TC Energy Corp (TRP) 2014 Q1 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2014 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 2014 first quarter conference call.

With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, our Chief Financial Officer; Alex Pourbaix, President of Development; Karl Johannson, President of Natural Gas Pipelines; Paul Miller, President of Liquids Pipelines; Bill Taylor, President of Energy; and Glenn Menuz, our Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other Company developments. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at TransCanada.com. It can be found in the Investor section, under the heading Events and Presentations.

Following their prepared remarks we will turn the call over to the conference coordinator for your questions. During the question-and-answer period, we'll take questions from the investment community first, followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please 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, Lee and I would be pleased to discuss them with you following the call.

Before Russ begins, I'd like to remind you 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 also I'd like to point out that during this presentation we'll refer to measures such as comparable earnings, comparable earnings per share, earnings before interest, taxes, depreciation, and amortization or EBITDA, comparable EBITDA, and funds generated from operations.

These and certain other comparable measures do not have any standardized meaning under GAAP, and are therefore considered to be non-GAAP measures. As a result they may not be comparable to similar measured presented by other entities. These measures are used to provide you with additional information on TransCanada's operating performance, liquidity, and its ability to generate funds to finance its operations. With that, I'll now turn the call over to Russ.

Thanks, David. Good afternoon, everyone, and thank you very much for joining us. Earlier today, I delivered my annual address here in Calgary to our shareholders, our investors, analysts, employees, and others via the web. My message to them was quite simple. Our strategy is working. 2013 was an unprecedented year of opportunity at TransCanada, as we announced CAD19 billion of new projects, expanding our growth portfolio to CAD36 billion.

Our strategic focus is clear, as I said, is to complete these projections and bring them into operation. We expect to bring CAD3.6 billion of those assets into service in 2014. These include the CAD2.6 billion Keystone Gulf Coast extension, which began transporting crude January 22, and the Tamazunchale pipeline extension, and further expansions of the NGTL system, and four of our solar powered facilities in Ontario. We expect the remaining CAD35 billion of projects will become operational over the remainder of the decade, and that they will generate significant growth and earnings in cash flow.

Focusing for a couple of seconds on the first-quarter results, comparable earnings were CAD422 million or CAD0.60 a share, a 15% increase on a per share basis, compared to the same period in 2013. I'm pleased to announce that we had another very strong first three months, with cash. Comparable EBITDA was CAD1.4 billion and funds generated from operation were CAD1.1 billion, a 20% increase compared to the same period last year. Today the Board of Directors declared a quarterly dividend of CAD0.48 per common share for the quarter ending June 30, 2014. That equates to CAD1.92 per share on an annualized basis.

TransCanada performed well in the first quarter, due to strong performance of our base existing assets. A very cold winter resulted in strong demand for our natural gas and power facilities, which provide power to many residents across North America. I think, underscoring their critical value to the North American economy. Don will discuss our results in much more detail in a few minutes, but before he does that, I'd like to touch on our progress on a number of our major projects.

First, I'm pleased to mention the start up of our Gulf Coast extension. It began transporting crude, as I said, to refineries in Texas on January 22. We expect that pipeline will have the capacity to deliver an average 520,000 barrels a day in the first full year of operation, as we ramp up to full delivery capability of 700,000 barrels a day. The extension is an important facility as it helps the United States expand its infrastructure network, with a high-tech pipeline that will grow -- will ship growing supplies of American oil, along with Canadian oil to markets.

Turning to Keystone XL, where the permitting process has again been delayed. On April 18, the US State Department announced it needs more time to gather input from eight federal agencies, with respect to the national interest determination period. They need time to process the 2.5 million public comments received, and to better understand certain legal issues in Nebraska. In our view, this delay is inexplicable. The first leg of our Keystone system took just over 600 days to review and approve, and now after more than 2,000 days, five exhaustive environmental reviews, and over 17,000 pages of scientific data, the review process continues to be delayed.

In Nebraska the current route approved by the States' Department of Environmental Quality is still valid, as the lower court ruling is under appeal. The State Supreme Court should hear arguments in the fall with expected decision at year-end. A majority of Americans support this pipeline, and the project has strong bipartisan Congressional support. Our shippers do remain 100% behind the project, and poll after poll since 2011 continues to find an average of 65% of Americans support Keystone XL, and they want to see it built.

In the State Departments final environmental impact statement issued in January concluded Keystone XL will have minimal impact on the environment. As a result of the delays, the CAD5.4 billion cost estimate for Keystone XL will increase, depending on the timing of the actual permit. As of March 31, 2014, we had invested CAD2.3 billion into the project. We anticipate the pipeline would be operational approximately two years after we receive a Presidential permit. I continue to believe that the facts will prevail at the end of the day, and we will eventually receive a Presidential permit.

