TC Energy Corp (TRP) 2012 Q2 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2012 second-quarter results conference call.

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

Thanks very much and good morning, everyone. I'd like to welcome you to TransCanada's 2012 second-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 & Oil Pipelines, Greg Lohnes, President Natural Gas Pipelines, and Glen Menuz, our Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other Company developments. Please note that a slide presentation will accompany their remarks and 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 will 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 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 the 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 the US Securities Exchange Commission. And finally, I'd 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 and certain other comparable 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 TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations. With that, I'll now turn the call over to Russ.

Thank you, David, and good morning, everyone, and thank you for joining us today. Last quarter I spoke about delivering critical energy infrastructure and this continuing to be a priority for our Company, and I can tell you that we remain focused on advancing that priority and I'll talk about some very positive news related to our Gulf Coast Project in just a minute. But I'd remind you that all of our projects, currently underway, are either regulated or they're underpinned by long-term contracts which gives us great confidence that they will generate stable sustained earnings and cash flow growth for our shareholders for years to come.

In the second quarter, our businesses for the most part continued to perform very well. However, a portion of our business that is directly impacted by power prices and gas prices was adversely impacted by weak demand and soft prices. That said, I remain very confident that TransCanada's well positioned to grow earnings, cash flow and dividends as we complete our current capital program, secure attractive new opportunities and benefit from the cyclical recovery in natural gas and power prices.

Remain on target to complete CAD13 billion in capital projects between now and 2015, including the restart of two nuclear reactors at Bruce Power. Our Gulf Coast Project that will deliver US and Canadian oil to Texas refiners, the Keystone XL project, which will bring US Bakken and Canadian oil sands crude to market, the Tamazunchale Extension, our Ontario solar project and many further expansions to our Alberta System.

Turning to the financial highlights for the quarter. Comparable earnings were CAD300 million or CAD0.43 a share, excluding an after tax charge of CAD22 million related to the Sundance A arbitration decision announced this week. Comparable earnings were CAD322 million, or CAD0.46 per share. Comparable EBITDA was CAD1 billion. And funds generated from operations were CAD729 million. Today the Board of Directors declared a quarterly dividend of CAD0.44 per common share for the quarter ending September 30, 2012. Don Marchand, our CFO, will offer more details on our financial results in just a couple moments.

But before he does, I will walk you through some of the very important advancements in our three core businesses over the past quarter. On the Gulf Coast Project, we've now achieved a very important milestone as we advance our Gulf Coast Project that will deliver US and Canadian oil to Texas refiners. I'm pleased to confirm that we did receive a final of the three necessary permits needed from the US Army Corps of Engineers. This will allow us to maintain our previously stated schedule of beginning construction on the pipeline this summer and an in-service date of mid to late 2013.

At a cost of $2.3 billion, this project will employ approximately 4,000 American workers during the construction project and many more jobs that are created at US companies, manufacturing all the materials needed to build such a large piece of energy infrastructure. Included in the cost of $2.3 billion is the $300 million, 76-kilometer Houston lateral pipeline that will transport oil from Cushing, Oklahoma to Houston refineries as well.

US crude oil production has been growing significantly in states such as Oklahoma, Texas, North Dakota and Montana, and producers do not have access to enough pipeline capacity today to move that production to the large refining market on the US Gulf Coast. The Gulf Coast Project will address that constraint and at the same time allow Gulf Coast refiners access to lower cost domestic production and avoid paying premium to foreign oil producers.

On the Keystone XL project, in early May we submitted a Presidential Permit application with the US Department of State for the Keystone XL project, which now is defined from the US Canada border to in Montana to Steele City, Nebraska. TransCanada continues to work collaboratively with the Nebraska Department of Environmental Quality on an alternative route that avoids the sensitive Sandhills. That work includes submitting alternative route corridors to the DEQ along with a preferred corridor. A number of public open houses were held to gather feedback from Nebraskans and the DEQ is telling us their review should be complete in the coming months. Once the route is identified and approved, it would be submitted to the federal agencies involved in the approval of the pipeline.

The over three-year environmental review of the Keystone XL completed last summer was the most comprehensive process ever done for a cross border pipeline. That review culminated with the State Department issuing a final environmental impact statement that concluded there would be no significant impacts to most resources along the proposed pipeline corridor. Based on that work, TransCanada expects its cross border permit should be processed expeditiously by the Department of State and a decision made shortly thereafter based on the new route in Nebraska.

Assuming a Presidential Permit is granted in Q1 of 2013, we expect the Keystone XL will be operational in late 2014 or early 2015. The capital cost of Keystone XL is estimated to be $5.3 billion, of which $1.5 billion has been spent as of June 30, 2012.

Back in Canada, we held an open season this past spring to gauge interest in the potential construction of additional oil terminal at Hardesty. We were able to secure bonding long-term contracts in excess of 500,000 barrels a day. And as a result of this strong commercial support, we expanded the proposed 2 million-barrel project to 2.6 million barrels. The CAD275 million project will provide new infrastructure for Western Canadian producers and easier access to the Keystone pipeline system. We expect the Keystone Hardesty terminal to be operational by 2014.

The Keystone system in aggregate is essentially a backbone that connects new and growing Canadian and US supplies to key North American markets. Going forward, we plan to pursue opportunities further along the value chain such as short and long-term storage projects at the receipt and delivery points of the pipeline system. In addition to our continuing focus on connecting growing Canadian supply, we also intend to add supply from US shale plays to the most desirable markets in the United States. Today our customers are asking us to look at markets we do not serve today, both on-shore and off-shore including existing markets in Eastern Canada. And I can tell you that we are aggressively pursuing all of those opportunities.

Moving to gas. In June our Company was selected by Shell Canada and its partners, Korea Gas, Mitsubishi and Petro China, to build, own and operate a large scale pipeline that will transport natural gas to the West Coast to supply their proposed LNG production., storage and port facilities in Kitimat, British Columbia. Virtually all of the capacity will be subscribed by Shell and its partners under shipping agreement for a minimum of 25 years. The CAD4 billion project will connect growing supplies in Northeast British Columbia with growing export markets for natural gas in Asia. We have dubbed the 700-kilometer project, the Coastal GasLink pipeline. It is designed to deliver gas from the Montney region near Dawson Creek British Columbia to a liquefied natural gas export facility that would be built in Kitimat. With initial capacity of 1.7 billion cubic feet per day, we anticipate this large diameter Coastal GasLink pipeline to be operational towards the end of the decade.

