TC Energy Corp (TRP) 2012 Q1 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2012 first-quarter results conference call. I would now 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 afternoon, everyone. I'd like to welcome you to TransCanada's 2012 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, 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. A copy of the presentation is available on our website at www.TransCanada.com and it can be found in the Investors 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 any additional questions, please re-enter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments, and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations, for your detailed financial models, Terry, Lee and I would be pleased to discuss them with you following the call.

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

Finally, I'd also like to point out that during this presentation we will 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 US 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 it's operations.

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

Thanks, David. Good afternoon, everyone, and thank you for joining us. Delivering critical energy infrastructure, that was the underlying theme of my address to our shareholders at our annual meeting today. And since the spring of 2010, we have brought on about CAD10 billion of new projects. Combined, those assets are expected to generate about CAD1.1 billion annually in EBITDA. A further CAD13 billion of projects are expected to become operational by 2015. So, that's the theme of what we're up to at this company.

With respect to the first quarter of 2012, TransCanada performed, I think, very well in a challenging environment. The billions of dollars of new assets that we placed into service are generating significant earnings and cash flow. That said, we had some lengthy planned maintenance outages at Bruce Power. We had one of the warmest winters ever and we've got historically low natural gas prices, and those things did have an impact on first-quarter earnings. Our expectation is that natural gas prices will remain low for at least some time. On the positive side, we have two refurbished nuclear reactors at Bruce Power that are close to producing electricity and other new assets are under construction and an expected growing demand for energy, and inevitable higher prices in the future position us very well for continued growth in cash flow, earnings and dividends going forward.

During the first quarter, comparable earnings were CAD363 million or CAD0.52 a share. And comparable EBITDA was CAD1.1 billion and funds generated from operations were CAD841 million. And again today the Board of Directors declared a quarterly dividend of CAD0.44 per common share for the quarter ending June 30, 2012. Don will discuss our results in a bit more detail in a few minutes, but before he does that I'd like to touch on the progress we've made on a number of these new projects that I mentioned at the beginning.

First of all, the Gulf Coast Project, development of our Keystone system continues to progress with our announcement in February that we had been -- that what had been the Cushing to Gulf Coast Section of the Keystone pipeline project had its own independent value at the market place and would be constructed as a standalone project called the Gulf Coast Project. The approximate cost of that 36-inch line is about CAD2.3 billion and subject to certain regulatory approvals. We anticipate the Gulf Coast Project to be in service in mid to late 2013. Included in the cost, that CAD2.3 billion cost, is CAD300 million for the about 47-mile Houston lateral that we'll transport oil to those refineries in Houston.

As you are aware, US crude production has been growing significantly in states such as Oklahoma, Texas, North Dakota and Montana and those producers do not have access to enough pipeline capacity to move this production to the larger refining markets in the US Gulf Coast. And the Gulf Coast Project is meant to address that constraint and will also allow refineries to access lower-priced domestic crude production and avoid paying a significant premium that they're paying today for world priced oil from foreign producers. And we're working on acquiring the final permits needed to get that project underway and we'd expect to commence construction later this summer with an expected in-service date of some time in mid 2013, as I said.

On the Keystone XL front, I expect that very shortly we'll be filing an application for Presidential Permit with the US Department of State and it will be an application from the US/Canada border in Montana to the Steele City in Nebraska. So, we'll supplement that application with an alternative route in Nebraska as soon as that route is selected. The application will include the already reviewed route in Montana and South Dakota. The over three-year environmental review for the Keystone XL system completed last summer was the most comprehensive process for a cross-border pipeline that we're aware of, and based on that work, we would expect a cross-border permit should be processed expeditiously and that a decision should be made once the new route in Nebraska is determined.

Earlier this month, legislation was passed in Nebraska that allowed TransCanada to re-engage with the state's Department of Environmental Quality. That legislation was signed into law by Governor Hyman recently and the Company will continue to work collaboratively with the Nebraska Department of Environmental Quality in determining an alternative route for the Keystone pipeline that avoids certain sensitive areas of the Nebraska Sandhills.

Last week, TransCanada filed a report on alternative routing with the Nebraska DEQ and the DEQ will manage that process going forward with public input and their ability to provide information and determine what is the most appropriate route. Once the route is identified and determined, Governor Hyman will decide whether or not it's appropriate and would at that point inform any federal agencies involved in the approval of the pipeline of his ultimate decision. Our company has been working in assessing the routing in Nebraska since November of 2011 following the State Department's notice to delay the decision on the presidential permit until we adjusted the route in the Sandhills. If a presidential permit is granted next spring, we would expect that the Keystone XL pipeline would be operational in late 2014 or early 2015. The capital cost of that project is now estimated at CAD5.3 billion and that's unchanged from where we were before, and we've invested about CAD1.5 billion in that project as of March 31, 2012.

We continue to develop new projects that are attached to our Keystone Pipeline System. Last month TransCanada launched and concluded an open season to obtain binding commitments for the Keystone Hardesty terminal. That's a 2 million barrel project located in Hardesty, Alberta, and will provide new infrastructure for Western Canadian producers to access the Keystone Pipeline System. And TransCanada is currently reviewing those open season results and we remain very optimistic that those results will turn into contracts and we expect the Keystone Hardesty terminal to be operational by late 2014 or early 2015.

Our entire Keystone system provides the backbone to connect all of this new supply, both in Canada and the US, and transport it to key North American markets providing TransCanada with, I think, are very significant opportunities to add laterals, terminals, and connections well into the next decade. Our customers continue to ask us to look at markets we don't serve today, both onshore and offshore, and that does include looking at existing markets in Eastern Canada and all of those opportunities I can tell you that we will aggressively pursue in the coming months.

