reduction in unregulated natural gas storage revenues. Net income applicable to common shares in the fourth quarter was CAD269 million, or CAD0.39 per share, compared to CAD381 million, or CAD0.56 per share, for the same period in 2009. As you learned earlier, we recorded a one-time valuation provision in the fourth quarter against the MacKenzie gas project, which had the non-cash impact of reducing net income by CAD127 million, or CAD0.18 per share.

I will now briefly review the business segment results at the EBITDA level. Natural gas pipelines business generated comparable EBITDA of CAD737 million in the fourth quarter, compared to CAD745 million in the same period last year. A higher equity return on a larger investment base earned by the Alberta System was more than offset by reduced revenues for both the Alberta System and the Canadian main line. These reduced revenues were primarily due to lower financial charges and income taxes, which are recovered on a flow-through basis and have no impact on net income.

Moving to oil pipelines. As mentioned last quarter, EBITDA in the first phase of Keystone was to be capitalized until the project was operating at its Phase I design capacity of 435,000 barrels per day. This milestone was reached in late January and we began recording EBITDA on February 1, 2011. With the commencement of commercial operations of the Cushing extension, we also began recording EBITDA on this Phase, as well, in early February. With both Phases now in full service, Keystone will generate 11 months of EBITDA in 2011, based on long-term contracts of 530,000 barrels per day, plus any additional volumes received in the spot market.

Energy generated comparable EBITDA of CAD301 million in the fourth quarter, compared to CAD248 million for the same period last year. The CAD53 million increase resulted from a combination of factors. New earnings from Halton Hills in Ontario and the second phase of Kibby Wind in Maine, increased generation volumes and lower operating costs at Bruce A, as well as increased capacity revenues and higher realized prices and sales volumes in US Power. This was partially offset by lower realized power prices at Bruce B and Western Power, and reduced revenues from our Alberta based natural gas storage. In early 2011, the operator of the Sundance A Power Plant declared force majeure on Units 1 and 2, effective mid-December 2010, and on February 8, 2011 notified TransCanada the units could not be economically returned to service. To date, TransCanada has received insufficient information to determine whether there is support for either claim, and recorded revenues in December 2010 under the Power Purchase Arrangement as though this event was a normal plant outage.

Now turning to the income statement items below EBIT on slide 25. Interest expense in the fourth quarter was CAD173 million, compared to CAD184 million last year. The CAD11 million decrease was primarily due to higher capitalized interest, related to the advancement of our capital growth program in 2010, and a reduction in translated US dollar denominated interest expense resulting from a weaker US dollar. This was partially offset by incremental interest expense on new debt issues of US CAD1.25 billion, and US CAD1 billion in June and September 2010, respectively. In the fourth quarter, CAD150 million of interest was capitalized to assets under construction, compared to CAD128 million for the same period in 2009. As new projects are placed into service, capitalized interest will begin to decrease, somewhat offsetting the impact of higher EBITDA associated with these new assets. Interest income and other of CAD61 million in the fourth quarter of 2010 increased by CAD39 million compared to the same period last year. The increase reflects higher gains realized in 2010 compared to 2009, from derivatives used to manage exposure to foreign exchange fluctuations on US dollar income. Income taxes were CAD94 million in fourth quarter 2010, CAD27 million higher than fourth quarter 2009, primarily due to tax adjustments in 2009, including those arising from a reduction in tax rates in Ontario. Preferred share dividends totaled CAD14 million in fourth quarter 2010, reflecting the cost of issuing CAD350 million of cumulative redeemable first preferred shares in each of March and June of 2010, and CAD550 million worth in September 2009.

Moving on to cash flow and capital expenditures on slide 26. Cash generation remains strong. Funds generated from operations for fourth quarter 2010 was CAD812 million. For the full year, funds generated increased by CAD250 million, to over CAD3.3 billion. The increase was mainly due to higher earnings and the income tax benefit generated from bonus depreciation for US income tax purposes on Phase I of Keystone which was placed in service on June 30, 2010. Capital expenditures were CAD1.5 billion in the fourth quarter, principally related to the construction of the Keystone Cushing extension, the Groundbirch, Guadalajara and Bison natural gas pipelines, the Bruce A restart and the Coolidge power plants. For the year, we spent CAD5 billion to further advance our CAD20 billion capital program, bringing the total to date to approximately CAD14 billion.

Now, looking at slide 27. Our liquidity and access to capital remains strong. At the end of the year, our consolidated balance sheet consisted of 42% common equity, 4% preferred shares, 2% junior subordinated notes, and 52% debt, net of cash. At December 31, we had CAD800 million of cash on hand, along with CAD3.8 billion of available and undrawn revolving bank lines. Our two commercial paper programs remain well supported by the market and continue to provide a flexible and attractive source of short-term funds. Our dividend reinvestment program participation was 34% in the most recent quarter, generating about CAD100 million of common equity to underpin our continued significant growth. With the dividend announcement today, we are returning the discount on common shares issued under the DRIP to 2%, which is equivalent to the discount in 2008 prior to the financial crisis. This is effective for common share dividends payable on April 29, 2011 and for preferred share dividends payable on March 31, 2011.

