TC Energy Corp (TRP) 2011 Q1 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2011 first 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 2011 first 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; Greg Lohnes, President of Natural Gas Pipelines; and Glenn Menuz, our Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and other general issues pertaining to TransCanada. Please note that a slide presentation will accompany their remarks. A copy of that presentation is available on our website at TransCanada.com and it can be found in the Investor's section under the heading Events and Presentations.

Following their prepared remarks we will turn the call over to the conference coordinator for your questions. And 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 reenter 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 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 and 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 measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures and as a result, they may not be comparable to similar measures presented by other entities. They 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'll now turn the call over to Russ.

Thank you, David, and good afternoon, everyone and thank you for joining us today. As many of you heard in my annual meeting address a short time ago, we had a very strong first quarter. Comparable earnings were up 30% compared to the same period last year to CAD425 million or CAD0.61 per share. The two main factors that drove this earnings increase, we are seeing the positive results of our CAD9 billion of new assets being put into commercial operations this past year. And TransCanada's base load power assets have benefited from higher power prices, primarily in the west. Our strategy is working and realizing on our vision of becoming the leading energy infrastructure company in North America by focusing on what we have worked on so well in the past and executing our strategies moving forward. We will continue to deliver energy reliably, safely, and responsibly, growing earnings and cash flow over the near term and the long term.

A key element of this is completing the remaining CAD10 billion of our capital program. Over the last 12 months, 7 new major projects have started operations. The first 2 phases of the Keystone project, Kibby Wind, Halton Hills, Bison, Groundbirch and the North Central Corridor project. Two other major projects are expected to be complete in the coming days and months, but I'll provide you with a little bit more information on that in just a moment.

On the financial side, on all measures, this was a very strong quarter. Net income applicable to common shares for the first quarter was CAD415 million or CAD0.59 per share, which is an increase of 20% per share over last year. Comparable EBITDA for the first quarter of 2011 was CAD1.2 billion, an increase of 22%. And funds generated from operations were CAD919 million, an increase of 27%. As well, today the Board of Directors declared a quarterly dividend of CAD0.42 per common share for the quarter ending June 30, 2011.

Moving over to Keystone. We celebrated a very significant milestone this quarter. And just a few weeks ago I was in Oklahoma to mark the start of the Cushing extension of our Keystone pipeline system. And I think you'll remember I announced the start of the commercial operations of that portion of the pipe in our last quarterly call. This extension expands the capacity from 435,000 barrels per day to 591,000 barrels per day. And shippers have entered into binding contracts on the first 2 phases of the project of 530,000 barrels a day, or about 90% of that capacity is already spoken for.

And we continue to progress the Keystone XL project on a number of fronts. There's now greater clarity in the regulatory process for the expansion through the Gulf Coast. We were very pleased the US State Department committed to concluding its review of Keystone by the end of this year. And two weeks ago the State Department issued its supplemental draft environmental impact statement. And that report provides additional information and thousands of pages of additional detail, analysis of key environmental issues. But the fundamental conclusion the State Department reached last spring in its draft report has not changed. The project conclusions were that it would still have a limited environmental impact.

We expect completion of the environmental review in July or August, and from there, there will be a 90 day national interest determination period. I'm confident that the Keystone XL project will pass that test and that we'll receive a positive decision by the end of the year. The President of the United States this spring said that they will continue to rely on Canada as a steady and stable and reliable supplier of oil. And I think our Prime Minister said it even better after his meeting with the President. He said that the US faces a choice between the nation's receiving its ongoing needs for imported crude oil from unstable sources such as the Middle East, or from the most secure, most stable and friendliest location, which is Canada. The choice is clear, and TransCanada's Keystone pipeline can help provide that energy security. As well, it creates 20,000 jobs and injects CAD20 billion into the US economy without CAD1 of government support. So clearly, our view is this project is in the public interest.

Moving over to our gas pipeline business. Following the start of operations of the Groundbirch natural gas pipeline in late December, I am pleased to report that we began construction of the Horn River pipeline last month. Both Groundbirch and Horn River have contracts to ship just over 2 billion cubic feet a day of BC shale gas to markets. Part of this total includes a new agreement to ship another 100 million cubic feet a day, growing to about 300 million cubic feet a day by 2020. This new project will require us to extend our Horn River pipeline by about 100 kilometers deeper into this prolific play at a cost of about CAD265 million.

Further development in Alberta and British Columbia is on the horizon. We have filed several applications with the National Energy Board to expand our pipeline network to accommodate growing volumes and throughputs. TransCanada is expected to invest about CAD475 million in these various projects over the next few years.

Moving over to Mexico. Our Guadalajara pipeline project down there continues to move forward. We increased our investment in the project through the addition of a CAD60 million compressor station that CFE required to expand its gas capacity, and the pipeline isn't even complete yet. Construction is now about 90% complete and we should be operational next quarter. The CAD420 million project will move gas from Manzanillo to electric generators and to supply Mexico's second largest city in Guadalajara.

Over to the Mainline, TransCanada filed an application with the National Energy Board in late January for approval of revised interim tolls for its Canadian Mainline effective March 1, 2011. In February, the National Energy Board approved TransCanada's revised interim toll application. These tolls were effective March 1 and were consistent with the approved 2007 to 2011 settlement. We filed an application this morning for approval of final tolls that is consistent with this five-year existing settlement. And it is aligned with our current interim tolls. We have worked, as you know, very hard with our shippers over the last many months and while we've agreed on many concepts, unfortunately we've not yet been able to reach agreement on new tolling concepts. It is our current attention to file a more comprehensive rate review application with the National Energy Board later this year that will address tolls for 2012 and beyond. The question that I'm most commonly asked these days is, are your costs going to be recoverable in the Mainline. And I think what's important to remember is the Mainline is a regulated utility and it's my belief that given the scope and importance of that asset, it will remain regulated for a long time to come. Its costs were all prudently incurred and they were all improved by the regulator. And therefore, these costs are recoverable, as they have been historically.