Moving over to gas. In the Alberta System, the NEB approved about CAD330 million of projects in for the Alberta System in the first quarter. This is a portion of the previously reported CAD810 million of projects for the Alberta System filed in 2011, so there is still about CAD500 million of applications that are pending and awaiting approval.

TransCanada 's firm commitment to transport about 3.4 billion cubic feet a day from Western Alberta and Northeast British Columbia by 2014 and request for additional volumes on the Alberta System from both the northwest portion of the western sedimentary basin and Northeast British Columbia have also been received. Infrastructure to connect Western Canadian sedimentary basin to supply to growing market continues to be pursued, particularly to support the further development of the Alberta oil sands production. There will be new gas needed for that, gas fire generation, and to supply proposed LNG export facilities off the West Coast of Canada.

Canadian Mainline on June 4, 2012, an NEB hearing will begin on TransCanada's application to change our tolls and services for the Canadian Mainline, including a significant lower long-haul toll for the years 2012 and 2013. The hearing is expected to conclude in September with a decision in late 2012 or early 2013. TransCanada is working to construct a new pipeline infrastructure to provide Southern Ontario with additional natural gas supply for the Marcellus shale basin. The NEB is continuing to access that application for the project and that application was filed late last fall. Assuming the project is approved, construction is scheduled to begin in July of this year and we should be able to complete it in November. The capital cost of the Marcellus facility expansion is approximately CAD130 million.

Up in Alaska, on March 30, Exxon Mobil, ConocoPhillips and BP and TransCanada announced that they're working together on the next generation of what we call resource development in Alaska. The four companies agreed on a work plan aimed at commercializing North Slope natural gas resources within the Alaska Gas Inducement Act framework. Because of the rapidly evolving global market, large-scale liquefied natural gas exports from South Central Alaska will be looked at as a viable alternative to natural gas pipeline through Alberta and on to the lower 48.

Moving to Mexico, this past February we announced plans to build, own and operate the Tamazunchale Pipeline Extension in Mexico. That CAD500 million, 235-km pipeline has contracted capacity of about 630 million cubic feet a day. It connects to TransCanada's existing Tamazunchale Pipeline linking up with Mexico's existing pipeline grid and provides natural gas to CFA in a combined cycle of natural gas generation facility. The Tamazunchale Pipeline Extension demonstrates our continued commitment to develop Mexico's energy infrastructure to meet the growing requirements for increased natural gas supply. That project is underpinned by a 25-year natural gas transportation service contract with Mexico's state-owned power company, and we would expect that pipeline to be operational in the first quarter of 2014.

Moving now to energy. A significant milestone was reached by Bruce Power in mid March. The Company received authorization from the Canadian Nuclear Safety Commission to power up unit two. This effectively ended the construction and commissioning phase of the project and represented the final major step necessary in bringing the reactor into service. Final safety checks for unit two are currently being completed and work is underway to prepare the reactor for synchronization to Ontario's electric grid. Bruce Power anticipates the unit will start commercial operations in the second quarter of this year and refurbishment of the unit one reactor at Bruce is progressing on time and is expected to begin operations in mid third quarter of 2012.

TransCanada's share of net capital cost of the refurbishment is expected to still be CAD2.4 billion, and once the work is complete, Bruce Power will be one of the world's largest nuclear facilities generating more than 6200 megawatts or about 25% of Ontario Power's needs. Bruce Power consists of two generating stations, Bruce A and Bruce B, with each station housing four nuclear reactors. Six of those reactors are currently operational, producing about 4700 megawatts of power, and TransCanada owns 49% of Bruce A and 32% of Bruce B. Bringing Bruce Power unit two into service further complements TransCanada's significant and growing energy investments in Ontario.

The Company currently owns and operates the approximately 700 megawatt Halton Hills generating station. It has a 50% interest in the 550-megawatt Portland energy center in Toronto. And we recently announced a CAD470 million agreement to purchase nine Ontario solar generation projects. The Bruce Power Restart Project, Halton Hills [PAC], and the solar project, represents new investments in Ontario infrastructure of approximately CAD4 billion to produce low emission or emissionless power.

So, to conclude, TransCanada's strategy is working. Our capital program continues to progress with CAD10 billion of assets becoming operational in the last two years and CAD13 billion more moving forward. We expect that those assets will generate significant earnings and cash flow in the future. As well, TransCanada is well positioned for the future with CAD50 billion of projects currently being considered. The need for our expertise is quite clear as the North America market evolves and North America assesses how it's going to manage the billions of dollars needed to upgrade energy infrastructure across the continent. So, by staying disciplined, sticking to our strategy, we will continue to grow cash flow, earnings and dividends and generate superior risk-adjusted returns for our shareholders.

I'll now turn the call over to Don who will provide you with some additional comments on our first-quarter 2012 financial results. Don?

Thanks, Russ. Good afternoon, everyone. I'd like to start today by highlighting a number of key points. TransCanada produced a solid first quarter driven by good performance of our CAD47 billion portfolio of high-quality energy infrastructure assets. Plan maintenance outages at Bruce Power combined with the low natural gas price environment and an unseasonably warm winter did impact earnings in the period. That said, CAD10 billion of new assets placed in service since June 2010 are contributing highly predictable earnings and cash flow underpinned by long-term contracts or regulated cost-of-service business models. This will be supplemented by the CAD2.4 billion Bruce restart which is nearing completion and CAD800 million of Alberta system projects that have or are about to come into service in 2012.

In addition, the Company continues to identify and secure new investment opportunities in all segments of it's core businesses and geographies. These projects will further contribute to sustainable earnings, cash flow and dividend growth in the future. And last, we remain very well-positioned to fund the remainder of our current capital program, as well as pursue other new initiatives.