Next, just a quick update on TransCanada's adoption of US GAAP versus International Financial Reporting Standards, or IFRS. As I mentioned last quarter, given the uncertainty around rate regulated accounting under IFRS, and the one year deferral available to the Company, TransCanada will continue preparing its consolidated financial statements in accordance with existing Canadian GAAP for 2011. To appropriately reflect the economic impact of our regulators' decisions regarding the Company's revenues and tolls, effective 2012 TransCanada expects to adopt US GAAP as an alternative to IFRS. And finally, we expect to file our 2010 annual report to shareholders tomorrow, which contains the consolidated financial statements and accompanying notes, as well as the related management's discussion and analysis.

In closing, TransCanada produced another solid quarter with comparable earnings 15% higher than 2009. Our unprecedented CAD20 billion capital program is now two-thirds complete, having invested nearly CAD14 billion to date, with CAD10 billion of these projects contributing to earnings and cash flow in 2011. And we are well positioned to finance the remainder of our capital program through 2011 and 2012.

That's the end of my prepared remarks, and I'll now turn the call back to David for the Q&A.

Thanks, Don.

Just a reminder, before I turn it over to the conference coordinator, we will take questions from the financial community first, and once we've completed that we'll then turn it over to the media. With that, I'll turn the call back to the conference coordinator for your questions.

Thank you. We will now take questions from the telephone lines. (Operator Instructions).

The first question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thank you.

I have a question on Keystone, the cost increase in US dollars. Very helpful to know that a third of that increase can be attributed to the move in the Canadian dollar versus the US dollar. Can you give us a breakdown as to how much of the balance would be from your Gulf Coast project versus the other initial phases of Keystone?

Sure, if you think --Linda, it's Alex.

If you think about that total CAD1 billion, and say a third is just translation of the Canadian dollar assets, we're probably about 35% to 40% would be capital increases along base Keystone, just related to the very hot market we experienced, but I think more importantly, the incredibly bad summer weather we experienced which had some impact, and then the balance would be impact on the Gulf Coast, the XL project, largely driven by evolving regulatory requirements and the timing that we've experienced.

Okay.

And can you confirm, Alex, that for the base Keystone it's 50/50 borne by shippers versus TransCanada, and in US Gulf Coast it's 75% being absorbed by the shippers?

That's correct, Linda.

Okay. That's very helpful.

And then I noticed as well on the timing, I think Russ was talking about a 2013 in-service date. Previously, the expectation had been a Q1 in-service date. Is that timing potentially shifting, and how much of that schedule can be kind of crashed and accelerated, if shippers want to pay more?

That's an ongoing discussion that we have with our shippers. We're quite comfortable that, even given the delays we've experienced, that we think we can be in service in Q2, 2013. And if there was a desire to be quicker, that could probably occur. But as you can imagine, with these kind of things, it's a bit of a -- what you gain in time you may give up in capital, but we're certainly capable of being in service by no later than Q2, 2013.

Great. That's helpful.

Now, for some of your smaller projects, I noticed a bit of a creep-up in CapEx as well. Would the CAD30 million increase in Bison and CAD40 million increase in Guadalajara be attributed to a strengthening Canadian versus US dollar, or is there something else going on?

Those would be similar issues to the ones that Alex mentioned on Keystone, is that's an ongoing and increasing regulatory requirements and bad weather as we were closing those projects.

In Mexico as well, bad weather?

I guess Mexico hasn't been -- they've been different weather, we've had some wet things, but I'd say Mexico has been more related to land acquisition and some changes in scope.

Okay. That's great. Thank you very much.

Thanks, Linda.

Thank you.

The next question is from [Chas Reese] from UBS. Please go ahead.

Hello, guys.

Regarding the Sundance APPA termination notice, was wondering what the hurdles are that a Company must meet before it successfully terminates APPA.

It's Alex.

I guess, if you take a look at the PPA, it basically states that if a unit is damaged or destroyed to the extent that it is incapable of generating electricity and it is then determined that the plant cannot economically be repaired, replaced, rebuilt or restored, and then it says taking into account both the owner's and the buyer's expected future income from the repaired unit and the costs thereof, then the owner must provide written contract -- written notice to the buyer and the balancing pool, and both the balancing pool and the buyer have the right to dispute the owner's determination. And then on top of that, there's an overriding obligation within the power purchase agreement for the seller to maintain the equipment in good order. So those are sort of the hurdles that need to be met. We got our notice on February 8, as I think Russ mentioned, and we're now -- we have a 10-day period in which to choose to dispute that notice.