We continue to make great progress on the CAD12 billion Energy East project. An important milestone occurred in March, when we filed a project description with the National Energy Board. Prior to the filing of full facility application for this initiative with the NEB, in the next few months, we will continue to consult with thousands of stakeholders along the 4,600 kilometer route. We'll hold dozens of public open houses and many more face-to-face discussions to ensure all stakeholders' concerns are incorporated into our design. The 1.1 million barrel a day pipeline will transport oil from Western Canada to Eastern Canadian refineries and export terminals in Quebec and New Brunswick, creating jobs, cash revenue and energy security for Canadians.

Those benefits are substantial. They include CAD35 billion in additional gross domestic product for Canada, more than 10,000 full time jobs during the development and construction phases, 1,000 more jobs once the pipeline is operating, and CAD10 billion in tax revenues for all levels of government over the lifetime of the project. Most people don't know, but in Canada we import over 700,000 barrels of oil each day from foreign countries. Energy East will allow us to push out this foreign oil, creating the opportunity for Canada to use and refine its own resources, something that benefits all of us from coast to coast to coast. Our plan is to file our application this summer, with the intent of obtaining regulatory approval some time in early 2016. Based on that schedule, we plan to bring the pipeline into service to Quebec in early 2018, and to New Brunswick later in 2018.

Moving to the gas side of our business, where the main line volumes have been rising, delivery volumes in the first quarter of 2014 were 5.9 billion cubic feet a day compared to 4.7 billion cubic feet a day during the same period last year. As a result of the pricing discretion provide by the NEB's ruling, TransCanada has been able to move the contracted subscribers on the Canadian main line to 3.5 Bcf a day, and reach a longer term settlement with its Eastern Canadian customers.

In late March the National Energy Board responded to the local distribution companies, or LDC, settlement application we filed in December of 2013. The regulator offered two options to process the application: TransCanada can continue the application as a contested tolls application or make an amended application with more information. The Company has now made a decision to refile an amended application with additional supplemental information in the second quarter of this year. We continue to believe this settlement is of great benefit to all stakeholders, and we remain confident in its ultimate approval.

Moving over to the NGTL system where we continue to expand the critical network of pipe, CAD400 million in expansion projects are currently in various stages of development and construction. In addition, we have approximately CAD1.8 billion of projects in, that have been applied for, but not yet approved. Those include our CAD1.7 billion North Montney project. In early February, we received a hearing order for that project, and that hearing will begin in August. The 300 kilometer pipeline will connect to the Prince Rupert Gas Transmission project, which is proposed to supply natural gas to the proposed Pacific Northwest LNG export facility near Prince Rupert. For the North Montney project we have signed 2 billion cubic feet a day of contracts with Progress Energy.

With respect to our B.C. LNG pipeline projects, both the Coastal GasLink project and the Prince Rupert Gas Transmission project have achieved important milestones over the quarter. Environmental assessment applications for both projects were submitted to the B.C. Environmental Assessment Office and the B.C. Oil and Gas Commission. The CAD5 billion Prince Rupert Gas Transmission project and the CAD4 billion Coastal GasLink project are expected to be operational in the latter part of this decade.

Moving over to the United States, it's been a very productive spring for the ANR Pipeline, with the announcements that we had secured 2 billion cubic feet a day of firm 20 year-plus natural gas contracts on the system's Southeast main line. These contracts will enable growing Utica and Marcellus Shale gas supplies to move to Northern Markets, but as well, southbound to meet the growing demand for LNG export from the US Gulf Coast. TransCanada is now assessing further requests for service, which could result in further expansions of the ANR system.

Moving up to Alaska, we received some very positive news two weeks ago concerning the Alaska pipeline project with the approval of Senate Bill 138. The approval means the Alaska government and TransCanada will now be able to move forward with agreements to transition from the AGIA license to a new structure, as set out in heads of agreement, that was signed by Exxon-Mobil, BP, ConocoPhillips, TransCanada, the Alaska Gas Line Development Corporation, and Alaska's Commissioners of Natural Resources and Commissioner of Revenue. That agreement was signed in January. The agreement lays out the commercial framework for the development of an 800 mile natural gas pipeline to transport gas from the Alaska North slope to an LNG plant on the State's South Central coast.

Moving over to power, in 2011, we agreed to buy nine solar projects from Canadian Solar Solutions. The combined capacity of those nine projects is 86 megawatts, at a cost of CAD500 million. We acquired four of those projects in 2013, and expect to acquire four more in the fourth quarter of 2014. The deal to purchase the ninth and final facility should close in mid 2015. All nine facilities will complement TransCanada's existing operations in Ontario. The new renewable energy produced from those projects will be sold to the Ontario Power Authority under 20 year power purchase agreements.