I'll take the next few minutes to expand on the details of our first quarter, but before I do, I would like to note that TransCanada adopted US GAAP effective January 1, 2012. Comparative 2011 figures have been adjusted as net necessary to reflect the new basis of presentation. Net income and comparable earnings are not affected by this change. One notable difference is to reported EBITDA. Annualized for the full year, EBITDA is expected to drop by approximately CAD300 million. This accounting change effectively moves about CAD200 million of depreciation and CAD100 million of interest cost above the line into EBITDA. Essentially just geography.

Now moving to our consolidated results. Comparable earnings in the first quarter of CAD363 million or CAD0.52 per share decreased by CAD60 million or CAD0.09 per share compared to the same period in 2011. Incremental earnings in Keystone and other recently commissioned assets, combined with higher contractual earnings in Eastern Canadian power were more than offset by a lower contribution from Bruce Power due to significant plant maintenance outages, lower contributions from the Canadian mainline, ANR and Great Lakes natural gas pipelines, lower realized prices in US power as well as lower unregulated natural gas storage revenue in Alberta, and higher interest expenses as a result of lower capitalized interest.

Two plant outages at Bruce Power combined to reduce comparable earnings by about CAD0.06 per share in first quarter 2012. As mentioned in prior periods, Bruce A Unit three commenced a six-month west shift plus planned maintenance outage last November. While the outage will create significant long-term shareholder value by extending the useful life of the reactor to the end of the decade, it meant that Unit three was unavailable for the entire quarter. In addition, a planned maintenance outage in the first quarter of Bruce B Unit eight lasted 46 days.

Low demand for gas and power, largely on account of unseasonably warm weather, along with resilient production in high storage levels, resulted in a weak volume and pricing environment on certain of our US gas pipelines and in US power. This put further downward pressure on earnings per share by about CAD0.05 when compared to first quarter 2011. So, when I break it down, the CAD0.09 per share decrease in year-over-year comparable earnings was largely due to plant outages at Bruce Power and a lack of demand for energy in an unseasonably warm winter.

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 CAD725 million in first quarter 2012, compared to CAD773 million for the same period last year. The CAD48 million net decrease resulted primarily from lower earnings on the Canadian mainline and lower revenues in US natural gas pipelines. Incremental earnings from the Bison and Guadalajara pipelines, which were placed in service in January and June 2011, partially offset these decreases. With respect to the Canadian mainline, the first-quarter results reflect the last NEB approved return on equity of 8.08% on a deemed common equity of 40% and exclude incentive earnings.

Our lower investment base in first quarter 2012 also reduced earnings compared to the prior year. Future quarters will reflect the same return on equity until we receive a decision from the NEB on our 2012-2013 tolls application expected some time in late 2012 or early 2013. In our application, we requested and after-tax weighted average cost of capital of 7% which equates to a rate of return of 12% on a deemed common equity component of 40%. Our US natural gas pipelines were affected in first quarter 2012 by uncontracted capacity on Great Lakes and lower earnings from ANR and GTN. For the remainder of this year, historically high natural gas storage levels and the low natural gas price environment will likely continue to negatively impact revenues in US pipelines.

Turning to oil pipelines, Keystone generated CAD173 million of EBITDA in the first quarter of 2012, compared to CAD99 million for the same period last year. The increase was the result of recognizing an additional month of earnings in 2012 as the Company commenced recording income on Keystone on February 1 of last year. Higher fixed tolls for the Wood River Patoka section of the system also contributed to higher revenues in this quarter.

Keystone remains on track to generate approximately CAD700 million of EBITDA in 2012. Throughput volume on the system continued to rise in the period averaging approximately 536,000 barrels per day including about 6,000 barrels per day of spot volumes.

In energy, comparable EBITDA was CAD244 million in the first quarter compared to CAD315 million for the same period last year. The CAD71 million year-over-year decrease was the result of the combination of factors. On a positive note, energy recognized incremental earnings from the start-up of Coolidge in two phases of Cartier Wind, as well as higher results in Eastern Canadian power. These increases were, however, more than offset by a reduction in Bruce A and B generation volumes from planned maintenance outages mentioned at the outset of my comments, lower contributions from US power mainly resulting from lower realized power prices, and weaker price spreads in natural gas storage.

The arbitration hearing to address the Sundance A force majeure and economic destruction claims dispute commenced on April 9, 2012. The hearing is expected to conclude in May and TransCanada expects to receive a decision in mid 2012. TransCanada has continued to recognize revenues and cost at Sundance A as it considers this event to be an interruption of supply in accordance with the terms of the PPA and is therefore recurred at CAD30 million of EBITDA for the three months ended March 31, 2012, and CAD188 million since the interruption began. The outcome of any arbitration process is not certain. However, TransCanada believes the matter will be resolved in its favor. In unregulated natural gas storage, lower realized price spreads caused EBITDA to decline CAD15 million versus first quarter 2011.

Finally, in energy at Bruce Power, the Unit three six month west shift plus planned maintenance outage, referred to earlier, is expected to be completed in mid second quarter 2012 and the two refurbished Bruce A Units are expected to enter commercial service in second quarter and mid third quarter 2012 respectively. From that point on, Bruce Power will operate an eight-unit site that will generate significant earnings and cash flow for the Company.

Now, turning to the other income statement items on slide 20. Comparable interest expense in the first quarter was CAD242 million compared to CAD210 million in the same period last year. The CAD32 million increase reflects lower capitalized interest related primarily to Keystone and Coolidge and incremental interest expense on new debt issues. These increases were partially offset by the impact of debt maturities in 2012 and 2011.