And if you do indeed dispute it, what are the possible resolutions, if there are objections on your part or on the balancing pool's part?

Well, you know, I think if we object to it, which I would guess is highly probable, this process would go into an arbitration proceeding. Some of the time lines are set out in the power purchase agreements, but at that time the ultimate schedule, I guess, would be up to the arbitrators.

Okay.

And just lastly, we've seen a lot of outages at your PPA plants in Q1 and, given that you've sold four at a decent amount of power in Western Canada, do you see any issues with your hedge obligations or are you having to buy anything in the spot market in Q1 or going forward?

No, you might have heard me say this in previous quarters, but given the very low prevailing power prices up for a lot of 2010, we had made a conscious decision to be significantly longer in the Western power portfolio than we otherwise would. If you assume Sundance A comes back in 2011, we're probably 50%, 51% unhedged. And if you assume it doesn't come back, we're 64% hedged, and significantly less hedged in 2012 and 2013.

Okay. Great. Thanks, Alex.

Okay.

Thank you.

The next question is from Carl Kirst from BMO Capital Markets. Please go ahead.

Thank you. Good afternoon, everybody. Thanks for the time.

Just a couple of broader timing questions, maybe starting first with Sundance and, you know, Alex, you just mentioned I guess the time frame is a little bit up to the arbitrator. Correct me if I'm wrong, but is the force majeure that was declared last summer, has that been resolved or is that still ongoing, and so is this something we might be taking nine months or even longer perhaps, to get resolved?

You're talking about the force majeure claim that was made on Sundance, on the Sundance B unit?

Correct.

Yes. So that one, we took exception to that claim of force majeure. We really take the view that mechanical problems occur at plants every year and they're normally treated as normal plant outages. So when we look at what's gone on there, with what we know, and it is somewhat limited, we take the position that, that does not fall within the definition of force majeure. So we have accordingly taken Trans Delta to arbitration on that , and so it could be some time before we have an outcome.

Now, on Sundance B, because they have brought the unit back and it is generally operating at or above its target availability, it isn't -- we're really just talking about a historical amount of money for 2010, and we're not seeing any -- we're not seeing those costs continue to accrue.

I guess where I was going to with the question is that, is the potential arbitration time line for Sundance A something that could extend as long as we've seen for --

Yes.

The Sundance B?

Yes, it quite possibly could.

As I said, there are some -- there are time limits within the power purchase agreements as to, sort of the process of parties appointing arbitrators, et cetera, et cetera, but at the end of the day, it is a quasi-litigation process and it does take a bit of time to get through.

I appreciate that.

And then one other timing question if I could, really back to Linda's question on Keystone. And partly, I guess, I just wanted to clarify, Russ, what you had said as far as the EIS and the Presidential permit in mid- to late year, and I wasn't sure if you were setting those up sequentially in as much as the EIS in mid-year and Presidential permit then, obviously, by the end of the year, or if we might still see the EIS any day now. And I guess I'm just trying to figure out, is it that we don't know, or have you gotten some indication from State Department or what have you, other channels, that suggests that the EIS really isn't going to come before the summer?

It's not foreshadowing any of those. We haven't got any new information from the last time we updated you.

I guess what we know, at this point in time, is that the Department of State continues to process the comments that it received. We would expect that they would issue a final Environmental Impact Statement at -- in the, hopefully, coming weeks or months. What we do know is that once they do that, there's a 90-day public interest determination period, and then there's some comments to follow. So you're looking sort of from that date, a plus three to four month kind of time frame. So that's kind of what gets you. If we saw a final Environmental Impact Statement in the next month or two, that would get you from there another four months, so like sort of six months from today lands you in that kind of time frame that I mentioned in my opening remarks. But we don't have any better information today than that. We're still thinking that, that final Environmental Impact Statement is imminent. They may go down a process of asking for additional information. We've mentioned before that, that process could tack on additional time frame to the process. But at this point in time, we don't have any information as to what direction they might be going on that front.

Great. Appreciate the clarification. Thanks, guys.

Thanks, Carl.

Thank you.

The next question is from Ted Durbin from Goldman Sachs. Please go ahead.

Good afternoon.

I just wanted to ask about the -- thinking about the Cushing, the Gulf Coast portion of XL. If you look at the WTI to brown or LOS spreads, obviously there's a lot of demand to move oil out of Cushing and the Gulf Coast. Would you consider decoupling this project from the larger XL, to help sort of alleviate that Cushing bottleneck? But then, maybe still maintain the flexibility to run the heavier crudes with your engineering, if and when you get the Presidential permit.