The Mainline is a very important piece of the North American gas delivery system. Evidence of that need for the system was demonstrated well in the first quarter where the system receipts averaged about 4.2 billion cubic feet a day and peaked at about 5.4 billion cubic feet a day. And has, by far, still the single largest long haul gas system on the continent. Total deliveries east were about 6.6 billion cubic feet a day. In addition we recently concluded a successful open season for the Mainline that resulted in agreements to ship 220 million cubic feet a day of Marcellus shale gas to eastern markets. And we just wrapped up another open season for the Mainline that is expected to lead to contracts for an additional 150 million cubic feet a day of Marcellus gas that will make its way on to Ontario markets, and perhaps further than that.

On the northern gas front, the Alaskan pipeline team continues to work with its shippers to resolve the conditional bid that we received as part of the project's open season held last summer. And we are working at completing tasks, together with our partner Exxon Mobile, in many areas in preparation for a filing which will be filed with the Federal Energy Regulatory Commission by October of 2012. Last month, the MacKenzie Valley pipeline project was approved the National Energy Board, marking the end of a long federal regulatory process. The project sponsors are now preparing for discussions with the federal government on a fiscal framework that would allow the project to move forward.

Over on the power side, next week, we will officially mark the start of commercial operations of the Coolidge power plant in Arizona. Power produced at Coolidge will be sold to a local utility as part of a 20-year power purchase agreement. The CAD500 million generating station will provide peaking power to the area residents when it is needed. The remaining stages of Cartier Wind Project in Quebec are nearing completion. The final two stages of the 590-megawatt project are expected to be operational in December 2011 and December 2012, respectively. Cartier Wind is 62% owned by TransCanada and, like Coolidge, all of the power produced at Cartier will be sold to Hydro-Quebec under a 20-year power purchase contract.

Over at Bruce, plant commissioning is underway at Unit 2. As refurbishment work enters its final stages, construction of Unit 2 should be complete in the second quarter of this year. Bruce expects to load fuel into Unit 2 in the second quarter of 2011, synchronized to the electric grid by the end of 2011, and begin commercial 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 on Unit 1 in the third quarter of 2012. Plant commissioning and testing are underway and will accelerate at the end of the second quarter when construction is expected to be completed. TransCanada's share of total capital costs still is expected to be CAD2.4 billion.

On the financial side, earlier this week, TransCanada announced that it sold a 25% interest in both its Bison Pipeline and Northwest Gas Transmission System to TC Pipelines LP for $605 million. The purchase price included CAD81 million of GTN debt. And the sale is expected to close in May and is subject still to certain closing conditions. The proceeds will be used to help fund our near term capital needs. Going forward, our goal is to maximize shareholder value by using our growing internally generated cash flow as well as our debt capacity to fund growth. If additional funding is required, we will consider further asset sales to our LP, as we did with Bison and GTN, or other portfolio management activities. Earlier today, we announced that we would no longer issue common stock from Treasury under the dividend reinvestment program. As we've stated before, we do not believe we need any additional common equity to fund our existing capital program.

Our funding requirements over the next three years, we believe, are very manageable. Our substantial and growing internally generated cash flow, our ability to access senior debt, preferred shares and high spread security markets on very competitive terms provides us with significant flexibility going forward. In 2014 and beyond, our significant discretionary cash flow will be directed to further enhancing financial strength and flexibility, incremental growth opportunities, and ongoing dividend growth.

So to wrap up, and as I told our shareholders this morning, we have a clear path for growing this Company through our enviable portfolio of long life assets that are critical to the supply and delivery of energy across the continent. We're well positioned to benefit from a continuing rise in power as economic activity recovers. And we have completed nearly CAD10 billion in projects that have started or will start soon over the coming days. And we have CAD10 billion of high quality, contracted projects that will be completed in the next two to three years. Projects that will deliver predictable, stable, long term cash flow.

In the longer term, we have three very attractive and growing businesses to reinvest our CAD3 billion to CAD4 billion of annual cash flow. Reinvestment that will be done, as we've always said, in a disciplined fashion and in a way that allows us to live within our means. If we are successful in executing on those priorities, we will grow cash flow, earnings and dividends which ultimately leads to share price appreciation and growing long term shareholder value.

And with that, I'll turn the call over to Don Marchand who will provide you with some additional details on our first quarter 2011 financial results. Don?

Thanks, Russ, and good afternoon, everyone. Before I expand on the details of our first quarter, I'd like to draw your attention to a few key themes. First, TransCanada's diverse set of high quality infrastructure assets generated significantly higher comparable earnings and cash flow year-over-year, even though a portion of our business continued to be impacted by lower power prices in natural gas storage spreads.

Second, I will reiterate Russ's comments earlier. We continue to successfully advance our CAD20 billion capital program that will further contribute to earnings, cash flow and dividend growth in the future. Over CAD14 billion is now invested in the program and about CAD10 billion of these projects either begun or are about to commence operations. Both the Wood River, Patoka and Cushing Extension phases of Keystone, the Halton Hills and Kibby Wind power facilities, and the Bison and Groundbirch natural gas pipelines were all generating significant EBITDA in the first quarter of 2011. Coolidge and Guadalajara are both expected to enter commercial service in the second quarter.