In the first quarter, CAD74 million of interest was capitalized to assets under construction, compared to CAD97 million for the same period in 2011. Capitalized interest has declined as new projects have been placed into service, somewhat offsetting the impact of rising EBITDA associated with these new assets. Comparable interest income and other for first quarter 2012 decreased CAD3 million to CAD25 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 segments. Comparable income taxes of CAD140 million in first quarter 2012 were down CAD47 million versus 2011, primarily due to lower pretax income.

Moving onto cash flow and investing activities on slide 21, cash flow remains solid in the first quarter and continues to grow primarily from incremental earnings from our new assets. Funds generated from operations increased by CAD26 million, to CAD841 million in the period. Under US GAAP funds generated from operations reflect actual cash distributions received from our equity accounted for investments versus our proportionate share of their collective funds from operations previously recognized under Canadian GAAP. This new basis of accounting is expected to reduce reported funds generated from operations by less than CAD100 million on an annual basis. As mentioned in prior updates, the principal difference between Canadian GAAP and US GAAP is the accounting for joint venture investments which, in TransCanada's case, is predominantly Bruce Power, as well as Northern Border, TQM and Iroquois.

Capital expenditures were CAD464 million in the first quarter 2012, most of which relates to the Keystone Gulf Coast Project and expansions and extensions of the Alberta System. Equity investments of CAD216 million in 2012 and CAD151 million in 2011 represent the Company's investment in equity accounted for joint ventures and primarily relate to our investment in the refurbishment and restart of Bruce Power Units one and two and other planned maintenance activities including the West Shift Plus Program. During 2012, we expect to invest approximately CAD3.5 billion on capital projects which includes expenditures on the Alberta System, Keystone, Bruce Power, Tamazunchale Extension, Canadian solar and maintenance capital. Included in this number is approximately CAD250 million in capitalize interest.

Now looking at slide 22, our liquidity position and access to capital markets remains strong. At the end of the first quarter, our consolidated capital structure consisted of 42% common equity, 4% preferred shares, 3% junior subordinated notes, and 51% debt net of cash. We had CAD196 million of cash on hand along with CAD4.3 billion of committed and undrawn bank lines.

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. In March we issued $500 million of senior notes maturing in March 2015 and bearing interest at a rate of 0.875%. The proceeds were used for general corporate purposes and to reduce short-term indebtedness. And, last, we are well positioned to fund our current capital program as well as CAD380 million of remaining 2012 debt maturities.

In closing, TransCanada produced solid earnings and cash flow in first quarter 2012 in a challenging environment characterized by unseasonably warm weather, excess natural gas supply and low natural gas prices. While these factors are expected to continue to impact volumes on our US pipelines and power prices to US power, our new assets are performing well and we look forward in the coming months to the positive impact of completing the refurbishment of Bruce Power Units one and two, as well as the West Shift Plus maintenance outage on Unit three and additional Alberta projects coming online. Towards the end of this year, we will have some of the first Canadian solar facilities to our portfolio. We continue to advance other initiatives in our CAD13 billion committed capital program including the CAD2.3 billion Keystone Gulf Coast Project. We are well positioned to fund the remainder of that program through internally generated cash flow and term debt without any new subordinated capital.

Finally, we expect to continue to generate significant cash flow that can be used to invest in additional accretive growth opportunities to continue to grow the dividend and further enhance our financial strength and flexibility in the years ahead.

That's the end of my prepared remarks. I will 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 financial community first and once we've completed that, we'll then turn it over to the media. With that, I'll turn the call back to the conference coordinator.

Thank you. (Operator Instructions) The first question is from Linda Ezergailis from TD Securities. Please go ahead.

Thank you. I have a question with respect to your Bruce Unit two. I guess I was of the understanding that it would be coming into service late Q1 or early Q2. I realize it's a very complex project and a month or two is not a huge delay in the grand scheme of things, but maybe you could give us some color as to why in these final months it's coming on a bit slower than expected, and when in the second quarter might you start booking earnings or being in service?

Sure, Linda. It's Alex. I think that mid 2012 date for Unit two is actually -- that's a pretty conservative number, and both we and Bruce are working hard to try to get the units on in advance of that, so I think we have a significant opportunity to get it in well, sorry, the middle of Q3. We have an opportunity to get it in more in line with the dates you saw earlier.

Okay. But the first unit to come into service, it's coming on a little bit slower than expected.

Sorry. I thought you were talking about Unit one.

So what's the brief delay?

I think you kind of hit it on the head. It's -- we are done. All of the construction, all of the commissioning, we're going through a series of very, I don't want to use the term delicate, but there's a lot of physics tests, chemistry tests that need to get done and it's taking a few days longer, a little bit longer than anticipated, nothing really material.

I think what I'd say is, we're producing steam now at the unit and we haven't engaged that steam yet into the steam generators. That's the next step in the process, and that's going to happen very, very shortly. We have to go through all the tests. You fill it up basically, you put the steam in it, you raise the temperatures, you check your valves, you check everything and then you bring it back down, and then you ramp it back up to a little bit higher level and that's the process we're going through. Everything is actually -- it's powered up and we're actually making energy, if you will, we just haven't engaged the turbines yet, and that's the next step, and that will happen very shortly here.

And you're quite confident that you at one won't experience these last-minute delays and it will be mid Q3?

Unit one through the whole process, because we've had the benefit of the experience on Unit two, it allows us to better anticipate what challenges we might be seeing with respect to Unit one. So, I think the team is quite confident about that guidance.

I think as you pointed out, Linda, we're on top of this right now, we're actually starting these reactors, so we're in the process of doing it, and it will be done in the next few weeks. That's what we're doing right now, we're actually starting these facilities. We are at the end of this thing.