Yes, I -- we've -- that's obviously something we would consider right now. We have put -- we've put all of that together in the XL permit, and we are very confident we're going to receive that permit. I guess in the incredibly unlikely event that we didn't receive the Presidential permit, we would consider decoupling it. But the other thing I would say is, under any scenario, we do have the option, after receiving the Presidential permit, to get right to work. That portion of the pipeline we can construct in all seasons. So we would likely go ahead. We would likely go ahead with that, as soon as we received the permit, and that would probably see us have the ability to get it in service earlier.

I think that -- I'd just add to what Alex said, is that really, having the Keystone XL project as being the cornerstone for then to build other things off of it is what sort of drives the positive economics for a project like that. Recognize that the spread between, say, WTI and LOS is pretty wide right now, but that is a transitory number and that we need to be able to provide that service on an intermittent basis, you know, coming up with sort of long-term contractual arrangements that would underpin the capital of a 36-inch pipeline from Cushing to the Gulf Coast is very difficult stand alone. You really do need to combine it with some other project, which our Keystone XL project, you're starting to see the benefits of being able to attach other things to it, like the Bakken Marketlink project, for example.

Those standalone can't exist, but as part of Keystone they become very economic, and obviously offer those US producers an outlet to move their crude oil to market as well. So, I think that just adds to the necessity of getting this project built and moving forward.

That's helpful. Thanks.

And then if I could just ask a little about financing. How are you thinking about your financing needs and the change, maybe now that we have the delay in XL, but the higher costs, how does that interplay work and again, thinking about the dividend increase you did today, maybe just talk a little bit about your financing needs.

It's Don here.

From a finance perspective, with Keystone, the spend profile's moved out slightly, so we're not entirely sure exactly which time bucket it will fall into exactly, whether it's 2011, 2012, 2013. What we're expecting this year is CapEx, something in the CAD3.5 billion range, of which CAD1.4 billion is Keystone related. When you factor in maturities, dividends, funds from operations, our requirements are something just short of CAD2 billion this year, which is down from what we showed you at Investor Day. We entered the year with CAD800 million of cash on hand. We have the DRIP running. So our needs are quite modest for this year. And then our capital markets requirements going forward will largely be driven by what time bucket, again, those Keystone expenditures ultimately fall into.

Okay. Thanks. Those are my questions.

Thank you.

The next question is from Juan Plessis from Canaccord Genuity. Please go ahead.

Thank you very much.

With respect to the New York power market, I'm just wondering if you could comment on the capacity prices you're seeing now in that market, and how you see that market shaping up for 2011 and how that would compare to 2010.

Sure.

Juan, what I would say right now, winter 2010, 2011 is probably about the same as last year, around CAD4.00 a kilowatt month. We are -- you probably have seen that the FERC just recently came out with a new order on the demand curve reset process, and I think certainly our perspective at TransCanada is that over the mid- to long term, that will be a very positive -- it will have a very positive impact on capacity prices in the market. I think it probably -- one of the quirks of that FERC order is that they gave a period of months for the New York ISO to come back with a compliance order incorporating the decision that FERC made, and so there is a possibility that, although I think it clearly is going to have an upward impact on the demand curve, it may be delayed beyond the summer, in which case we would probably still be looking at summer demand prices in the -- sort of the CAD10.00 to CAD14.00 a kilowatt month.

Okay. Great. Thank you.

And just wondering now are you now fully through the financial impact from the unit 30 outage at Ravenswood?

Yes, largely. If I recall, I think we're 100% through it in around May, so the summer period should be on our full claim capacity.

Okay. Great. Thank you very much.

Thanks, Juan.

Thank you.

The next question is from Matthew Akman from Macquarie. Please go ahead.

Thanks a lot, guys.

A couple questions about your plans for spending on northern gas pipelines in light of, I guess, some of the delays up there. Maybe just start with MacKenzie, the disclosure says that now any amounts, I guess, spent there will be expensed. Do you plan on spending much money up there?

No. There isn't, at this point in time, much money to spend. The only activity that will be going on is discussions with the Federal Government and our partners in the project, the producers in the Aboriginal pipeline group, and those are the only sort of minimal expenditures that we have, which are just a couple of bodies. So there's really no material expenses for this.

Okay. Thanks for that.

And then in Alaska, I know right now that there's a CAD500 million state reimbursement plan that you guys won, but there's talk among some of the legislators of possibly rolling that back under AGI. And I'm just wondering, if that were to happen, would you slow or cease expenditures on Alaska as well?

That would be the case. Right now we have an agreement, I guess, under our license, under [Agea]. The Alaskan government will fund 90% of our expenditures up to their cap of CAD500 million. We expect that, that will continue. But in order to change that funding, if you will, either party has to deem the project to be uneconomic and we have to negotiate from there. So we need legislative change for them to not continue to fund, which are the proposals that you referred to, but those fundamentally changed the agreement that we have under Agea. And I would suspect that under that scenario we wouldn't continue to spend the funds that we're spending in pursuit of our FERC certification.