Third, TransCanada's financial position and access to capital remains strong. Earlier this week we announced a $600 million asset sale to our sponsored MLP, TC Pipelines, which in turn successfully plays $300 million of common units in a public offering that will close on May 3. The proceeds from this drop down will put a significant dent in our financing needs for 2011.

Looking to 2012 and 2013, in addition to our growing internally generated cash flow, we are well positioned to opportunistically fund the remainder of our current capital program with no additional common equity. Options include further drop downs to TC Pipelines, portfolio management activities, senior debt, hybrid securities and/or preferred shares.

I'd now like to take the next two minutes or so to elaborate on these themes and our first quarter 2011 results. Comparable earnings in the period were CAD425 million or CAD0.61 per share compared to CAD328 million or CAD0.48 per share in 2010, an increase of 27% on a per share basis. Incremental earnings from CAD9 billion of newly commissioned assets, combined with improvements in many of our existing core businesses, contributed to the significant increase in first quarter 2011. Specifically, the startup of Keystone, Halton Hills, Bison, Groundbirch, and the second phase of Kibby Wind, higher power prices realized in Western Power, higher return on equity on a thicker equity component for the Alberta system, and lower pipeline business development costs. These increases were partially offset by a reduction in unregulated natural gas storage revenues and higher interest expense.

I will now briefly review the business segment results at the EBITDA level. The natural gas pipelines business generated comparable EBITDA of CAD796 million in the first quarter compared to CAD768 million in the same period last year. The year-over-year increase reflects incremental EBITDA from Bison, a higher equity return on a thicker equity component for the Alberta System and lower expenses related to the Alaska pipeline project.

Moving to oil pipelines. As mentioned last quarter, we began recording EBITDA in both the first and second phases of Keystone at the beginning of February. We are very pleased to have this marquis asset fully operational and contributing significant earnings and cash flow. 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. In the first quarter Keystone reported CAD99 million in EBITDA.

Energy generated comparable EBITDA of CAD354 million in the first quarter compared to CAD259 million in the same period last year. The CAD95 million increase was primarily due to higher realized power prices in Alberta, increased generation volumes and lower operating costs at Bruce A, and new earnings from Halton Hills and Ontario in the second phase of Kibby Wind in Maine. This was partially offset by lower realized power prices, lower plant availability at Bruce B, and reduced revenues from Alberta based natural gas storage.

In early January 2011, the operator of the Sundance A power plant declared force majeure on units 1 and 2 effective mid-December 2010. And in February 2011, notified TransCanada the units could not be economically returned to service. TransCanada does not agree with this claim and has disputed both matters under the binding dispute resolution process provided in the power purchase arrangement. As the limited information TransCanada has received to date does not support these claims, TransCanada continues to record revenues and costs under the PPA as though this event was a normal plant outage. Comparable EBITDA first quarter included CAD39 million related to the Sundance A PPA.

Now, turning to the income statement items below EBIT on slide 23. Comparable interest expense in the first quarter was CAD210 million compared to CAD182 million last year. The CAD28 million increase reflects decreased capitalized interest related primarily to Keystone, and incremental interest expense in new debt issues of $1.25 billion in June 2010 and $1 billion in September 2010. In the first quarter, CAD97 million of interest was capitalized to assets under construction compared to CAD134 million for the same period in 2010. As we have seen, 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. Comparable interest income and other of CAD31 million in the first quarter of 2011 increased by CAD7 million compared to the same period last year. The increase reflects higher gains realized in 2011 compared to 2010 from derivatives used to manage exposure to foreign exchange fluctuations on US dollar income.

You will have noticed this quarter that we've modified slightly our definition of comparable earnings to exclude unrealized gains and losses on all derivatives related to risk management activities. Previously, we excluded unrealized gains and losses on US power and natural gas storage derivatives and natural gas storage inventory. But have now expanded this to similar fair value adjustments for all commodity prices, interest rates, and foreign exchange. While these derivatives provide effective economic hedges from underlying exposures, they do not qualify for hedge accounting treatment. Therefore, in accordance with GAAP, we must reflect changes in the fair value of these instruments and net income each period. These fair value or mark-to-market changes reflect a point in time valuation that is generally not representative of locked in margins that will be realized on settlement and therefore, do not meaningfully reflect our underlying operations. As such, we've excluded them from comparable earnings. It is important to note that the realized gains and losses that are recorded when these risk management derivatives are settled continue to be reflected in comparable earnings.

Comparable income taxes of CAD185 million in first quarter 2011 were CAD67 million higher than first quarter 2010, primarily due to higher pre-tax earnings. Preferred share dividends of CAD14 million were CAD7 million higher in the first quarter 2011 due to the issuance of 350 million of cumulative redeemable first preferred shares in each of March and June of 2010.

Moving on to cash flow and capital expenditures on slide 24. Cash flow was strong in the quarter for many of the reasons already discussed in my review of EBITDA. Funds generated from operations of CAD919 million increased CAD196 million or 27%. Capital expenditures were CAD784 million in the first quarter 2011, principally related to Keystone, to Bruce A restart, Guadalajara, and Alberta System expansion projects. For the year, we expect to spend approximately CAD3.5 billion to further advance our CAD20 billion capital program. With our strong and growing cash flow, cash on hand at the beginning of the year, and the proceeds expected from the announced sale of a 25% interest in Bison and GTN to TC pipelines, our capital funding is largely complete for 2011.