On the NOVA gas system, we continue to expand our large natural gas gathering and distribution network during the first half of the year investing about CAD600 million in 10 separate pipeline projects that were built on time and on budget and are now operational. This includes the completion in May of the CAD250 million Horn River project that will bring BC shale gas to market. The NEB has also approved an additional CAD630 million of expansions including facilities that will increase capacity to meet demand growth in Northeast Alberta.

In addition, approximately CAD340 million in new projects are still awaiting NEB approval including the Komie North project that would further extend the Alberta System into the Horn River area. TransCanada now has firm commitments to transport 3.4 billion cubic feet a day from Western Alberta and Northeast British Columbia by 2014. Infrastructure to connect the western sedimentary basins a growing market continues to be pursued particularly to support further development of the Alberta oil sands production and to supply LNG export facilities on the West Coast.

A few comments on our Mainline. An NEB hearing began in June, on June 4 on TransCanada's application to change tolls and conditions of service for the Canadian Mainline. The Canadian Mainline pipeline continues to be a critical piece of North American natural gas network connecting the gas fields of Western Canada with new-- and new Northeast US supplies to the highly populated markets in Central and Eastern Canada and the United States. Usage on the Mainline has shifted away from its historic high level of long haul base load shipments but is still required to provide daily gas to critical eastern markets especially during the coldest winter months.

The Mainline's large capacity is needed to provide natural gas for heating homes, offices, schools, hospitals across this country and into the United States. The NEB hearing is expected to conclude in late September or early October with a decision in late 2012 or early in the first quarter of 2013. The NEB has also approved our CAD152 million plan to expand our Mainline pipeline network in Ontario to accommodate additional supply from the growing Marcellus Shale basin.

Moving over to energy. Now earlier this week we received a decision from an independent arbitration panel regarding the dispute over TransAlta's Sundance A force majeure and destruction claims. I'm pleased that the panel determined that the power purchase arrangement should not be terminated. The independent body ruled TransAlta return the Sundance A units to service in a reasonable time frame. The panel also limited TransAlta's force majeure claim to a period from November 20, 2011 until the units are returned to service. TransCanada's entitled to 100% of the generating capacity of the 560 megawatts Sundance A coal-fired power plant until the PPA expires at the end of 2017. We look forward to receiving the economic value that Sundance A provides to our Company when those units are returned to service.

Moving over to Bruce Power. A further milestone was achieved at Bruce Power in June with the return to service of Unit 3. This CAD300 million investment is an important part of Bruce Power's strategy to maximize the operating life of the reactors. Unit 3 is now expected to produce low cost electricity through at least 2021. The Canadian Nuclear Safety Commission approved the restart of Unit 2 this past spring and that process was moved forward, and as it was moving forward an incident occurred in May in an electrical generator on the non nuclear side of the plant. As a result, Bruce Power submitted a force majeure claim to the Ontario Power Authority. If that claim is accepted, the price received for power generated from the operating units at Bruce Power the units will not be impacted. Work is under way to repair the damaged generator and Bruce expects Unit 2 to be in service in the fourth quarter of 2012.

Commissioning work is continuing on Unit 1. Bruce Power has received approval from the CNSC to remove the reactor shutdown guarantees and is proceeding with the restart of the reactor. Synchronization of the Ontario electrical grid is expected to occur in mid third quarter 2012. TransCanada's share of the net capital cost of the refurbishment is still expected to be CAD2.4 billion. Once the work is complete, Bruce Power will be one of the world's largest nuclear facilities producing 6200 megawatts of emission less energy for the residents of Ontario.

On our solar projects, construction has started on the first two of nine solar projects. They are part of a deal our Company signed in late December of last year with Canadian Solar Solutions. We agreed to purchase nine projects with a combined capacity of 86 megawatts for CAD470 million. Each project would be purchased once they are constructed. Acceptance testing is completed and the projects are operational. The first two projects are expected to begin producing power late this year with the remaining ones slated to be in service in 2013 or early 2014.

Moving to Mexico. We are advanced with the land acquisitions, permitting and engineering activities and except to mobilize for construction on the CAD500 million 235 kilometer Tamazunchale Extension natural gas pipeline in early fourth quarter of 2012. The project has a contracted capacity of 630 million cubic feet a day. It connects to the TransCanada's existing Tamazunchale Pipeline linking up with Mexico's pipeline grid and provides natural gas to CFE for their combined cycle power facilities. The project is underpinned by a 25-year natural gas transportation service contract with Mexico's state owned power Company and we expect the pipeline to be operational in the first quarter of 2014.

So to wrap things up, we continue to advance our capital program. News that we have received the final necessary permits for our Gulf Coast is certainly welcome news for our Company and will allow us to move forward on that pipeline. These-- all of these large scale projects along with our existing core assets do provide us with a certain degree of stability and a very solid platform for growth in the future. We now have CAD17 billion of commercially secured projects and we are considering a number of large -- of other large scale opportunities in all of our three core businesses.

The need for our expertise appears clear in North America. As North America assesses how it will adapt to new and growing supplies of oil and gas and to manage the billions of dollars of investment needed to upgrade the energy infrastructure across the continent.

As I said earlier, I remain very confident TransCanada is well positioned to grow earnings and cash flow and dividends as we complete that capital program, continue to secure attractive new opportunities and benefit from the expected recovery in natural gas and power prices. I'll now turn the call over to Don Marchand who will provide additional details on our second-quarter financial results. Don?

Thanks, Russ, and good morning, everyone. Like to start today by highlighting the following. TransCanada produced steady second-quarter operating results driven by good performance from our CAD48 billion portfolio of high-quality energy infrastructure assets. While persistently high natural gas storage levels, low natural gas and power prices and the planned outage at Bruce Power did impact earnings in the period, CAD10 billion of recently committed assets are contributing highly predictable earnings and cash flow. All of these assets are underpinned by long-term contracts or regulated cost of service business models.

Looking forward, in the near term this will be supplemented by the CAD2.4 billion Bruce A restart which is approaching the finish line, and CAD800 million of Alberta System projects that have or are about to come into service in 2012. In addition, the Company continues to advance various other projects including the Gulf Coast and Keystone XL oil pipelines and secure new investment opportunities in each of its three core businesses. These projects will further diversify the Company's portfolio and contribute to sustainable earnings, cash flow and dividend growth in the future. Finally, we remain well positioned to fund our very -- our capital program as well as other-- these other new initiatives.