Okay. Thanks for that.

And then one last cleanup question. Don, I think you said your CapEx plans for this year have you spending about CAD3 billion. Is that correct?

About CAD3.5 billion.

About CAD3.5 billion, down from CAD5 billion at Investor Day?

Yes, five-ish was the original figure.

And that's all Keystone, right?

Yes.

Okay. Thanks a lot, guys. Those are my questions.

Thank you.

Thank you.

The next question is from Pierre Lacroix from Desjardins Securities. Please go ahead.

Yes. Thank you very much.

My first question is on the IRR on the Keystone. You mentioned that the 7% to 9% is basically unchanged following the capital cost increase. Just wanted to -- I was curious to know ,what was the positive impact that the back-end and the Cushing Marketlink had on the IRR of the Keystone, if any, and maybe you can give some perspective on this. Thank you.

Thanks, it's Alex.

Because of our cost sharing, there really was very modest downward revision to our IRR with respect to that capital. On the other side, there was pretty significant positives associated with Bakken and Cushing, keeping us within that 7% to 9% range that Russ talked about. But net-net, if you put them together, the overall impact was positive.

Okay. Good. Thank you.

And just wanted also to have some kind of an update on the negotiation related to the Oakville PPA, anything new there that you can share with us?

You know, we have continued our discussions with the Ontario Power Authority, and I think it would be fair to say we are the largest investor in the Ontario power market, so we've had a long and, I think, mutually beneficial relationship with the OPA. So we are working with them. We are confident that we are going to recover our costs of the plant and our economic value associated with that PPA, and those discussions are ongoing and intensive, I think is what I would say right now.

Okay.

And one last, on Marcellus you signed basically something like 225 million cubic feet there. You mentioned, in the third quarter, that you had interests around 1 billion cubic feet, so can you give us some perspective on what is the upside there, what kind of capital costs we could expect for deploying this new project?

So if I -- just to rephrase the question, is your question we had originally said there was about 1 billion cubic feet a day of interest which has translated into about 250 million cubic feet a day of contracts from the Marcellus, and you're wondering what the capital cost associated with that project might be. Is that correct? That's your question?

This is exactly it.

So as you know, in all open seasons, you always get more interest than actually turns out at the end of the day. I think that in the long haul, Marcellus will continue to grow and we will see larger volumes, but at this point in time the volume that was willing to contract on a term basis to underpin capital was about 250 million cubic feet a day. We're still working out exactly what modifications to our system will be required to move that kind of volume. I think ultimately to move the -- a number that looks like between 250 million cubic feet a day and 1 billion cubic feet a day, we're probably looking at a number that's CAD200 million to CAD300 million kind of range. It's not significant. But what we would look to do in the interim, as volumes grow, is to look at other ways of operating our system, back hauls and those kinds of things, to make those movements occur. And then as volumes grow, we would look to spend the capital.

So we're analyzing that right now, as to what the impact will be, and that would sort of be the max range for capital I would see at this point in time, but we haven't put a peg in it yet.

Okay. Thank you very much. I appreciate it.

Thank you.

The next question is from Andrew Kuske from Credit Suisse. Please go ahead.

Thank you. Good afternoon.

Not sure if this question is for Russ or for Greg, but it just relation to the Canadian mainline. Is your view that essentially the falling of the interim toll application and the rejection of the settlement that you had is really the NAB opening up the door for they want to see a broader application on really the underlying economics of the line and how a return framework should be structured.

I would say that the answer to that is no. I don't think there's any sort of hidden message in the NAB's denial of our application. I think what they said was there is pretty significant changes that were requested and that their opposition to those changes and that a sort of a full hearing process was required before they could adjudicate on those significant changes. We felt, on the surface there was sufficient benefits for them to make that decision, and little down side risk in making that decision, because tolls would have otherwise been less than they would have been under the 2007 to 2011 settlement, but nonetheless, they chose to rule that they didn't have sufficient information and that they needed to not allow that on an interim basis. But that doesn't mean that they made any statement with respect to the validity of what we were asking to do. I guess the way I would characterize it is they said that they needed to see the full evidence and the arguments of both sides pro and con as to the benefits and detriments of it, before they made a decision on such significant changes.

That said, we continue our discussions with both the producers and the market to try to find accommodation where we can, and I remain optimistic that this philosophy, if you will, moves us in the direction that's beneficial for everybody, and that there's a win-win to be had here and we continue to press that direction. But as we've said, if we can't come to that accommodation, we will file something similar to what we proposed, on a more contested basis.