Okay. So kind of an end of May in service?

Again, we'll work through the next few, and hopefully have some positive announcements for you.

All right. Great. Good luck. Thanks.

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

Yes, thank you very much. You stated in the release that you have about 35% of the US power generation contracted for the remainder of 2012. Can you give us some color around the price of these contracts? And how much of the US power produced in the first quarter was contracted? And also if you have plans to increase your contracted position for this region going forward?

I think given the very low prices prevailing, particularly in the New England, New York power markets with this low gas price environment, and very, very unseasonable weather, we've taken the position that there's not a lot of upside, Juan, in contracting long-term forward. We think there is a lot more upside than downside.

Okay. Thanks. And the price of the contracts you have in place?

In terms of average price are the kind of deals were doing right now?

Okay. Thanks. And, secondly, do you have an update for us on the contract arbitration process with the OPE with respect to Oakville and when you might expect a resolution on this?

We are working towards this arbitration process. I think we talked about that before. We've executed an arbitration agreement and we're proceeding towards and arbitration. We continue to look at opportunities that may be available to avoid that, but I would expect that we'll be in a situation where we would have the arbitration heard probably this summer, later this summer with a decision probably Q3, early Q4.

Okay. Thank you very much.

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

Thanks. Good afternoon, everybody. Actually, Alex, maybe I could just key off that last answer. I didn't know in working here with Bruce and Unit one, we may have 30 to 60 days where it looks like all of Bruce A is going to market power -- excuse me, market prices. Is the negotiations with Oakville, does that give any leverage to perhaps renegotiate that timeframe that both units have to be in service by July 1?

Carl, I would say that both Bruce and TransCanada are very aware of that date, and that's why I suggested that we think there is a very significant likelihood that we'll be able to get these units in by the end of June. In the event that we slip that date by a small amount of time, the impact of it wouldn't be very material. And I think there's also an opportunity, not so much with Oakville, but I think there's lots of opportunities for the parties to that contract to work together to see that we don't go to that situation.

Great. I appreciate that color. And maybe one other question if I could, I guess for Don or Greg, but on the mainline, obviously a very warm winter. The volumes on the -- I guess what I'm trying to understand is, obviously below the expected budget of around 3.3, 3.4 from last I recall, but by the same token we're still have rates that are 2011 rates. And so where does that put us for under collections at this point?

It's Greg, Carl. So, as you know, we're going on June 4 in to the beginning of the hearing, and so we were in the situation because as you noted, we were on the 2011 rates that if we're able to obtain the package that we proposed to the NEB that we would have been in a refund position with respect to some of that amount, or it would have set off against the existing deferrals. As it is now, with the volumes which we anticipate running in that 2.1 to 2.5 range on average here, because, as you say, we didn't get the winter that we had last year, we would expect that we'll likely not have a deferral or a small deferral assuming that we're successful in the rate case. If any of the key elements of the rate case are not awarded to us in our favor, that would have an impact but I can't really speak to that, as we are just starting into the hearing process.

Understood. Appreciate the color.

Thank you. The next question is from Paul Lechem from CIBC. Please go ahead.

Thank you. I was just wondering if you could give us some more color around Ravenswood and the capacity pricing in New York, what's been causing the rebound -- slight rebound in the capacity pricing and where are you at with the FERC and any decision on your ruling?

Sure. I had a little bit of trouble catching all that, but I think a question that was about where are we with respect to capacity pricing? I just noticed a little while ago that the summer strip option cleared at about CAD12 a kilowatt month, so much higher than 2011, and more in line with what we saw in 2010. And then we're seeing numbers kind of up across the board, 2012 versus 2011. The complaint is in front of the FERC. Obviously, there was a lot of work done in the fall of last year. I think the FERC has all of the information that they require. We certainly haven't heard anything back from them at this time, and we would expect at some time they will make -- they will either issue a decision, or could potentially seek to have a hearing on the matter, but we would expect to hear something in the next few months, I would imagine.

Okay. And what's been driving the rebound in the capacity pricing?

A couple of things. I guess number one, in October 2011 a revised demand curve was implemented and that would result in higher reference prices for a given amount of supply, and then there were some other rule changes that were implemented by the New York ISO that had the effect of changing the way demand response capacity is measured in the market.

We think that both of those events have increased spot market capacity prices compared to the prior year. The other comment I would say, and it's kind of hard to actually determine the full impact, but since the New York ISO decision we've had announcements at about 835 megawatts of capacity in zone J as being moth balled, and I think that is sort of working through the system also.

That's helpful. Thank you.

Thank you. The next question is from Steven Paget from FirstEnergy Capital. Please go ahead.

Thank you. I'm wondering if you could comment maybe on the longer-term future of Bruce Power and what does it look like at the end of the decade? And could there be, for example, a Bruce B west shift?

So, Steven, what I would say is, with the work that we're doing on units three and units four, we are getting to the first units to be reached in the end of their lives will likely be the B units towards the end of the decade. We believe that certainly the Ontario government has stated publicly and repeatedly that they expect and would like to see Bruce remain an eight-unit site going forward.

We think there's a very strong argument that can be made to continue to extend the life of the B units and units three and four. One of the things that the Bruce team is working on is, we do believe that there will be an opportunity, future refurbishments may not require a full sort of five-year shutdown but because various systems in the plants are coming to end-of-life at different times. We actually have an opportunity to significantly extend the lives of the remaining units without the need for these big expensive and massive scoped five-year averages. We can do it in a series of seasonal outages, for example.

Okay. Thanks for that. Alex, if you could comment you've been willing in the past to talk about hedged power prices in Western Canada. Can you let us know what it looks like for the Ranger of the year?