Now moving to our consolidated results. Comparable earnings in the second quarter of CAD300 million, or CAD0.43 per share, decreased by CAD55 million, or CAD0.08 per share, compared to the same period in 2011. As highlighted in our quarterly report, net income for the second quarter 2012 included an after tax charge of CAD37 million, or CAD0.05 per share, related to the impact of the Sundance A PPA arbitration decision. Of this amount, CAD22 million, or CAD0.03 per share, related to income recorded in first quarter 2012 and is reflected in Q2 comparable earnings while CAD15 million, or CAD0.02 per share, related to income recorded in fourth quarter 2011 and is shown as a non comparable Q2 2012 item. I will review this in more detail in a few minutes.

Excluding the impact of the Sundance A arbitration decision, comparable earnings for second quarter 2012 were CAD322 million, or CAD0.46 per share, a decrease of CAD33 million, or CAD0.05 per share, compared to the same period last year. Incremental earnings from Keystone and other recently commissioned assets including Guadalajara and Coolidge are more than offset by lower contributions from the Canadian Mainline, ANR and Great Lakes natural gas pipelines, and lower realized power prices and generation volumes in US power. In addition, a significant planned outage at Bruce Power reduced comparable earnings by about CAD0.04 per share in second quarter 2012. As mentioned in prior periods, Bruce A Unit 3 commenced the West Shift Plus life extension project last November. While the outage will create significant long-term value by extending the useful life of the reactor beyond the end of the decade, it meant that Unit 3 was out of service for all of the first and most of the second quarter, not returning to full power until June 17.

I will now briefly review the business segment results at the EBITDA level starting with natural gas pipelines. The business segment generated comparable EBITDA of CAD666 million in second quarter 2012 compared to CAD688 million for the same period last year. The CAD22 million net decrease resulted primarily from lower contributions from the Canadian Mainline, ANR and Great Lakes. Incremental earnings from the Guadalajara pipeline in Mexico, which was placed in service in June 2011, partially offset these decreases.

With respect to the Canadian Mainline, the second quarter and year-to-date results reflect the last NAB approved return on equity of 8.08% on deemed common equity of 40% and exclude incentive earnings. A lower investment base also reduced earnings compared to the prior year. Third quarter will reflect the same return on equity pending a decision from the NEB on our 2012/2013 tolls application expected sometime in the late 2012 or early 2013. In our application, we requested an after tax weighted average cost of capital of 7%, which equates to a return of -- rate of return of 12% on a deemed equity commitment of 40%.

Our US natural gas pipelines were affected in second quarter 2012 by discounted and unsold capacity on Great Lakes and lower storage and transportation revenues from ANR. For the remainder of this year, high natural gas storage levels and the low natural gas price environment will likely continue to negatively impact revenues generated by these assets.

Turning to oil pipelines. Keystone generated CAD178 million of EBITDA in the second quarter of 2012, compared to CAD154 million for the same period last year. The CAD24 million improvement was the result of an increase in revenues related to higher fixed tolls for the Wood River Patoka section of the system which came into effect in May 2011, as well as higher volumes. Keystone remains on track to generate approximately CAD700 million of EBITDA in 2012.

In energy, comparable EBITDA was CAD170 million in the second quarter, compared to CAD248 million for the same period last year. The CAD78 million year-over-year decrease was the result of the combination of factors. The business benefited from incremental earnings from the startup of Coolidge in May 2011 and two phases at Cartier Wind in November 2011 as well as an increase in contribution from Bruce B resulting from higher generation volumes, lower operating costs and lower lease expense. However, these were more than offset by a lower contribution from US power, resulting from lower realized power prices, higher load servicing costs and reduced water flows at the hydro facilities in New England, a reduction in Bruce A generation volumes from the planned West Shift Plus life extension outage, lower generation volumes received from the coal power purchase arrangements in Alberta, primarily due to planned maintenance outages by the plant owners, and a CAD30 million pretax charge related to the Sundance A arbitration decision.

With respect to Sundance A, TransCanada had accrued CAD188 million of pretax income from the commencement of the outage in December 2010 to the end of March 2012. As a an outcome of the arbitration decision, the Company's entitled to receive approximately CAD138 million of this amount representing the accrued earnings for the period up to November 20, 2011. The CAD50 million of EBITDA recorded beyond this date was adjusted for in the second quarter 2012 in two ways. CAD30 million of the CAD50 million related to earnings recorded in the first quarter of the current fiscal year, was adjusted through comparable earnings. The remaining CAD20 million related to fourth quarter 2011 and was excluded from 2012 comparable earnings. Going forward, until the Sundance A units are returned to service, TransCanada will not realize the generation or related revenues it would otherwise be entitled to under the PPA and will be relieved of the associated capacity payments. TransAlta indicated expects to return the units to service in the fall of 2013.

Now turning to the other income statement items on slide 23. Comparable interest expense in the second quarter was CAD239 million compared to CAD236 million in the same period last year. The slight increase reflects incremental interest expense on new debt issues, partially offset by higher capitalized interest related primarily to Keystone and the impact of debt maturities in 2012 and 2011. In the second quarter, CAD76 million of interest was capitalized to assets under construction compared to CAD68 million for the same period in 2011.

Comparable interest income and other of CAD19 million for second quarter 2012 decreased CAD9 million due to lower realized gains on derivatives used to manage the Company's net exposure to foreign exchange fluctuations on US dollar income. In combination with US dollar denominated interest expense, this hedging program largely counterbalances the currency impact of translating US dollar pipeline and energy income reported in the business lines. Comparable income taxes of CAD91 million in the second quarter 2012 were CAD48 million lower primarily due to lower pretax earnings and changes in the proportion of income earned between Canadian and foreign jurisdictions.

Moving on to cash flow and investing activities on slide 24. Cash flow remains solid. Funds generated from operations totaled CAD729 million in the second quarter, and are on track to be approximately CAD3.5 billion for the full year 2012.

Turning to investment activities. Capital expenditures were CAD397 million in the second quarter, and CAD861 million for the six months ended June 30, 2012 most of which relates to expansions and extensions of the Alberta System and the oil pipelines business. Equity investments for the three and six months ended June 2012 were CAD197 million and CAD413 million respectively. This represents the Company's investment in equity accounted for joint ventures and mostly relates to our investment in Bruce Power and its refurbishment and restart of Units 1 and 2 including capitalized interest as well as other planned maintenance activities including Unit 3 West Shift Plus program.