And then in that context, the tolls for some of the short haul, for the gas LDCs in Ontario, they went up quite dramatically under the existing regulatory construct. So it would be safe to say, or you would be hopeful at least from an LDC perspective, that they would look for a more of a negotiated settlement.

I believe that's correct. They had some fundamental concerns with what we had proposed originally, and we'll work to find an accommodation with the LDCs, and at the same time remain or keep intact the support that we have from the producing side of the pipeline. We did apply, as you know, for a new interim toll and we would hope that the National Energy Board would rule on that interim toll by March 1. And what I'd say, I guess there was some opposition to it, but significantly less opposition than there was to our original filing of our interim toll.

That's helpful.

And then if I may, just a question for Alex. And it's in relation to the Alberta power market, and really since the force majeure claim from Trans Delta at Sun One and Sun Two, we've seen a lot of increased volatility within the power pricing of the market. Just sort of what are your thoughts on the price action in the last two months, and how you think about that on a go forward basis in the Alberta power market?

I think it's kind of interesting. It's been my view for a while that forward market prices in Alberta were not truly reflecting sort of the supply demand realities in Alberta. And as I said, as a result, we certainly weren't that anxious to sell a lot of power forward. And I think Trans Delta's problem with Sundance A just really sort of brings home the issue that the Alberta power market was sort of one major unit away from being a very tight market. And you know, we've seen power prices go up over the next sort of two or three years anywhere from sort of CAD10.00 to CAD20.00 a megawatt hour ,and I think it just sort of does bring home this issue that this is -- we have strong demand growth. We don't have a lot of projects -- or new projects in the works. So I think it certainly bodes for some higher prices for a while in the Alberta power market.

That's very helpful. Thank you.

Thanks, Andrew.

Thank you.

The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.

Good afternoon.

If I can just ask first about funding. You have a few things that are going on that are putting some pressure on the credit metrics, whether that's potential mainline settlements, some of the cash flow concessions you are making, the MacKenzie write-down or Sundance. But then you've also talked about pushing out the CapEx. So when you're looking at the various forms of capital, I know, Don, you did not mention common equity. What's your confidence level kind of with that for 2011, and then given that you've just pushed CapEx into 2012, any color as to you how you feel about common equity in 2012 as well?

We don't see a need for common equity beyond the DRIP program, given our current construction program, regardless of what time buckets Keystone ultimately falls into. In terms of other subordinated capital, the markets are all in good shape, in terms of looking at things like drop downs into the LP, the preferred share market here in Canada remains very robust, and the hybrid market in the US, the pricing has come in quite substantially there. So we have a lot of options available to us, in terms of subordinated capital. But the longer this capital program gets pushed out, the more we can pay for it out of internally generated cash flow.

Okay.

And then, just on the Keystone XL timing, there had been some headlines about the potential for a modified EIS, the timing that you set out I assume that, that, based on what you said, that does not kind of take into account if there was a modified EIS and if we saw one that would push the timing out even further?

I think the range that we gave gives us a cushion under our sort of reasonably expected outcomes for where we may get to on that regulatory process. I think, as Russ said, if we move quickly to the final EIS, then we're sort of -- we can still be towards the summer, and if there is a more modified or a little more extensive process, then that kind of would take us towards the end -- more towards the ends of the year.

Thanks, Alex.

And just the last question, Don, you'd mentioned on Sun One and Two that you'd recorded revenues in December as if it was a normal outage. Is that the same treatment you're going to be taking into 2011 as well?

We'll have to look at the facts as they develop here, in terms of the revenue recognition rules and how this thing plays out. So we haven't made any firm decisions on how that will be treated here, going forward into 2011.

Okay. That's great. Thanks very much.

Thanks, Robert.

Thank you.

The next question is from Faisal Khan from Citigroup. Please go ahead.

Thanks. Good afternoon.

With the outage at Sundance, how will you be supplying your physical hedges that you guys have put in place in the Western market?

Faisal, it's Alex.

I mentioned earlier that we are even with -- even with that outcome for Sundance A, and it being out, we are still structurally very significantly long in the market. We're a few hundred mega watts less long than we were, but we have more than enough physical power to supply the hedges that we have in place right now.

Okay. Great.

Then just last question, on the below the line on the tax rate, excluding the one time items, what was the tax rate for the quarter, and what do you guys expect it to be kind of going forward for the year?

It's Don here.

The tax rate is in the low 20%s. Part of the low rate is driven by the regulatory business, which is -- the taxes there are paid on a flow-through basis, what we pay is what we collect. So there is some noise around that. But we would expect something in the low 20%s to persist for some time here, with the skew more toward the deferred taxes than paying current taxes, given the tax shelters we've got generated from all the capital spending right now.

Okay. Got you. Thanks.

Thank you. (Operator Instructions)

The next question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Thank you. This is just a follow-up tax question for Don.