Now looking at slide 25, our liquidity and access to capital remains solid. At the end of the first quarter, our consolidated balance sheet consisted of 42% common equity, 4% preferred shares, 3% junior subordinated notes, 51% debt net of cash. At March 31, we had CAD600 million of cash on hand along with CAD3.8 billion of committed 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 37% in the most recent quarter, generating CAD93 million in common equity. With the dividend announcement today, common shares purchased with reinvested cash dividends under TransCanada's dividend reinvestment and share purchase plan will no longer be satisfied with shares issued from Treasury at a discount, but rather will be acquired on the TSX at 100% of the weighted average purchase price. This will serve to reduce further future dilution of earnings and is reflective of the strength of our financial position, the successful advancement of our construction program, and the various attractive alternatives available to TransCanada to finance our current growth portfolio.

Next, just a quick update on TransCanada's decision to adopt 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. Effective 2012, TransCanada has the option to and will adopt US GAAP as an alternative to IFRS. This will help insure the economic impact of our regulators' decisions regarding the Company's revenues and totals will be appropriately reflected in our accounts going forward.

In closing, TransCanada produced a very strong quarter with comparable earnings 27% higher than first quarter 2010. Our unprecedented CAD20 billion capital program is now two-thirds complete, having invested over CAD14 billion to date, with CAD10 billion of these projects significantly contributing to earnings and cash flow in 2011. With the drop down to our MLP, TC Pipelines, our financing plan is well advanced for 2011, and we are well positioned to fund the remainder of our current capital program through 2012 and 2013 without any additional common equity. Finally, in 2014 and beyond, we expect to generate significant discretionary cash flow that can be used to continue to grow the dividend, invest in accretive growth opportunities and further enhance our financial strength and flexibility.

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

Thanks, Don. As noted earlier, at this time we will turn the call back over to the conference coordinator for your questions. And as mentioned earlier, we'll take questions from the investment community first followed by the media. And with that I'll turn it over to the conference coordinator.

(Operator Instructions) Chad Friess of UBS.

Good afternoon. Was wondering if you could provide some color on the current level of throughput on Keystone, how that compares to Q1? And directionally where you would expect that to go over the remainder of the year.

It's Alex here. Since we have opened up the Cushing Extension we are flowing at, give or take, 375,000 to 400,000 barrels a day, and we would expect that to slowly ramp up over the course of the year.

And I think it's important to remember that as of the commencement of commercial operations, we have 530,000 barrels a day of firm contract that have paid for movement irrespective of what flow is. So our cash flow isn't necessarily reflective of the volume movement.

Right, makes sense. Secondly, given the bottleneck at Cushing, there's been a few competing proposals made to get more oil into the Gulf Coast area. Could you comment on how you think the Keystone expansion stacks up from a competitive standpoint, and whether you think there's room for more than one pipe, multiple pipes into the Gulf Coast region?

Sure. Off the bat, our initial proposal for Cushing market link was around 150,000 barrels a day. I think from what we hear from industry experts, ultimately by 2013 or so, there's probably a need for up to around 500,000 barrels a day of takeaway capacity to the Gulf. If there is that interest, we have the ability to up size our offering. But even given that, it looks like there is an opportunity for more than one pipeline. We take a look at this project. We think it is a very competitive project. It has a very low capital cost and we can be in service right around the beginning of 2013. So we think we're a very competitive option. And we've already committed to go ahead because we've received sufficient shipper support to do so. But it's full speed ahead on that project for us.

Sam Kanes of Scotia Capital.

I'll roll two questions into one. It's very broad. Russ, you've had a chance now to settle into your current role. And the question is about structure and the size of TransCanada coming out the other side in 2013, '14. And I look at what Duke did acquiring West Coast, breaking out Spectra, Duke Power, et cetera. And just wondering if you may view or perceive you may have a hold-co discount within your Company now or in the future, does it make sense to look at the size of your Company in several pieces, whether or not a renewable spin-out makes sense or not. And there's both my questions.

I'd say at the current time, Sam, no intentions on splitting the Company or doing any of those things. Currently, there's significant synergies between all parts of our business, both financially and operationally. Looking out into the future, we will do whatever is in the best interest of our shareholders and add the most shareholder value. But I can tell you from my perspective, I've seen the value of operating these companies together. The cash flow from one can fund the growth in the other through certain parts of the cycle and vice versa. Operationally, a lot of the equipment we use, whether we're using a gas turbine to run a compressor or whether we're using it to run an electric generator, it's the same equipment and we see economies of scale by operating those things under one operating tent. So at least at the current time, we think that there isn't a discount on our stock for holding these businesses together and that they are synergistic.

At the financial level, all of our businesses have the characteristic of low risk, stable cash flow. So from a balance sheet perspective they all fit together. And I would suggest that as I've observed some of these other transactions that have occurred, one of the difficulties is holding assets on a balance sheet that have different characteristics and actually require different kinds of balance sheets. We've been very careful to construct our energy business, for example, in a way that has, from a cash flow perspective, the same kind of characteristics as a regulated pipeline or a contracted pipeline. So they are all very similar from that perspective and I don't think that there's any discount out there at the current time. We actually, I think, get some positive benefit from the size and scale and scope of the operation and then the cash that it generates.

Pierre Lacroix of Desjardins Securities.

Thanks, a quick one. Just want to confirm the CapEx profile over the next couple years. You mentioned CAD3.5 billion in 2011 and how it's going to roll out into 2012 and 2013, thanks.