In conclusion, our diverse portfolio of energy infrastructure assets generated strong earnings and cash flow in 2013. The trend continued in the first quarter of 2014 with comparable earnings of CAD422 million or CAD0.60 per share, a 15% increase, compared to the same period in 2013. Funds generated from operations were also up 20% to CAD1.1 billion. Today, we are advancing CAD36 billion of commercially-secured capital projects. We expect this high-quality portfolio of contracted projects to generate significant growth in earnings and cash flow between now and the end of the decade.

I can tell you we're focused on delivering on that expectation, and our folks are working as hard as they can to make that happen. I'll now turn the call over to our Chief Financial Officer, Don Marchand, who will offer details on our financial performance. Don?

Thanks, Russ, and good afternoon, everyone. Before I review our Q1 results in detail, I'd like to highlight a few key messages. We are pleased to report another solid quarter across all of our business segments. Our assets performed well during this unseasonably cold winter, a clear demonstration of their importance and value to the overall infrastructure grid in North America. On January 22, the $2.6 billion Keystone Gulf Coast extension commenced commercial operations, and began contributing to earnings and cash flow. Another CAD1 billion of new assets are expected to positively impact results later this year, as they are brought into service. They include the Tamazunchale pipeline extension, ongoing expansions of the NGTL system, and the acquisition of four more Ontario solar facilities.

We remain highly focused on advancing the remainder of our CAD36 billion portfolio of high quality, long life energy infrastructure growth opportunities. All of these projects are underpinned by long-term contracts or cost of service business models, and are expected to result in significant growth in earnings, cash flow and dividends over the remainder of the decade. And finally, we remain well positioned to fund our current capital program with predictable and growing cash flow, strong balance sheet, and access to multiple attractive external funding sources.

Now, moving to our consolidated results shown on the next slide. Comparable earnings in the first quarter were CAD422 million or CAD0.60 per share, increased CAD52 million or CAD0.08 per share compared to the same period in 2013. This 15% increase in comparable EPS was primarily due to a higher allowed return on equity, and a higher average investment base on the NGTL system, the start up of the Keystone Gulf Coast extension in January, higher realized capacity and power prices in US power, and higher equity income from Bruce Power, due to lower planned outage days at Bruce A and B. This was partially offset by higher operating costs and lower storage revenues at ANR, and increased interest expense due to new debt issuances.

Turning to our business segment results at the EBITDA level, our Natural Gas Pipelines business generated comparable EBITDA of CAD848 million in the first quarter of 2014, compared to CAD746 million for the same period last year. Canadian gas pipelines EBITDA of CAD566 million increased CAD69 million compared to 2013. Improved results were primarily due to a higher average investment base, and a higher allowed return on equity of 10.1% on the NGTL system. Flow through items led to higher EBITDA from the Canadian main line, but do not have an impact on net income.

US and international gas pipeline's EBITDA of CAD291 million increased CAD33 million compared to first quarter 2013, primarily as a result of higher revenues at Great Lakes due to cold weather this winter. Currency translation also had a positive impact as a result of the stronger US dollar. Partially offsetting the increase in EBITDA in US pipelines were lower storage revenues, and higher operating costs at ANR.

Turning to Liquids Pipelines, the Keystone pipeline system generated CAD248 million of EBITDA in the first quarter, with a CAD62 million year-over-year increase, primarily a result of the commercial in-service of the Keystone Gulf Coast extension on January 22, and the favorable impact of the stronger US dollar. The start up of the Gulf Coast extension is another significant milestone in advancing our capital program, and we are pleased to have this asset now contributing to earnings and cash flow. For 2014, the Gulf Coast extension is expected to generate approximately $250 million of EBITDA, largely underpinned by contractual commitments.

In Energy, comparable EBITDA was CAD345 million in the first quarter, compared to CAD277 million for the same period last year. The CAD68 million increase was the result of a combination of positive factors. Bruce Power's equity income rose CAD33 million, reflecting fewer planned outage days at Bruce B, as well as from Bruce A's Unit 4, which was undergoing a planned life extension outage in the year-ago period.

US Power also generated improved results in the first quarter compared to last year. The CAD26 million increase in EBITDA was primarily due to higher realized capacity prices in New York, and higher realized power prices in both New England and New York, partially offset by higher fuel costs at Ravenswood. Natural Gas Storage generated a solid quarter, improving CAD9 million year-over-year, driven by increased volumes at higher realized storage spreads.