During 2012, we expect to invest approximately CAD3.9 billion in capital projects and equity investments, which include expenditures on the Alberta System, the Gulf Coast Project, Keystone XL, Bruce Power, the Tamazunchale Extension, Canadian Solar and maintenance capital. This number contains approximately CAD300 million of capitalized interest.

Now looking at slide 25. Our liquidity position and access to capital markets remains strong. At the end of the second quarter our consolidated capital structure consisted of 43% common equity, 4% preferred shares, 2% junior subordinated notes and 51% debt net of cash. We had CAD490 million of cash on hand, along with CAD4.3 billion of committed and undrawn revolving bank lines with our high-quality bank group. Our three commercial paper programs, one in the US and two in Canada, are well supported and provide flexible and very attractive sources of short-term funds. We are well positioned to fund our current growth program through funds generated from operations and access to the capital markets on attractive terms. Going forward, we will be opportunistic in sourcing required capital given the unprecedented low interest rate environment.

In closing, TransCanada's diverse, high-quality energy infrastructure assets performed well in the second quarter. The majority of our assets continue to generate stable and predictable earnings and cash flow, although historically high natural gas storage levels and low natural gas and power prices affected certain aspects of our business and will continue to do so until we see a recovery in the macro natural gas environment. Though these factors are expected to continue to impact volumes on our US pipelines and power prices, our new assets are performing well and we look forward to the contributions from Bruce Power completing the refurbishment and restart of Units 1 and 2, as well as having Unit 3 returned from the seven-month life extension outage, Alberta System projects coming online and a decision on the Mainline 2012/2013 tolls application.

We also continue to advance other initiatives in our CAD17 billion capital program including the start of construction on the $2.3 billion Gulf Coast Project, and towards the end of the year adding some of the Canadian Solar facility to our portfolio. It is noteworthy that since the beginning of this year we have added CAD5 billion of new projects which include Coastal GasLink, the Tamazunchale extension and the Keystone Hardesty terminal. We are well positioned to fund our current program along with these projects and the additional growth we hope to secure.

Finally, we expect to continue to generate significant cash flow that can be used to invest in additional accretive growth opportunities, grow the dividend and further enhance our financial strength and flexibility in the years ahead. That's the end of my prepared remarks, I'll now turn the call back over 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 investment community first, and once we've completed that, we'll then turn it over to the media. With that, I'll turn it back to the Conference Coordinator for your questions.

Thank you. We'll now take questions from the telephone lines, first from the analysts. (Operator Instructions) Paul Lechem from CIBC.

Maybe just a couple of questions on the power facilities. On Bruce nuclear, maybe to start off with, you mentioned you've filed a force majeure. I was just wondering if you could give us any more color around what the basis is on the claim, what the timing might be and any issues you might expect on that?

It's obviously a pretty sensitive legal issue. Suffice it to say, we believe that there's ample justification for the force majeure claims for both Units 1 and 2. We've advanced that and we expect to hear back at some in the future on it.

Would you hope to hear back before the units actually both go back online?

Hard to say. I think it might take a little bit of time to get through this issue.

So in Q3 are you going to be recording revenues on that based on the contracted price or based on the spot price that--?

No, based on the contracted price.

Okay. And then just quickly on Ravenswood, if I can switch over The-- in the write-up you mentioned FERC has addressed one of the two claims. Can you talk a little about what that claim was that they've addressed and what's the other claim outstanding and what you expect the outcome to be?

The claims were both related to issues about -- around the concept of mitigation exemption tests for buy side market power in the market. They came out a little while ago with the first decision. I think there were both some positives and some negatives from that order. We were pretty encouraged that FERC took some steps to increase the transparency and accountability with regards to future mitigation exemption test decisions. And the order also addressed our concerns regarding transparency of these met determinations and the need to adjust met determinations for inflation.

I would say that our complaints on the need to consider bilateral contracts and selection of differing natural gas price curves, those issues were denied. I think that first order or application that we made was really made before we had all of the information with respect to the mitigation exempts test outcome for those two plants in Zone J. And as a result, we filed the second application, once we had the specific information on how the met determinations were made for those two new plants. That's the one we're still waiting to hear and I think we'll get a lot more information when we see FERC actually opine on those two specific incidences of how the ISO applied their met criteria.

And just on that, do you expect that there will be any retroactive application to the capacity pricing or will this just affect go forward, on a go forward basis?

No, I think unfortunately FERC has really loathed to make any order that has retroactive impact in any market, any energy markets. So any decision that they would come out with, I would expect would be prospective.

Okay. Thank you for that.

Thanks, Paul.

Juan Plessis from Canaccord Genuity.

Back to Bruce Power, with regard to the restart, do you expect Unit 2 to enter commercial service in Q4? Is it possible to be a bit more specific on that timing now that we're already well into Q3?

Yes, what we're doing, Juan, is we're-- there are some opportunities we have to accelerate the completion of that repair. That's kind of the reason for the range of outcomes and we're just working through that right now. So as soon as we can give a little more color, we'll certainly do that.

Okay, thanks for that. And I read that Bruce Units 3 and 4, their percentage availability is expected now to be in the low 60s for the year. I think this was lower, I think at the end of Q1 you indicated mid-70s. Can you tell us, give us a little bit of color, what's going on there?

Sure. We have an outage planned for one of the units already this year and when the Bruce guys were doing their analysis, what they realized is that by modestly extending the Bruce outage in that unit in 2012, we can do away with an outage in 2013. So it had a very significant value, positive value to extend that outage in 2012 and thereby avoid the need for an outage in 2013. So that's the reason for the change in availability percentages.

Okay. Thank you very much.

Linda Ezergailis from TD Securities.

I was-- I'd be interested to hear any updates on your discussions with various stakeholders on your eastern Keystone initiative as well as potentially extending upstream to service the oil sands. And specifically I'm wondering what sort of timing and scale might be expected and how much of that is dependent on first of all getting the Presidential Permit for Keystone XL and potentially the West Coast pipelines by other parties being resolved either way in terms of those going ahead?

Sure, let me try to address all of those and let me know if I missed any of them. But as we've talked about in the past, we are looking pretty hard at an opportunity to transfer some of our Mainline pipeline from gas transportation service to oil transportation service. We're still in the relatively early stages of that. We have certainly determined, we believe it is very technically feasible, and we believe the resulting tolls from that project are very competitive with other competing projects to get Canadian oil to markets both in and outside of Canada.