It's good to know that you'll be likely deferring taxes for some time. In 2010, that future income tax line item in your cash flow from operations was CAD521 million. How -- what would be the kind of run rate over the next couple of years, and how might that trend over time?

In terms of the overall rate, as I just mentioned, probably in that low 20%s. In terms of the current versus deferred split, it would be some element of current taxes, I don't think I have in front of me here a run rate on what that would look like in 2012 or 2013, other than to broadly say that , again, with the amount of shelter that we have, we would expect to be paying lower levels of current tax for the next couple of years, anyway.

Yes, and Linda, it's Glenn. The difference between the two years between 2009 and 2010 is primarily due to just over CAD200 million of tax recoveries related to our Keystone bonus depreciation, so that's a bit of an anomaly in there. We hope to see some of that going forward. But that makes up the difference.

But right now, we don't have a split between current and deferred.

Okay. But in 2013, you might have a similar bonus if XL comes into service?

Yes. The bonus depreciation rules were extended for 2011, just before year end, so we would expect Bison and the Cushing extension to also qualify, going forward. So again, our tax loss carry-forwards are substantial for the next few years.

Okay. Great. Thank you.

Thank you.

Thank you. This concludes today's question-and-answer session for analysts. We'll now take questions from the media. (Operator Instructions).

First question from the media is from Tracy Sutherland from Argus. Please go ahead.

Hello. Thanks for your time. This is for Russ, if you wouldn't mind.

You were talking before in relation to the Keystone pipeline. I just wanted to go back to the US Department of State consideration of the environmental impact study. You mentioned that you were expecting some formal final EIS imminently, but the Department isn't confirming at this stage whether it's going to release a final EIS or a supplemental EIS, which could obviously involve more additional public comment and potentially even further study into environmental impacts. Do you think there are any grounds for issuing a supplemental EIS ruling?

Our view is that it's been a comprehensive process. We made our application in September of 2008. The process ran for approximately 18 months to 20 months. They came to the conclusion it had limited environmental impacts. Certain issues have been raised subsequent to that issuance of that draft Environmental Impact Statement in April. In our view, I think that we are capable of answering all of the issues, the safety issues that were raised, the pipeline quality issues that were raised, through discussions with the Department of Transport and FIMSA. They're well equipped to deal with those issues. The territorial issues in the Canadian oil-sands, I think those are outside of the scope of the project. We recognize why they've been raised, but I think in prior permitting processes for both ourselves on the base Keystone and the Clipper project, all of those issues were raised and dealt with through those processes.

So there hasn't been any new information that's been raised. So our view is there is sufficient grounds to move directly to a final Environmental Impact Statement and the public interest review period. Obviously, the Department of State needs to run their own process. We respect that, and they'll determine what the next step in the process is.

Okay.

And just to clarify, you said you expected the pipeline to be operational in 2013?

Correct.

Okay.

And just one further question, if I may. Just in relation to Nebraska, the legislators there are considering passing some new regulations which would refer to the routing and the security of future oil pipelines running through that state. Should the Keystone pipeline be subject to these new rules, if they passed?

Our view would be the routing was part of the environmental review process that started in 2008, as I said. The process has been rigorous. We have chosen a route that has the least environmental impact, and that all of those issues have been dealt with at the federal level. So I guess, our view would be is, no, we should not be subject to an additional review period once the federal review process has taken place.

So you shouldn't be subject to any state laws in Nebraska that related to these sort of things?

I think that's a pretty broad question. With respect to the routing that you asked me the question on, I don't think that we should be subjected to any additional routing analysis within the state of Nebraska.

What about any additional laws that related to security, additional security?

Again, that's a very broad question. It's a very technical question and there are certain rules that we comply with on both the state level and the federal level, and I couldn't answer the question on such a general base basis.

Okay. Thanks very much.

Thank you.

The next question is from Edward Welch from Dow Jones. Please go ahead.

Hello. Thanks for taking my question.

We saw the Cushing Phase Two expansion go -- begin delivering this month, as well as, the same month we also saw a record level of oil supplies at that key supply depot for the US. I'm just wondering basically, is it a possibility that the working storage at Cushing will basically fill up or will become constrained in some way? If that does happen, what does that mean for TransCanada and for the shippers on the Keystone line?

We have sufficient storage capacity to operate our pipeline system, so I don't have any worries in that regard. We have the ability to store a product for our shippers, to move it to their specific refineries.

I can't answer the more global question on whether or not we're going to fill up the storage capacity at Cushing, but what I can tell you is that it is one of the largest storage hubs on earth, and there is millions of barrels of capacity storage, and I haven't heard anybody suggest that that's an issue at this point in time. But as I said, I can only speak to the operations of our system, and I believe that we have either our own proprietary or contracted storage that's sufficient to manage the needs of our customers.