Yes. Let me -- what I would say, looking at our Alberta or our Western power prices and forgive me here, I'm just trying to dig it up as I'm talking, but we're contracted right now probably about two-thirds of 2012. Significantly lower, probably about 40%, 41% in 2013. I don't necessarily want to comment too much on the prices we've achieved, but we're looking at prices in the balance of the year around CAD70 give or take for 2012, and then full year 2013 kind of in the mid-60 range.

Okay. Thanks for that. Those are my questions.

Thank you. The next question is from Matthew Akman from Scotiabank. Please go ahead.

Hi, guys. I wanted to ask a couple questions on the Alaska Pipeline Project. And, in particular, obviously there's been some change in scope there, considerable change and I'm wondering whether you guys can obtain the subsidies for development of the pipeline that you had achieved under AGEA for the new revised project?

So, I think what you're referring to is the State's contribution, the CAD500 million contribution to the development of the lower 48 project. The way we've reconfigured the project at the current time is, it will be a project change essentially, under AGEA for the parties to look at an alternative market on the West Coast. That doesn't mean that we're canceling the Lower 48 project, but we are basically, for all intents and purposes, going to suspend that one for a period of time and then look to the feasibility of a West Coast alternative.

So, a lot of the work that's been completed to date for the project can be used for a West Coast LNG alternative, and it will continue to be run under AGEA the same as it has been today so that funding mechanism stays in place as we look at West Coast alternative, but first round there isn't as much technical work as there is market feasibility work. So, I would expect from a TransCanada perspective and from a total perspective our project spend will be lower than it would have otherwise have been this year. So, TransCanada's portion of those costs would be less and, likewise, the State's portion of those costs will be less this year.

Okay. When you say in your disclosure in a way that preserves project assets, what do you mean by project assets? Like the --.

With respect to Alaska disclosure. I don't know what the specific words are, Matthew, that you're referring to, but I would suggest what they probably mean is the work that we've done to date is preserved, and there will be some of that work that will be useful because somewhere between one-third and one-half the route is similar between the two projects.

Okay. I see. So, just preserving right-of-ways or something like that?

Correct. They're just looking at the words you're referring to, so I know exactly what you were referring to.

Yes, there's a paragraph on Alaska Pipeline Project. Is TransCanada still interested in building the infrastructure related to this, correct? And would that include not only a pipeline, but maybe LNG facilities? Are you guys interested in that component, as well?

It's still too early to know, I would say. It may be a project that when we originally conceived the Alaska Highway Project with Exxon Mobil it includes the upstream gas processing plant as part of the project, so if a West Coast LNG project is conceived as an upstream gas processing plant pipeline and LNG liquefaction facility, and then all project participants would participate in and we would likely participate in a percentage of the whole, but it could also be configured in a way that you got the upstream gas processing in the pipeline and LNG facility as a separately owned facility.

The primary objective of the Alaskan government is to ensure that there is open access to the pipeline to all participants who want to drill in Alaska. That wouldn't necessarily be a requirement, at least at this time, of an LNG facility. So, our participation is required in the pipeline, but not necessarily an LNG facility and we will work that out with our partners and we're open on whichever way it breaks.

Last question here. Any rough timing for this kind of stuff being in service or is it way too early to even say?

I'd say it's too early to say, but I would say that they've always targeted some time early in the next decade is when they would like to monetize that resource and I would think that is in the minds of producers. From a State perspective, obviously they'd like to monetize this resource as quickly as they can. So the next step is feasibility study, and at the same time in parallel the State and the producers need to negotiate a fiscal framework under which it would make it economical for the producers to move forward.

Okay. Thanks very much, guys. Those are my questions.

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

Russ, in your opening comments you mentioned a little bit on the oil side around producer interest in getting oil to the East Coast. I'm wondering if you can elaborate on that a little bit more, and I think I saw a headline that you may even consider converting the main line? Is that something that is just a glimmer in your eye? Is this something that you would even think about or maybe just comment on that a little bit more?

Maybe start with the macro. There's been a lot of rumors swirling about what we might or might not do, but the genesis really is Canada imports some 500,000 barrels a day of oil from other places around the world. They pay world oil prices for it, so grant life price is not W-2 I prices, so they're paying higher than the North American prices. At the same time, Canadian producers are receiving a price for their production. It's been discounted, one by the WTI, the Brent discount and, secondly, a heavy discount and potentially even a transportation discount. So from a Canadian perspective we've had inbound interest from both producers and refiners as saying, is there a way to marry this up?

With respect to our assets, if you will, that currently traverse the continents between East and West, we always look to what is their best value and best use for all of our stakeholders? That includes gas shippers, municipalities along the right-of-way provinces, producers, we look to the best interest of all of those and try to maximize the value as much as possible to the greatest number of stakeholders. So, obviously, conversion of a portion of our gas pipeline is a possibility but we are in pretty early days.

We converted line one to crude service and basically the process we went by was to look at whether or not that pipeline had greater value to the Canadian public interest in gas service or in crude oil service, and it was determined at its best value, not that it wasn't needed in gas service, but it's best value was in oil service. And, similarly, if we take a look at this project and people want us to do a further, I guess, investigation those would be the parameters under which we would look at making that happen.

I think you can see that economically, at least on the oil side, that seems to make a lot of sense. We've done the conversion before. So, technically it's possible that we could do this, obviously if there is cost in conversion. So, it appears to be feasible. But, again, we've got a lot of conversation that would have to occur with those shippers that want it to happen, and the impact on our existing Gas business, and we have to have those conversations. So, in terms of a glimmer in our eye, we're in the early stages of responding to market interest in whether or not we could better utilize these assets in that way to service that need.