We have a lot of optionality with respect to the size, depending on the demand, we could configure it probably anywhere from a 400,000-barrel a day pipeline up to about a 900,000-barrel a day pipeline. And right now we're thinking the option that we could -- we already have about 80% of that pipe in the ground which we think gives us significant advantage going forward. And then the opportunity, we could build incremental pipeline anywhere from Montreal, potentially all the way to the Canadian East Coast and that will l have a lot to do with what our shippers have to say. I would say at this point we're getting a lot of inbound interest from potential shippers on the project, but we have a fair bit of work to do to lock all of that down.

That's interesting. What about servicing the oil sands region as well?

So we are -- we see very significant opportunities to grow our presence in the inter-Alberta market. We're working pretty hard on that, we don't have anything to announce now, but we're working hard and we think we're going to have some good results down the road.

That's great. Thank you.

Last question on that one, Linda, just, it's Russ, if I could add, you asked whether it was dependent upon the outcomes on the West Coast projects or the Keystone Presidential Permit process. And I would say that those opportunities aren't dependent upon the outcomes of those. As you know, Canadian production is expected to grow by about 2 million barrels a day. US crude is expected to grow, especially for us in the Northern parts of Bakken in Montana and North Dakota, say another 1 million barrels a day, so we're going to need a lot of transportation capacity to move both from those field locations as well as to move it to markets, new markets, both within Canada and potentially export markets. So our projects what we're hearing from the market place aren't dependent upon the outcomes of others. People are seeking new transportation alternatives to get their crude out of the ground and on to market.

That's very helpful. Just a follow-up question for either Don or Glen. With respect to your consolidated effective income tax rate, is it reasonable to assume that a run rate going forward would be similar to the second quarter, given that your business mix has shifted a bit?

Probably something in the 24% range is what we would suggest as an appropriate rate for this year and next year at this stage.

Great, thank you.

Matthew Akman from Scotiabank.

Just sort of come back to Bruce, but I just want to know specifically whether you've found that you can actually repair the electrical generator, whether you have to replace it? Sounds like repair.

No, it's -- we have spare parts to repair it. Basically what happened, although it was an unused, new condition generator it had a manufacturing defect in it which caused a portion of the generator to overheat. We do have spare replacement parts and there are a number of parts we're repairing, so that process is well advanced and we expect to be putting the unit back together in fairly short order.

Okay. Thanks, Alex. Shifting to oil pipeline, since you guys announced the Gulf Coast extension differentials have widened out and I think concerns over capacity, even though Seaway's been out at remain and potentially been [exhausted]. I'm just wondering what your outlook is for the economics of your Cushing to Gulf Coast link and whether that's improved over the last six months since you guys announced the project?

As I know you're aware, with all of the increase in production in the Bakken, with Canadian production and with the Midwest refineries converting a lot of their capacity to heavy, we expect to see over the next decade something in the range of about 2 million barrels a day of incremental light sweet capacity sort of sitting in Cushing. So we think even with Seaway, even with our project, there's significant requirement for takeaway capacity. We're certainly seeing continued interest by potential shippers on the projects. And the other comment I would say is we remain very confident that Keystone XL is ultimately going to be approved and at the end of the day that'll see that pipeline be fully contracted. So we're pretty comfortable overall with how we sit economically on that project.

Okay. And final question on ANR which obviously was weak in the quarter, there's a lot of storage around. Is your outlook for that pipeline still robust once the storage levels come back to normal? Is this kind of a temporary phenomenon in your minds or is it a longer term erosion of the pipeline's competitive advantage that's caused the deterioration in cash flow for the quarter?

I think you're right. The high storage levels coming into the first quarter impacted not only storage, but transportation as well as condensate sales. We saw that continue into the second quarter. There was an unusual item in the second quarter of 2011 for about CAD6 million which was a settlement with respect to some offshore transportation. So that was a bit of an anomaly and kind of skews the look of the results. I would say we have some impact from the basis differential on our Southwest line being a little tighter than we've seen in the past with significant supplies in the Chicago area as well as in the Ohio area. So we are seeing minor reductions in revenues as a result of that. I'd suspect some of that will continue but with a normal year these storage and related transportation and condensate revenues should recover.

Okay. Thanks, guys. Those are my questions.

Thank you.

Thanks, Matthew.

Carl Kirst from BMO Capital.

Just a couple of clean-up questions, most of mine have been hit. The first is actually on -- this is really more I guess affiliated with Coastal GasLink or at least I should say LNG to the West Coast. Since announcing that project I'm just curious if there's been any other stepped up conversations for instance with any of the players in Prince Rupert as far as connecting into Vanderhoof?

We continue to have discussions as we were having prior to coastal gas link with all of the players who are -- have announced or are looking at LNG to the West Coast, and clearly Prince Rupert is one of the outlets as well as continuing to look at the Alaska opportunity for LNG. We looked at it in two parts. The first part is the benefits of the Alberta System and our NGTL system and the NIT hub, two parties wanting to go to the West Coast. When you start up an LNG facility, you need to keep the volumes full every day, all the time, so there's quite a bit of drilling required. But the benefit of having access to the most liquid hub in North America is something that a lot of the potential parties looking at the West Coast see and so we talked to them about that as well as specific projects to the West Coast, whether those go from Vanderhoof or another point on the NGTL system remains to be seen.

Fair enough. And then maybe one other, Greg, pipeline question for you. Just my recollection was that there were a number of RFPs coming out of Mexico, maybe due September, October, that would collectively be around CAD3 billion or so and I guess is that still -- is that still going forward and if it is, when do you think you would hear whether you'd be successful with that?

The projects as of last week they announced a couple week delay but looked like Mexico is still pursuing all four of those projects. The first one starting at the US border along the west side of Mexico. We are interested in those. None of the bids have been due yet but we are clearly interested in and looking to bid on those. If they stay on track the first projects we'd hear during the third quarter.

Great. Thanks so much.

No problem.

Robert Kwan from RBC Capital Markets.

Just on the Alberta power and Sundance, just wondering how you feel about the fall 2013 date as the targeted return to service?

Our estimate is probably takes around 10 months or so to do a repair of that nature. So we're in -- we certainly are going to do everything we can to work with TransDelta to see if we can get that back as soon as possible. But it takes a bit of work to get that repair done.