So even if it is an unlikely possibility that, that does happen, then your suppliers wouldn't have to shut in production rates and like that, they would -- TransCanada would be able to store that for them until the supply constraints are eased, to sum up?

There's a combination of storage that we hold for our shippers and storage that they have on their own. We haven't been given any indication that there's a storage issue or constraint issue at this point in time, so I wouldn't expect any of that production to be shut in.

But I think, again, to the earlier caller's question on Keystone XL, the sooner we get on with approving that pipeline and getting it under construction, the sooner we can alleviate that bottleneck and move that additional crude oil supply to the Gulf Coast.

Okay. Thanks a lot.

Thank you.

The next question is from Scott Haggett from Reuters. Please go ahead.

Hello, Russ.

You're saying the line -- XL can be in service in Q2, 2013. How firm is that estimate, and what would cause that to waiver on further towards the second half of that year?

I think the biggest issue right now, Scott, is the permitting process and the delays in the permitting process. Based on the timing estimates for obtaining the Presidential permit that we outlined here today, which would be somewhere between mid- to late 2011, we believe that we can still hit that end of Q1, sort of Q2-ish kind of time frame for construction.

But obviously, further delays in the permitting process could result in further delays in putting the project in service and, again, as I've just pointed out, the longer that gets delayed, the longer that the benefits of being able to move additional crude to the Gulf Coast, move Bakken crude, move Canadian crude and get people back to work, the longer those things get delayed as well.

Thank you very much.

Thank you.

The next question is from Justin Amoa from Argus Media. Please go ahead.

Hello. Thanks for taking my call.

As you may know, there's been a -- quite a backlog of crude that's built in Western Canada as a result of pipeline disruptions on your competitor's pipeline. I'm wondering whether TransCanada has been able to pick up incremental spot shipments on the Keystone system as a result of those pipeline disruptions on your competitor's system.

We've done everything we can to help the industry alleviate that bottleneck, but as you know we've been in the commissioning phase of our pipeline system for the last six months or so and we've just begun ramping up to the higher capacity levels. I believe that we're running now somewhere between 450,000 and 500,000 barrels a day, and I believe that has had a positive impact on alleviating that bottleneck.

Okay. Thank you.

And of that 400,000 to 500,000 barrels per day throughput, how much of that is being directed to Cushing and how much is being directed to the Wood River Patoka market?

I think to this point, more so to the Wood River Patoka, but I don't have those figures right in front of me right now.

Is there a just an estimate or a percentage that you might be able to provide or -- ?

Right now, Justin, we're just commissioning, actually just finished commissioning the Cushing leg, so we filled it up with oil and we're just starting deliveries.

The original contractual split between the two directions is we have about 160,000 barrels a day of contract at Cushing and the balance of the 530,000 barrels a day of contract is at Wood River and Patoka. So that would give you sort of a feel as to what the split should be over the longer term. So that I believe, you can do the math but it's -- that's the split, 155,000 or so to Cushing, and the balance of the 530,000 of contracts that would go to Patoka and Wood River.

Thank you.

Thank you. (Operator Instructions)

The next question is from Joshua Sterns from Plant. Please did ahead.

Hello. This is for Russ or Greg.

One of the main concerns is going -- speaking to the Canadian mainline, and one of the main concerns that has been brought up several times by the various shippers in dispute, both on the pro and against side of the interim toll agreements, is the long-term economic life span and competitiveness of the mainline. I think Manitoba Hydra actually described it as a death spiral in their reply letter to the revised interim toll application. Has TransCanada made any sort of study as to cash flow expectations without the mainline?

Again, we believe that the mainline is very, very important North American infrastructure. Today it's moving about 5 billion cubic feet a day, which is bigger than any pipeline -- single pipeline in North America, so it is needed and useful. It supplies customers that have no other way of getting their gas. The system is economic. We need to reallocate some of the costs in our system to match the changes in market supply that have taken place over the last couple years.

But our view would be Western Canada is still a significant supplier of natural gas to the North American marketplace. It is still one of, if not the largest supply location at about 16 Bcf a day. We expect that, that production will continue to be there and will grow, as Northeast BC shale supply grows in the future. As we've said, we've contracted for an additional 2 billion cubic feet a day that will come on between 2011 and 2014. So the Canadian mainline will continue to be a very, very important part of the North American gas infrastructure for a long, long time to come, and we need to find a tolling structure that works in the new market paradigm, supply being in different locations than it's been, historically.

Okay. Thank you.

Thank you. One moment, please.

Thank you. So this concludes today's question-and-answer session. I would like to turn the meeting back over to Mr. Moneta.

Great. Thanks very much, and thanks to all of you for expressing your interest in TransCanada. We appreciate your time this afternoon and look forward to talking to you again soon.

Thanks. Good-bye for now.

Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.