That was actually really helpful, thank you. Do you have any sense of what size you could move, in terms of volumes? The capital, any sense of what the timing could be if something like this moved forward? And maybe a little bit about more about the regulatory process?

It's really, really, really early in stage. Timing and -- there's a lot of complexities and regulatory process. In terms of size, we've got pipelines that are anywhere from 30 inches or so, to 40 inches or so and that gives you a range of volume somewhere between the 300,000 to 500,000 to 600,000 barrels a day. And it's all dependent upon, as I said, what the demand in the marketplace is and what customers and stakeholders would like us to do. So, there's a lot of optionality there. But, again, we are in the early stages of investigating this, and we'll do what's in the best interest of, as I said, all of our stakeholders.

Got it. And hopefully that only counted as one for me. I'll ask just one more. On the Gulf Coast Project, can you just tell us a little bit more about the range of the toll your expecting to charge on there? How much of the capacity maybe you've contracted out there? Will you be seeking market-based rates? Just a little bit more detail on the Gulf Coast Project.

Well, I think I'll probably hold off on the toll, specifics on the toll. It is going to be, we believe it's going to be very, very competitive with the other options that are out there. With respect to cost of service or market-based tolls, we're going to see what our competitors do. One of the issues for market-based tolls is, do you have market power? And if there is an opportunity for market-based tolls, we'll certainly take a look at that and particularly if our competitors are allowed to do that.

And can you give us a sense of how much capacity is actually contracted right now?

We haven't released that for competitive reasons. What I can say, we're talking about 550,000 barrels a day, give or take, and a very inexpensive expansion case that would get us up to 830,000 barrels a day. We have quite a significant amount of long-term, 10--year average contract terms, and then there is a reasonable spot component to that also.

Okay, thanks, Alex. Appreciate it.

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

Thank you. Good afternoon. I guess a question that could go to Russ, and then also to Greg and I guess to a certain degree also to Alex. Just looking at a high level, Russ, what are your thoughts on being a greater participant in the NGO market whether it's from a transportation standpoint, processing? It is a component of the value chain where you're not really all that exposed at this stage in time?

We have been there historically, and so we've retained the expertise to be there. I think our approach to that business would be similar to our approach to all of our other businesses. We would come in on a fee-based basis. We're not necessarily interested in taking our commodity risk. I'd say at the current time that spread is very wide and attractive.

But, obviously, if you have to pay to get into it at the top of the market, there is a significant amount of risk in that kind of an acquisition at the current time. So, as gas production continues to develop, producers migrate to liquids rich natural gas, obviously new facilities are going to be required. And we could easily be the provider of some of those services, but under contractual terms that sort of hit our model.

How are you pursuing any opportunities within that space at this point in time?

I'm going to leave that to Greg.

Well, we always look at various opportunities around -- there really isn't anything specific that we're pursuing, although we try and monitor that market and determine if there is an opportunity for something, as Russ said, where we could do it on a contractual basis.

Okay. That's great. Thank you.

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

Great. Thank you. Alex, this is for you, just to go back to the hedge power prices you gave. CAD70 for balance of the year '12 and the mid-60s for '13. Were you trying to answer roughly where your hedges are at? Or were you trying to express where the curve is at?

I was trying to express where the curve is at.

And would you be materially different from that?

When you talk about it, that was a question I had asked earlier is, are you trying to get a feel as to what deals we're doing now or kind of what the weighted average of our historical hedge book is? And what I would say is because we do have a significant amount of legacy contracts, a lot of those contract even dating back to flow-through deals with the cold PPAs, call it the weighted average contract is obviously going to be less than that. I would say in terms of those numbers that I've given in our recent hedging activity, we have been at least as successful and have done -- we're quite pleased with our hedging activity to this point.

Okay. And another point I was trying to get at was, you had some very good performance in Western Power in the first quarter. Were your hedges, and you mentioned the hedging, was the pricing materially better in Q1 versus, say, what you are trying to convey for balance of year? Or was there also something else in the segment that you really were able to capitalize even though you had prices in the market that were down about CAD20?

We had some good short-term hedges in Q1, and we do have a pretty attractive hedge look for the balance of the year. A little more shaded towards the front end than the back end.

That's fine. Just last question, switching to oil. You've talked at times around a desire for intra-Alberta. I think there was even a map at the AGM presentation showing -- going north to Fort Mac. I'm just wondering how strong is your interest in doing that?

It is a very crowded space and then if you are pursuing it, is it something you would be looking at Greenfield as an extension of Keystone similar to what you're doing with the merchant storage at Hardesty? Or do you think it's maybe better to acquire a partner (technical difficulties) your way into that business?

The answer is, we are very, very interested in expanding our Oil Pipeline business within Alberta. You make a fair comment. There are a number of parties that are looking -- I guess what I would say is there is a very big opportunity set in terms of to build oil pipelines just because of, obviously, the huge increases in production expecting to come out of Alberta over the next couple of decades.

You are correct, there's a lot of competition for that. One observation I would have is that TransCanada's incredibly deep experience in building and operating pipelines in the very hostile environment of Northern Alberta, we think that our potential customers very much appreciate that capability and the demonstrated ability to operate in those kind of conditions. And we think that gives us -- it evens the playing field quite a bit and hopefully tilts it in our favor going forward.

Okay. And that's something you're active and pretty active in developing today or is this something that --

We're at --

-- more of a five-year type?

No. We're active right now.

Okay. Great. Thanks very much.

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

Thanks. My question follow-up was hit. Thank you.

Thank you. The next question is from Steven Paget from FirstEnergy Capital. Please go ahead.

Hi. Just a question. Could the Alaska line be built with greater capacity down to Central Alaska in order to pre-build what could be a lower 48 line or is that simply too expensive?