Yes, Don here. Looking at something in the CAD5 billion range for 2012 and about CAD2.3 billion for 2013. Those can move around depending on the Keystone spend profile but that's the order of magnitude in those two years.

Thanks. And one last, given your DRP, the decision you took on your DRP, reflecting some kind of more confidence in your financing ability over the next couple of years, are you more open now to take a look at acquisitions opportunity either in the power business or the pipeline?

I'd say that we're focused on our existing capital program. So we've got about CAD10 million of work in progress that needs to be completed over the next two to three years. To the extent that good investment opportunities arise on the horizon, we'll look at those but they're certainly not our focus today. As we get out in the 2013-2014 range we'll be looking for new investment opportunities and acquisitions, will be part of that slate of opportunities that we look at. And certainly we would have to start looking at some of those today because it takes that long to actually look at and close certain transactions that look like that. But our current focus is on what's in front of us today. We've got some hard work left to do. We've got CAD10 billion of projects.

And, quite frankly, our team has continued to find new investment opportunities in our core businesses around Keystone X. I think Alex mentioned things around the market link projects, we're seeing opportunities potentially attached to Houston market for example, we're looking upstream. Our gas business is generating incremental need for capital to attach new gas supply to it. On the energy side we're seeing continued opportunities for new builds in the various markets that we participate in as people look to move away from coal and add more gas generation. So on our horizon there appears to be a lot of opportunities for development. And I think what the message that we're sending today was, whatever that slate of opportunities is, whether it's development or acquisition, we will finance those in a way that is defined by living within our means, which is our internally generated cash flow, our debt capacity. And then if we need to actively do some portfolio management, use our limited partnerships, we'll do that as well.

Carl Kirst of BMO Capital Markets.

Thank you. Good afternoon, everybody. Nice results. Russ, maybe if I could start just a question on the NEB filing that you did today. Was it potentially a consideration instead of just filing 2011 today to actually do a multi-year filing if indeed a settlement didn't look like it was going to happen? And trying to just get a sense of, are we in a position where negotiations, even though they haven't happened yet, or a settlement hasn't happened yet, are still ongoing? And also if there's any way to firm up a sense of timing. You said later this year we'll be looking to perhaps file that and I didn't know if we could narrow that down at all.

Why I don't let Greg take that one.

So, Carl, we said right in our filing today that we would look to file a comprehensive rate case by October 31. So the goal would be to file a case that is really a full review of all of the cost in the cost of service as part of that application. As well as some structural changes in order to fulfill some of the larger picture issues, which is to have the areas which are the most used on the pipeline with the largest volumes paying for the infrastructure to a larger extent. So we're preparing that case. We are in negotiations. We continue to negotiate. We actively seek to settle with the constituents. We were just unable to get there right now. So we had an obligation to file by May 2 to firm up the tolls for '11. It made sense to firm them up consistent with the interim tolls that are already in place for the year so that the marketplace had consistent tolls for the year. And to continue to work towards something for the longer term. But in parallel to that, because we've been at this for quite a while and we have diverse interests amongst our stakeholders, we thought that it was necessary to move forward with a formal filing, which we'll put it in place in the Fall as we continue to negotiate along those same time lines.

Great. Appreciate the color. And if I could just follow-up one other question. And this is probably more for Alex. And this is really just from trying to reconcile from where we were at the end of last year to today. This is, particularly on the US generation portfolio. And there was a mention that, I think in perhaps the year-end release, there was something on the order of over 11,000 gigawatts hedged contracted for 2011. And it looks like there's only 4300 gigawatts left for the remainder of the year. And I'm trying to better understand what's going on there because part of it is, when you say the 4300 is going to be, perhaps, representative of 60% of our likely generation in sales, that seems to be much lower than last year. And so if you could help give some color on that.

Sure. A couple of things, and Glenn might jump in and talk about this a little bit. But the changes we made were really done from a perspective of attempting give better clarity and better information to our analysts and to our shareholders. In the Eastern, the US business particularly, and maybe I'll contrast it to the Western business, but the Western business we're basically in a business of Marketing the volumes that are produced from our facilities. In the East, we're marketing volumes produced from our facilities, we're buying third party volumes, physical volumes, and we're buying financial products, all with a view of serving our very significant customer load. And as a result, we thought it would be a lot more meaningful to our analysts to actually talk about how much of our owned generation is actually forward sold. Because I think it tended to over inflate if we added all those various sources of supply and treated them as percentage sold. So it was really just an effort to give more clear information to our analysts.

I think the only thing I would add to that, because I think Alex covered it quite well, is that when you were looking at what we had provided previously, that was always an historical look back split between contract and spot. And as Alex said now, we think the better information is to provide a percentage of planned generation. And a couple more points, maybe, to make on that. That as we go forward over the course of the year, normally, and in a normal course situation, you'd be looking to firm up more of that. And remembering that contracts can be anywhere from a year out to a week out. So definitely you would see that number increase. But as Alex also said, a good portion of that is what we would call our back to back sales to our industrial, commercial and wholesale customers. So that's not quite the same as -- the concept of contract versus spot doesn't really hold there but it does inflate the numbers. And lastly, that this 60% is only a point in time estimate, and again that will continue to move going forward. But I think the biggest underlying point to be made there is that we did feel that this was better information for the US power group as opposed to the traditional approach we were maybe taking with the Western power group.

Understood. So we just have some apples and oranges right now between those numbers?