And then just turning to oil on the inter-Alberta, what you're looking at. That's a pretty crowded space in between Fort Mac and the two major hubs. Just wondering where you see your advantage? Is there the potential to use some existing underutilized gas infrastructure there? Would you look to partner? Just kind of what are your thinking there?

I think you are correct, I mean, there is certainly some areas in Northern Alberta that are well served by incumbent pipelines. But a lot of those projects or a lot of those existing pipes are near or at capacity, so the next projects will kind of be pipe on pipe, new pipe on new pipe competition, and we believe we have a lot of experience operating and building pipelines in that part of the world. And we're always looking at our assets to see if there's an opportunity to potentially make better use of them. But we think we have some pretty strong competitive advantages in these areas where-- that are not adequately served by existing pipelines.

Robert, I guess I would add in terms of where the pipeline space has gone to the last little while. Something that TransCanada does bring to the table, it has become very clear in situations like the Coastal GasLink Project, having the technical capability to be able to manage through these major safety issues and operational issues, the capacity to deal with Aboriginal issues, which land owner issues which are now far more complex than they were before, and the financial wherewithal to actually build the pipelines necessary for the future. And we're hearing that more loud and clear every day that those are going to be criteria that are going to be front and center in everyone's minds in any of these competitive processes. No longer can it just be a bid solely based on the lowest price. It has to be a bid based on who can provide that service safely and reliably, not just for the next three years but for decades to come. And there is beginning to be a differentiation. So that's what I see our competitive advantage out there in the marketplace right now.

Okay, if I could ask one quick last question. Just on the Coastal GasLink, I think the contemplation is to roll at least a portion of it into the Alberta system. Does any-- if that application is rejected, does that do anything to change the returns under your contract with Shell?

No.

No, I don't see that. The Shell project stands on its own. The first piece of the pipeline would have access for NGTL and we would be holding an open season and talking to parties interested in accessing that pipe and then it would just become part of NGTL and would not result in incremental revenues.

Okay. That's great. Thank you.

Thanks, Robert.

Ted Durbin from Goldman Sachs.

Just to be clear on the coastal link LNG, what are the returns that you're targeting, should we think about this as pretty similar to a regulated cost of service pipeline project with a similar deemed equity and ROE that you're getting say on Alberta?

Yes, I think that's the right way to look at it.

Okay. And in terms of cost sharing there, is there anything there that you've got protection on or does that kind of all get rolled into the regulated piece of it?

No, we have an arrangement where we'll be incurring some costs in advance of determining whether the project goes forward or not, and if the project does not proceed we'll be reimbursed for those costs.

Got you. And then just coming back to Sundance here. This sort of CAD30 million pretax per quarter on the PPA, is that a good run rate to use in terms of call it a lost earnings until next fall or is there anything in the PPA that would change between now and then where that number might be different?

It's Glen here. I think as far as trying to model something that isn't going to be there, it depends on -- it would depend on power prices and spot prices at the time. I think it's just fair to say from a modeling point of view, you would just not put it in.

Got you. Okay, that's it from me.

And Ted, just for your own reference, if you want to look at what it did earn last year, you can just refer to the quarterly reports or Terry or Lee can help you with it offline.

Okay. Thanks, guys.

Steven Paget from FirstEnergy.

You sort of addressed this earlier, Russ, but what were some of the factors that led to the contract on the Coastal GasLink, like you said some of them were beyond price?

For sure, I mean as you think of a project of this magnitude, the pipeline isn't the driving factor in a project like this. The major factor is the CAD12 billion LNG facility that needs reliable supplies every day, so paramount in the criteria is reliability. So our proposal had to include how do we design a pipeline that has certain redundancies in it to ensure that reliability, what our operating practice is going to be, right down to our operator practices. Another one would be complexity of construction through some very, very tricky and steep terrains as you get into that sort of last part into Kitimat, TransCanada is one of the only Companies that has actually constructed in those kind of locations. Our Tamaz project kind of looked like that the last little while, our Guadalajara project in routing around a live volcano. Those technical capabilities were extremely important in the process.

I think a third one as I mentioned was our stakeholder and Aboriginal relations capabilities. We have built, as I said, probably CAD3 billion of facilities in Northeast British Columbia and Alberta over the last couple of years and dealt with those issues in an upfront and successful way. So I'd say those were some of the criteria that I believe were very front and center in us being the selected party to win that. I think the last one I guess it would be our financial capability and our ability to deliver on what we say that we're going to deliver. It's a CAD4 billion project and they're not for the faint of heart these days as being able to work through these processes in a professional way and actually get them done is critical and I suspect that's why Shell and its partners picked TransCanada.

Okay, well, that's great, thank you. I guess my next question is how much have you invested in Coastal GasLink at this point? And how much do you plan to invest by the end of this year?

The numbers are relatively small. I think we think the upfront costs are in the -- to get to the point where you have approvals in the CAD200 million to CAD300 million range and we're capitalizing those numbers.

As Greg said, is the event it doesn't move forward, 100% of those costs are recoverable.

All right, thank you. Those are my questions.

Thanks, Steven.

Thanks, Steven.

Andrew Kuske from Credit Suisse.

I think the question is really for Russ and probably a little bit of Don. We've seen some pretty attractive debt financings that have been done in the market in the last year and really in particular the last few months as nominals and really [risk] rates have dropped pretty impressively. So I guess the question really is how do you see that unfolding into regulated rates of returns where you've got regulated assets? And then on unregulated assets where you got really cheap financing available on the debt side, are you seeing any spread compression on your targeted returns?

On the regulated side, there has obviously been a linkage over the past 10 or 15 years in Canadian rate determination to long bond yields, so we're at a pretty low point right now in the low 8s. I'm not sure how much lower they can go before you start jeopardizing the attractiveness investing more in that infrastructure. In our rate filing we're looking for an [atlac] of 7% which we think is appropriate for long-term multi-decade infrastructure rather than single point in time.

In terms of assets we're looking at, we really haven't budged off what our hurdle rates are. Again, we look at things over a very long cycle here. Others may be looking at this cheap debt financing right now or even floating rate financing. But we're-- it is a factor but it's not a driving force for us to significantly lower hurdle rates on 20, 30, 40-year projects.