I believe at the current time, Steven, that there's only sufficient supply for one pipeline. The volume would have to grow substantially to be able to build two pipelines economically. To build a lower 48 pipeline we were looking at about [44] Bcf a day to make economic so if you took a portion of that and moved it elsewhere, you wouldn't have sufficient volumes to build twp pipelines. So, I think at the current time I'd say that the answer to that question is not likely. But, again, we're just starting to study. And that could be an outcome of the study, but my gut feel would say, at least at the current time and at least for the foreseeable future, there isn't sufficient gas supply for gas to go two different directions. It's got one way or the other.

Okay. Thanks, Russ. Is there an opportunity for TransCanada to invest in liquefaction in Northwest BC?

Again, similar to my comment on Alaska, if that's what the customers would like us to do, if we relate to them in terms of bringing gas from our hub or NGTL system to a pipeline that moves gas to the West Coast, we participate in that, we participate in the pipeline that we connect to all the way to the West Coast, and to the extent that those customers wanted us to participate in a liquefaction facility, we would look at that, as well.

I think our true expertise lies in -- and in our value-added, lies in the liquidity of the NGTL system, and the attraction of being able to bring gas on early, being able to bring to market and then switch to that market. And be able to move -- the flexibility to move the gas back and forth would be the primary value added. The second one would be we're one of the only companies in North America with the capacity, if you will, to be able to build large diameter pipeline through some of that very, very treacherous and difficult terrain through mountainous regions that you need to get through to get to the West Coast.

In terms of liquefaction and in the kinds of players that would likely build those on the coast, we don't bring a whole bunch of value-added. That said, if they want an integrated project, obviously we would be open to that, as we were when we look at the Broadwater importation facilities or the (inaudible) importation facilities. We have the capability but that wouldn't be what I'd say our core expertise is.

Alright. Thanks. Those are my questions.

(Operator Instructions) The next question is from Pierre Lacroix from Desjardins Securities. Please go ahead.

Thanks. Just a quick one for Don. The senior notes that were issued in March, the $500 million at 0.875%, can you give me some perspective on this? And what is your capacity or your opportunity to secure more of this?

Hi, Pierre. It -- obviously, if you look at the coupon it was a great opportunity to term out some debt. Our needs are fairly modest this year, in terms of total capital markets funding. We need about CAD1 billion and we have about CAD900 million in maturities. This took care of a piece of that. We would see perhaps doing another CAD0.5 billion, primarily for regulated rate base later this year. And the balance of that is simply made up of CP capacity and cash on hand. So, without a pressing need for any more capital and, trust me, these rates are extremely attractive, we'd love to be issuing more right now if we had a reason, but quite simply until we have a permit on hand on XL, the needs remain modest.

Okay. Thank you.

Thank you. The next question is from Steven Paget from FirstEnergy Capital. Please go ahead.

I know it's getting late, but you mentioned in the Q1 report that XL might be online late 2014, and previously it had been early 2015 and now it's late 2014, early 2015. What's made you a little bit more bullish in terms of the timing?

Steven, I think the main thing is that by making the decision to go ahead with the Gulf Coast Lake, it has opened up some opportunities for us to accelerate the Keystone XL Project. One of the challenges we had was when we were looking at building XL in its entirety, it was such a massive project that it basically took up most of the basic pipeline construction capacity in the US during those two construction seasons. And by going ahead early on the Gulf Coast Lake, it actually -- the remainder of the project, the hypotenuse as we call it, it's a much more bite-size project. It's still a big project, but we think that there is a reasonable chance that because it's a smaller project we could get it done in that shorter period of time and, hence, why you see us backing back to late 2014.

Okay. Thank you, Alex. That's it for me, I promise.

Thanks, Steven.

We have no further questions from analysts. (Operator Instructions) We have a question from Jeff Lee from Pipeline news. Please go ahead.

Good afternoon. This question is for Russ. What kind of activities, business activities or work, are you currently doing between Hardesty and Monchy Saskatchewan?

What kind of work? We've done obviously some of the -- give me those two locations again?

Hardesty and Monchy?

On the Canadian side of the border. Primarily what our construction activities have included is some right-of-way work, as well as some major river crossings that are what I call sort of a long lead time constraint, so we have done, I believe, two major river crossings. We've done a considerable amount of our tankage work at Hardesty. The tanks are actually, for the most, erected already so those are the kinds of activities that we've conducted to date. We'll commence what I would call the larger scale construction once we have the XL permit, but the pipe is essentially stationed along the right-of-way, and we're ready to commence that activity.

Are also re-communicating with your contractors?

Pardon me?

You also had some contracts to let out to towns and communities along the way for various construction projects. Are you in touch with those people?

We're in contact with all of the parties that are related to our pipeline, whether that be utility right-of-way or whatever us else that we need that affects those communities. We're in constant communication with all of our stakeholders, if you will, in terms of constructing. Obviously, we would have liked to have been under full construction by now, so we've had to keep all those people informed as to what our schedule looks like, and as we continue to revise our schedule we update our information to them.

Are they excited?

I think everybody's excited about this project. It's a very important project, and we've all been waiting a very long time to commence construction. And that activity is starting to roll, and, obviously, that's got all of our stakeholders excited.

Okay. Thanks very much.

(Operator Instructions) We have no further questions registered at this time.

Great. Thanks very much and thanks to everyone for participating this afternoon. We appreciate your interest in TransCanada. I know it is getting late on a Friday. Just a reminder for folks, Terry, Lee, and I will be available for further questions to the extent you have those later this afternoon, I promise we will get back to you. So, thanks again for your interest in TransCanada and we look forward to talking to you soon. Bye for now.

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