I think it's different how we look at the two businesses differently and how they are maybe exposed differently. And as Alex said, the different streams of power coming in under different contracts to different types of customers, you need to look at it a little differently and we want to make sure we provide the best information possible.

Juan Plessis of Canaccord Genuity.

Great. Thank you very much. With respect to the Sundance PPA, I'm just wondering if you can talk about the timing and the process for the arbitration over that Sundance PPA.

Sure, Juan. I would say that we have in front of us right away, there's a couple of what I would call procedural issues that need to be dealt with in front of our panel of arbitrators. And those are just some issues that I would imagine we'll be able to deal with quite quickly. Call it in, say, a 30 to 60 day period. But the actual meat of the arbitration is a lot more complex process. There's going to be discoveries of documents, examination of officers and so forth. And I would expect that the time line for an ultimate decision on the Sundance A arbitration would probably be in the 12 to 18 month period.

Okay, thank you. That is helpful. My second question, with regard to future potential roll down of assets into TC Pipelines, I'm wondering what assets you might consider rolling down. Would you consider a portion of Keystone to be a possible asset that might be a drop down?

At the current time, we look at all of our US based assets, pipeline assets, as being possible candidates. Some are better than others from a tax perspective and a structuring perspective. But that's not a list that we've shared external to the Company. Those are options that we hold going forward. And as we've said before, it's not an automatic that we make any sales to the LP. They're dependent upon the cash needs at the corporate level. And if selling assets to the LP makes the most sense and is our cheapest form of capital after we've exhausted other means, then we'll look at that. So all of the assets would be in that eligible pool. Some are going to be better than others for various reasons, mostly driven by tax and structuring reasons. But currently, to be more direct with respect to your question, until we get Keystone completed, I don't think it makes sense to restructure that asset and bring other partners into it until you have such time as you've got a stable and running asset. So, generally, what you've seen us sell into the LP, with Bison, for example, we waited until we completed it and it was up and running before we took a look at selling a portion into the Limited partnership. So Keystone interest will probably be some time in the future if that was to be considered at all.

Ted Durbin of Goldman Sachs.

Thank you. First question is, in western Canada, you talked about how weather and outages really drove the big spike in outages, Can you just maybe break that out? How much of the outages is just Sundance? Were there other things? And then go into what you see for supply/demand going forward here.

Yes. I think Q1, losing those Sundance units, obviously, you take that amount of megawatts out, especially baseload megawatts out of the market, and that resulted in really a give or take a CAD20-megawatt hour across-the-board increase in power prices. All the way out the curve, 2011, 2012, 2013. But then on top of that, I think Q1 was somewhat exacerbated that we did have some very cold weather in Alberta. And on top of that, we actually lost a number of other units in addition to the Sundance units. And that pushed, call it, the equilibrium price from the low CAD60s up into the mid CAD80 range for an average price that we saw in Q1. But yes, going forward, forward markets are looking for the next 2 or 3 years in the low CAD60 range and that seems like a pretty reasonable view to us.

That's very helpful, thank you. And then if I could just stay on the power side here. You said at Bruce B a lot of the contracts rolled off at the end of 2010 so this is our first look at that roll off. How many contracts were actually rolling with the vintage of them? And so we had CAD53 a megawatt hour this quarter versus CAD58 to CAD60 in 2010. Is that a good run rate going forward or is there a lot more rolling off in '11 and '12?

We've got most of them either rolled off or we bought them back in a low price environment. So you're going to see that number over the next couple of years will probably move down to the Bruce B floor price of give or take CAD50. In that range. And that probably occurs over a couple of years. Okay, thanks very much.

Matthew Akman of Macquarie.

Thanks, guys, couple of questions. One on Ravenswood. I'm just wondering why the US power earnings weren't a little bit better given more capacity available to offer into the capacity market from Ravenswood this year.

Sure. And we're going to obviously see a change going forward with this new demand curve reset decision that is coming out of FERC. But I think basically what happened is we got some extra megawatts because we were seeing the roll off of that Unit 30 outage that we had affecting our claim capacity. But then on top of that, the other big component which, obviously, affects capacity markets is peak demand. And as part of the ISO process, they had come to a conclusion that there had been a modest reduction in peak demand in the winter season, which offset the incremental megawatts that we were getting back by the Unit 30 outage rolling off.

Okay, thanks. Any thoughts on timing for the change in payments vis-a-vis the FERC proceeding?

We obviously took a position after the decision came out that we felt, although were we very happy with the decision, and we thought it vindicated a lot of the -- or supported a lot of the positions we had taken in that process, we were a little disappointed that the FERC allowed the ISO such a long time into November to implement the decision. So we certainly argued that it should have been, there should have at least been an interim refiling that would have seen us benefit quicker. I think we're expecting now, we're hoping to start seeing some of the benefits of the demand curve reset this summer, probably August or so.

Okay, great thanks for that. And just one separate question. Probably Don, this is for you. Obviously I think it's very good that you can show financial flexibility by dropping assets down into the LP at an attractive valuation. But my question is, how much more of that do you even really need to do, given that Keystone spend is, even if you get a decision at the end of this year, effectively delayed probably 6 or 12 months? Do you really even need anymore excess equity on your balance sheet? Cash flow is so strong, especially this year.

Yes, the direction of the arrow is pointing in the right way here. We'll watch cash flow. The credit metrics still need some improvement. The FFO to debt one, in particular. And as construction risk mitigates here, we're feeling more and more confident that we're getting near the end of it here. So it's really point in time and any other opportunities that might pop up and any speed bumps we might hit. But given what's on the plate right now, we're in pretty good shape here. To the extent we need any more subordinated capital, and we've outlined the hybrid security market, the prep market, and again for the drop down. So these are all fairly quick things we can do opportunistically. So the answer to your question is, yes, we feel we're getting near the finish line but we may not be completely there.