I think just on the first question, Andrew, you may look at the TQM hearing where the question of the linkage between long bonds and return on equity was debated. I think what was determined was that the formula that attached those two things together was no longer applicable especially in most markets in that particular period of time. We saw returns on -- required returns on equity rising, at the same time bond rates were falling. So clearly even directionally the formula wasn't correct. What we're seeing in the marketplace is returns for pipeline projects haven't moved that much. They've moved down as Don said for regulated project in that sort of 7% kind of range maybe from an 8% kind of range. But not materially, they haven't fallen materially.

And the fair return standard, the standard that determines the return on regulated assets is what, in the absence of competition, what would you be able to achieve as a return on an asset of similar risk in the marketplace. And I'd say that hasn't moved very much. So I wouldn't see going forward this current low interest rate environment having a material impact on a regulated returns.

So is it maybe fair to argue and really taking all those points into consideration that given capital is getting a bit more scarce, not necessarily on the Canadian market, but when we see markets globally there are a number of banks deleveraging and so capital is becoming a little bit more scarce from availability standpoint other than for the really good credits, that that should put a good baseline on returns and then arguably then put a biasing upward on returns on capital attraction tests?

Yes, I think that's fair.

Okay. Thank you.

Thanks, Andrew.

David Nicol from Morningstar.

Just two questions for you, more I guess broad industry type of questions. On the power side, I wonder if you can provide some insight as to what you're seeing with respect to power demand in Western Canada and the Eastern US? Specifically is it's strengthening or weakening or flat relative to the second quarter.

And then just a second question is on the liquids side. If you take kind of a broad look at pipelines in general right now, Enbridge added some incremental cost to, you could say secure incremental support in BC or for safety as they'd call it. What I'm wondering is whether you see that this could result in incremental costs kind of across the pipeline infrastructure for liquids in general under the logic of if it's good enough for BC, is it good enough for other regions? Thank you.

Well maybe I'll, it's Alex, I'll take that power demand question. I think if your question is sort of Q3 versus Q2, I think in just about all of the markets we're in we saw really, really low power demand. We had very mild weather conditions. I mean, Alberta had mild weather conditions, same actually for New York, New England. We've seen a big spike in demand in the summer period, particularly in Alberta hit an all-time peak summer load, very close to it's all-time peak. Ontario, we-- with the hot weather. We saw very strong peaks in New England, New York, with these high temperatures. But it's kind of little bit early days to draw trends out of that. So much of demand has been impacted by weather over the past six or eight months that it's kind of hard to draw a trend. What we do see is -- I like to look at peak demand because that tells me -- it kind of takes all the noise out of it. And definitely we're seeing some pretty strong new peak demands in Alberta and pretty good peak demand in New England, New York.

David, I'll take a shot at the second one. There's no question that the incidents that have occurred across North America both on gas pipelines and oil pipelines will result in additional requirements for enhanced safety and reliability and I think that's a very good thing. Safety is number one in the industry. I mean you hear us say that all the time, but it is. I'm very supportive of that. There's no question that there'll be increased costs associated with that but if that makes the public safer, that's a good thing.

With respect to our new designs, if you will, and our pipelines, I don't see any incremental cost on things like Keystone, for example. We were sort of ahead of the curve on that. We've agreed to 57 additional conditions already with the Department of Transport in the US which incorporates new construction techniques, higher number of remotely controlled shutoff valves across the system, increased number of inspections, burying the pipe deeper, drilling all river crossings. On the Keystone system we have 36,000 electric sensors, electronic sensors that monitor what goes on in that pipeline and satellite driven, refreshes every five seconds. So we're sort of at the leading edge. Now obviously not all pipelines will have that, but that is the future of what pipelines look like is that they are more costly but those costs have been built into our pipes, our new pipes already. But the bar is rising and as I said we're totally supportive of any things that makes our industry safer.

Greg, thank you.

Linda Ezergailis from TD Securities.

Just some clean-up questions on your power business. Your US hydro operations, is it fair to assume that the water levels will remain low in Q3?

That is typically our experience but we have had in the past some very, very rainy summers that have contradicted that. But typically as I know you know, we do get the lion's share of our generation out of the hydros from the snow pack and that's coming in the spring. So I would be-- I think it's a reasonable expectation that hydro volumes will be depressed for Q3.

Okay. And can you describe the nature of your unplanned outage at Portlands and how it's been resolved?

We had an equipment failure at Portlands which we had the unit out there for that period of time while we replaced the failed equipment and it's passed. Everything's fine and we're good to go.

Great. And any update on your discussions around resolving your Oakville arbitration with the Ontario government?

Well, we -- as everybody knows, we've signed an arbitration agreement and we are proceeding down that path with all haste for an arbitration-- for the arbitration to occur. At the same time, our door is open and we continue to have discussions about other resolutions of the Oakville issue and those other options could include a replacement power plant. So we're working on all of those options as we progress the arbitration.

Great. Thank you very much.

Thanks, Linda.

(Operator Instructions) Steven Paget from FirstEnergy.

A bit of a more macro question for Greg here is-- are we seeing a bit of a drop off in gas demand in Ontario? And if we are, I'm just wondering what might be behind it?

Well, I think there has been a bit of a demand drop, although our forecast into the future would see demand actually increasing as more of the coal fleet is retired and there's more conversion to natural gas. I think it's fair to say that the lagging impacts of the recession have impacted industrial demand in Ontario and so there's been some demand destruction there. The economy recovers and as we move to more gas fired generation, our view is we're going to see Ontario demand increasing. We've got lots of activity in the triangle and lots of interest in renewing and extending contracts in the-- in what we would call the triangle of the Mainline.

Okay. Okay, thank you.

Thanks, Steven.

Thank you. We'll now take questions from the media. (Operator Instructions) Scott Haggett from Reuters.

Hi, Russ. We've seen some US legislators link the Nexon, SINOC deal to the decision to not approve Keystone XL. And I'm wondering if you see those linkages and what we should be drawing from them?

Can you ask that question again, Scott?

Saying we're seeing some US legislators link SINOC's decision to acquiring Nexon with the decision to not approve Keystone XL. I'm wondering what linkages you see and whether or not that's a valid case that they're making?

I think as we said before, I mean the Canadian oil sands is the third largest, second largest, depending on who you're talking to, crude reserves in the world. Obviously, they're very attractive to Canada and North America but they're also attractive to markets around the globe and we said that before. And that it will be produced irrespective of the decision to build the Keystone pipeline. And I think we're starting to see that -- evidence of that interest obviously in things like the SINOC Bill. But I mean there's been a fair bit of investment from not just Asians but Europeans and American firms in the development of the Canadian oil sands. I suspect that will continue to grow going forward. It's a very important resource and Canada is a good place to do business. It has proper or economic or regulatory and environmental oversight, rule of law. It's a good place to invest your capital in this kind of business. So I suspect that it will continue to attract more and more investment from foreign companies.

So you don't think the two are linked?

As I said, these business decisions are fairly complex for folks and they're long-term decisions. So as I said, this is a very important resource and I don't expect that we'll see any diminishment in interest in the future here.

Great, thank you very much.

[Rebecca Thomson] from SunNewsNetwork.

First of all, what is your perspective on the conditions set out by BC Premier Christy Clark earlier this week on the Enbridge pipeline?

That's not one of our projects so I can't really comment on those conditions. As I said, it's a very important resources as I just said to the last caller. It's a very important resource for Canada. I think it's important that we find additional markets. US is probably the most logical important market for us, but as production grows, diversification of market is going to be very important for Alberta and for Canada and that process will sort itself out in the proper ways.

And secondly, I know you addressed safety earlier but just quickly, can you describe how TransCanada is reassuring Canadians and Americans that the Keystone pipeline will be safe?

Well I think the things that I mentioned before is it's going to be the state-of-the-art system. We've got significant experience in building pipelines and we have added additional features that include around the clock monitoring of the pipeline by our staff. We've added greater emphasis around leak detection and monitoring as I mentioned, 36,000 electronic sensors across the system. Horizontal drilling under all river crossings, we go a minimum of 25 feet under all river crossings. Those river crossings will include thicker steel, will operate at lower pressure and further protected by advanced non abrasive coatings under those river crossings to ensure when scouring and flooding does occur that that pipeline never becomes exposed. So those are the kinds of things that we put in place voluntarily on the Keystone pipeline system to make it the safest pipeline.

And the US Department of State through their three-year process, safety was one of the key criteria, and they determined at the end of that process and the final environmental impact statement that the pipeline would have a degree of safety above other pipelines that are in the United States today. So that's what we've been telling folks.

The Keystone pipeline itself has been operating for about 1.5 years now. We've delivered pretty close to 300 million barrels of Canadian crude to that marketplace safely and reliably every day. We have had some leaks in the system but those have all been related to our pump stations. The pipeline itself has had no integrity problems at all, and I would expect that we'll be able to continue to operate on that basis for the future. I mean we're-- said job one is safety and we're focused upon it and we have a 60-year history of doing that safely and reliably and I don't expect that to change.

Okay, great. And lastly, we've heard a message coming from Republican Senator Terry Lee this week, his message is get this project, this Keystone project accelerated. His message to Obama is stop changing the rules. So clearly this is going to be widely discussed in coming months among Americans. What do you think US voters need to know about the Keystone pipeline?

I think that what they need to know is that this will be the safest pipeline that has been built. It can be done in a way that meets the needs of Americans. But I think most importantly, the choice that we're talking about here is not a choice between alternative energies and crude oil. The US consumes 50 million barrels of oil every day and they import some 9 or 10 million barrels a day from elsewhere around the world. Canada is the safest and most reliable place to get that oil.

Really the only question on the table I think right now is where do we want to get that oil from. Do we want to get it from Canada or do we want to get it from other places around the world? If you get it from Canada, it results in a CAD5 billion Keystone XL pipeline project which provides economic stimulus. It provides suggest job creation along the pipeline system. And it provides significant energy security for not just the short term but this pipeline will be in the ground for decades. So those are the advantages to Americans and the sooner we get it approved, the sooner we can put all of those people to work and bring energy dependence, independence to North America. So that's what I see as the benefits and as I said, the sooner we can get there, the sooner we can put those folks to work.

Great, thank you.

Elsie Ross from Daily Oil Bulletin.

You mentioned that you might be looking at a delay in the Eastern Mainline expansion. How much of a delay could that be and what will that mean to somebody like York Centre, their energy that they're counting on it?

Yes, we're working hard to stay with or very close to our deadline and we're working with our shippers on making sure that we have ways to get supply to them. And that York is clearly one of our customers that we're working closely with. We just acknowledged in the quarter that we are seeing conditions coming out of the NEB with respect primarily to the acquisition of land that has the potential to slow us down a little. But we've just been looking at that project and we're working hard to make sure that we can get service to those customers.

So when do you have a sense of-- if there would be a delay and what it might be?

Well we need to get constructing here in the next couple of weeks and so we're working diligently right now to resolve with the NEB any final issues they have and so we'll know very quickly here.

Thank you.

John Spears from Toronto Star.

I have one housekeeping question and then a real one. The housekeeping is who was asking -- answering the questions earlier about Bruce Power? I just wasn't sure who it was.

Alex Pourbaix.

That was Alex Pourbaix, okay.

Yes.

Okay, thanks very much for that.

No problem.

Right, and I wanted to know about you said that you're still in discussions with the Ontario government about the Oakville plant and the alternatives. And you mentioned that there's several options and one might be a replacement plant. I'm just wondering if one of those options is a partnership with LPG at [Naticook]?

I just kind of threw that out as opportunities that would strike me as available. I think you probably saw that Eastern Power, which was in a similar situation to TransCanada with the cancelled PPA announced recently, that they were likely-- had an opportunity to build their plant on another site and that's really all I was referring to. I don't have any specific comments to add on where we sit with the OPA or government right now.

Great, thank you. Sorry, is that Alex Pourbaix again?

Yes.

Right, okay and just one other thing. There was a report that I'd heard that the Ontario government has already paid you CAD150 million in sort of preliminary compensation for the Oakville plant. Can you say whether there's anything to that?

That is incorrect.

Okay. Or any similar amount?

No.

Okay.

No.

Thanks very much.

No problem.

(Operator Instructions) [Patrick Badly] from [Plats].

I was just wondering if there is any sort of time line right now on the possible Mainline conversion and whether there's an idea of the costs that might be associated with that?

Again, we're in conversations right now with major potential shippers and a lot of those questions with respect to sizing which will then lead to cost as well as in-service dates and when they would like to see these in-service are being discussed currently. So I'd say it's premature to nail down any of those kinds of things at the current time.

Thanks.

Thank you. There are no further questions at this time. I would like to turn the meeting back over to Mr. Moneta.

Thanks very much. And thanks to all of you for taking the time this morning. We really do appreciate your interest in TransCanada and we look forward to speaking to you again soon. Thanks and bye for now.

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