Andrew Kuske of Credit Suisse.

Thank you, good afternoon. My question's for Russ or for Greg. And obviously your natural gas footprint touches a lot of different basins across North America. And I'm just curious as to your perspective on what areas are really surprising to the upside on incremental development? And what do you believe the drivers are on any upside that you're seeing?

When you look at North America in total, most areas that have shale development also have conventional supply falling off. And they're staying relatively flat from a total production perspective. The two areas that shine in that environment are Marcellus, which is all incremental supply, and the WCSB, where we're seeing significant new find, significant development. And fortunately for us we're able to tie a good portion of that into our system. As we all see the richer plays of more liquid rich plays are driving development. The pure dry gas plays are a little more difficult to get done economically. So areas like the Deep Basin in Alberta which are quite rich are seeing more and more development, but we're also seeing more of the conventional areas of Alberta using the new technology, and seeing development there. So we've been able to tie in significant new volumes. We've got more projects on the way and we're hoping that all of that will help bolster our infrastructure system.

So just as a follow-up to that, there have been a couple large joint venture arrangements. And in some cases offshore entities with North American companies that already own assets and resources in western Canada or in the Marcellus. Do you see a continuation of that trend, and could that even further accelerate the development of those basins?

I think so. When you hear the CEOs of some of the larger North American companies speaking, such as Encana, they refer to their interest in continuing to find joint venture opportunities. They've got lots of development acreage. And in the low price environment, it takes significant capital to move forward to either hang on to leases or to do some initial work to firm up reserves. So I think you will see more of that kind of development.

Linda Ezergailis of TD Securities.

Thank you. Just some clarifications around your CAD265 million Horn River extension. Would that be part of the Alberta System rate base or would it be more contracted?

That would be rolled into the Alberta rate base. One of the big advantages that we have as a result of, as you recall, a couple of years ago, the change of jurisdiction to NEB jurisdiction for the Alberta System is we are able to reach beyond the Alberta border, whether it's into Saskatchewan or whether it's into BC or elsewhere, in order to economically tie in new production into the existing system. And that being the most liquid point in North America. And producers seeing they can get immediate liquidity by tying their volumes into our system. So we'll continue to see, I think, expansions into Horn River, into Montney, and into other new developments. And we certainly have other discussions underway to continue to grow our Northeast BC business.

Thank you. So that CAD265 million would be part of the CAD475 million of identified Alberta System projects?

I don't have the numbers in front of me, but I suspect the answer is yes.

Okay, thank you. And then just a follow-up question on your power side. Maybe this is a question for Don. The CAD39 million of earnings, is that after-tax or EBITDA?

That's EBITDA, Linda.

And what was the after-tax number?

It's probably about CAD0.04.

Yes, after-tax, Linda, it would be the equivalent of about CAD0.04 a share. And, Linda, I'd just clarify for you, as well, I believe the Horn River project you were referring to, as well as the CAD475 million, add those two numbers together. So in other words, the Horn River project is not part of the CAD475 million, so you've got total incremental spend in the neighborhood of CAD700 million between those projects outlined in the quarterly.

Robert Kwan of RBC Capital Markets.

Thank you. Just first question on the Mainline. It's been a bit of a flip flop in support and I'm just wondering directionally, maybe comparing it to your proposal from late last year, what are some of the things that are different about what you're negotiating right now? And Russ you mentioned about having agreed on many concepts, obviously still lots left to go. But can you just talk a little bit about what some of those concepts where you found agreement?

I'll let Greg start and I'll jump in here where I might want to add a few things.

I think it's fair to say that it's included in our filing that the support that we had in December was primarily western Canadian support and others supporting moving forward. I think it would be right to say that all parties are interested in seeing the Mainline remain competitive and get to a steady, stable toll that's lower than the toll we have today. And there's strong interest in reaching an agreement. We were able to obtain significant market area support as a result of the work we've done over the last couple of months. But, unfortunately, we weren't able to garner really unanimous support that we would have needed to push forward a settlement right at this time. So it was necessary in order to meet the filing deadline with the NEB, that we move forward to firm up 11 tolls so that marketplace has consistent tolls for the year, and then to focus on 2012 and 2013. At this point, because you have so many diverse stakeholders, it makes sense to proceed to prepare for a filing in the fall that would address the longer term, at least '12 and '13 and look to deal with all of the components of our cost of service. And in parallel, continue discussions with all of our stakeholders to see if we can resolve at least some, if not all, of the components of that filing before that time.

The only thing I'd add is that the differences between December and what we were trying to achieve in the last few weeks, and the change of support from, say, migrating from West to East, if you will, I think it was due more to subtleties of language and those kinds of things. Which tie us into obvious concerns about how things will be actually defined for the long term. And again, one of our reasons for moving down the filing route is we'll solidify those long term subtleties. The concepts of moving costs out of long haul zones into both Eastern and Western zones, those are the kinds of concepts we're saying that generally people can get their heads around because they make some sense. But the subtleties around how you define some of those things and the term structures and those kinds of things are probably more where we can't find consensus among all the parties. And therefore, we're probably in a better position to try to define them with the regulator as part of the process and not outside of the process.

Okay. Thanks for that. The other question I had was about the funding/the DRP. And just wondering your philosophy on how you think about the DRP. Is it just something that you feel you're comfortable frequently turning on and off? Or should we really take your decision to turn it off as a feeling that you're feeling really good about the funding plan over a multi-year period notwithstanding that CapEx might be a little lower this year, you've got CAD5 billion coming up for 2012.

Definitely the latter, I would consider it as. We don't take turning the DRP on and off lightly. And we put it in place a few years back for a specific reason. We knew we were coming into a CAD20 billion unprecedented capital program and that we needed that stability to maintain our ratings and to make ensure that we had the capital to continue to fund our capital program. That need no longer exists and we don't anticipate having that kind of need in the future. So I would say unless something like that arose again, you wouldn't see us putting it back in place. Don, do you want to add anything?

Yes, I'd agree with that. And on an economics basis, we have other alternatives that are flexible and cheaper at this point as well.

Steven Paget of FirstEnergy.

A question just on throughputs on the Canadian Mainline. Through much of 2010, what you'd call the summer season, Mainline throughputs or receipts in western Canada were about 3 BCF, which almost looks like it's a group of longer contracts that are under rating, if you will, that 3 BCF a day. Does the Mainline have similar long term contract support to keep running at about 3 Bs a day or more?

I'd say right now, Steven, we're running about the same as last year at about the 2.9 level. We do have some significant long term contracts coming due here in the fall that, say, for the bulk of this year that most of those contracts remain in place. Right now, we see ahead of where we thought we would be at this time last year when we were forecasting, thinking more, as you say in the 3, 3.1 range. And right now we think we're likely to come through the year in the more 3.3 range.

3.3, you mean?

Yes.

Carl Kirst of BMO Capital.

Just a couple of quick follow-ups, if I could. The first is just on tax rate, Don. I think around February you'd indicated maybe you expect a low 20% tax rate all-in for the year, maybe for the next few years. Is that still the case even with a little bit higher rate here in first quarter?

It is higher and the principal driver is the Canadian regulated pipes, primarily the Mainline. It's a unique structure where we don't book taxes under Canadian Reg assets on the traditionally deferred tax basis. We basically book what we pay in cash tax and add that to our revenue requirement. So the bulk of the change upward is primarily due to a new view on a tax collection on the Mainline tolls. So where we are right now, I would expect something going forward, something that looks more like the Canadian statutory rate in that 25%, 26% range.

Overall, all-in for the year, you mean?

Yes, probably the 26% range is probably something that's a better guess right now as to where we end up.

And just to be clear, though, that is basically coming from the Mainline which is going to be passed through?

That's correct. In terms of the rest of business, again, something in that range from a Canadian statutory rate is probably appropriate as well, 25%, 26% range. The headline tax rate will jump up and down depending on, again, this Canadian regulated position. To the extent we collect less taxes, it'll drop. To the extent we need to collect more taxes, it'll pop-up. Color coded. Aside from the Canadian Reg business, I'd use something in that 25%, 26% range.

Okay, that's helpful. And then second question, if I could, and I apologize if this was already mentioned. But we've seen a little bit of some shift, perhaps, in the California renewable market. Is there any update perhaps or color on Zephyr maybe?

What are you referring to?

The merchant wind credits, for instance. The idea that maybe California is perhaps more open to taking renewables outside of the state within their portfolio. And I didn't know if that was creating some additional certainty around Zephyr or not.

We are right now still monitoring that and we're in pretty close discussion with the utilities. The big question for us is going to be how much, regardless of what the regulatory environment is, how much interest do the California utilities have in contracting out of state. So I would say on that one, probably continue to hold tight on that for a quarter or so, and we'll probably have a little better feel on that.

Linda Ezergailis.

Thank you. I apologize if this is in the Mainline final toll filing. But maybe you can just clarify, for the CAD1.89 toll to be in place this year versus a CAD2.07 that would allow you to achieve all your revenue requirements, currently, what would be your expectation of under-collecting revenues, if at all, if you exclude the 2010 CAD237 million under recovery?

So you'll recall in 2010 we had an under recovery. I think, it's around CAD239 million. That number is in the 2011 tolls. However, we had some over recovery due to the higher than expected volumes earlier in the year. And then we forecast what the rest of the year would be. So in order to keep the toll flat to the interim tolls and stay within the four corners of our five year settlement agreement, the toll would have gone to CAD2.07. We've asked the NEB to hold it at the CAD1.89. This is the toll that Don -- and I think on balance, the under recovery should be in the range of, assuming you carried forward the 2010 under recovery and hopefully a little bit less, depending on how the volumes turn out for the rest of the year. And then we would go into the long term toll rate case. And in that case, where we were hoping to bring tolls down substantially, a deal with that under recovery amount as just one of the issues to be dealt with during that rate case.

Okay. So you expect to be flat for 2011 to maybe up a bit. So a CAD200 million under recovery in total could be a reasonable number to assume for entry in 2012?

As I say, it's difficult to predict with so many months left in the year for volumes but I think from a planning perspective that's not a bad reach.

We'll now take questions from the media. (Operator Instructions) Samantha Santa Maria of Platts.

Thank you, my questions have been answered.

We have no further questions registered at this time. I would now like to turn the meeting back over to Mr. Moneta. Please go ahead.

Thanks very much and thanks to all of you for your interest in TransCanada. We appreciate your participation today. Terry, Lee, and myself have been at the site of our AGM, but we'll be heading back to our offices. To the extent you have any follow-up questions we'll be happy to try to deal with those later this afternoon. Thanks again for your interest and we look forward to talking to you in the not too distant future.

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