Now, turning to the other income statement items on slide 21. Comparable interest expense increased CAD17 million in the first quarter to CAD274 million. This increase was principally due to interest charges on recent US debt issues and higher foreign exchange on translated interest denominated in US dollars. This was partially offset by Canadian and US dollar debt maturities, and increased capitalized interest. As a reminder, exposure to US dollar income is largely offset with US dollar denominated interest expense, and financial derivatives, the net effect of which is that currency movements do not have a material impact on earnings over a rolling 12-month forward period.

In the first quarter, CAD79 million of interest was capitalized to assets under construction, compared to CAD55 million for the same period in 2013. This reflects higher capitalized interest for Keystone XL, as well as Mexican LNG and other liquids pipeline projects, partially offset by completion of the Gulf Coast extension of the Keystone system. Comparable interest income and other for the first quarter this year decreased CAD24 million compared to 2013, due to higher realized losses on derivatives used to manage our net exposure to foreign exchange fluctuations on US dollar income.

Comparable income tax for first quarter 2014 increased CAD65 million compared to the same period last year, due to higher pre-tax earnings, combined with changes in the proportion of income earned in higher tax jurisdictions, as well as higher flow-through taxes on Canadian regulated pipelines. Excluding Canadian regulatory flow-through pipelines, the effective tax rate was approximately 27% in the quarter.

Net income attributable to non-controlling interests rose CAD23 million in the first quarter compared to the same period last year, due to the partial sale of GTN and Bison last July to our MLP TC Pipelines. Preferred share dividends of CAD23 million were CAD8 million higher in first quarter 2014, as a result of the CAD600 million Series 7 and CAD450 million Series 9 issuances in March 2013 and January 2014 respectively.

Now, moving on to cash flow and investing activities on slide 22. Cash flow is once again very strong, primarily due to increased earnings across all business segments in the period, and higher distributions from equity investments. Funds generated from operations exceeded CAD1.1 billion in the quarter, representing a 20% increase over the same period last year. Turning to investing activities, capital expenditures were CAD778 million in the first quarter, driven principally by the Gulf Coast extension, expansion projects on the NGTL system and construction of our Mexican pipelines. Equity investments of CAD89 million in the quarter reflect increased investment in the Grand Rapids pipeline.

Now turning to slide 23. Our liquidity and access to capital markets remains solid. At the end of the first quarter, our consolidated capital structure consists of 40% common equity, 5% preferred shares, 2% junior subordinated notes, and 53% debt net of cash. At March 31, we had CAD740 million of cash on hand, along with CAD5 billion of committed and undrawn revolving bank lines, available with our high quality bank group. Our two commercial paper programs, one in Canada and one in the US, remain well supported, and continue to provide flexible and very attractive sources of short-term funds.

In January, we completed a CAD450 million preferred share issue in Canada. The Series 9 cumulative redeemable first preferred shares have an initial dividend rate of 4.25%, which is fixed to October 2019. In February, we issued CAD1.25 billion of 20-year senior notes, bearing interest at 4.625%. In March, we redeemed at par all of the outstanding 5.6% TCPL Series Y first preferred shares. The total face value of the outstanding shares was CAD200 million, and they carried an aggregate of CAD11 million in annualized dividends.

Finally, we closed the sale of Cancarb and its related power generation facility on April 15 for CAD190 million, and expect to realize an after-tax gain of approximately CAD95 million in our second-quarter results. Also in the second quarter, we expect to record a CAD33 million after-tax charge for the early contract termination of 38 billion cubic feet of leased natural gas storage capacity, effective April 30, 2014. Starting on May 1, we have reentered into a new arrangement for reduced average volume at lower rates for a six-year term.

Looking forward, we remain well-positioned to finance our capital program through funds generated from operations, new senior debt, as well as subordinated capital in the form of additional preferred shares, hybrid securities, and portfolio management, which includes the drop down of all of our US natural gas pipeline assets into TC Pipelines LP on a systemic basis over the next several years.

In closing, the Company produced a very strong quarter with comparable earnings per share and funds generated from operations up 15% and 20% respectively compared to 2013. As we progress through 2014, the addition of approximately CAD3.6 billion of new capital projects is expected to positively impact future earnings. In addition, we continued to advance the balance of our CAD36 billion of large-scale commercially-secured infrastructure projects, each of which is underpinned by long-term contracts, with strong counterparties or cost of service business models. This blue chip portfolio of integral energy infrastructure projects is expected to generate significant growth in earnings, cash flow and dividends for our shareholders, over the remainder of the decade.

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

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

(Operator Instructions)

The first question is from Paul Lechem from CIBC. Please go ahead.

I was just wondering on the main line filing, can you give us a sense of what the issues were around the LDCs, and why you have to refile, and what the outlook is there?

Sure, Paul. It's Karl talking. We initially filed that application as a settlement filing.

Now settlements are adjudicated in the NEB slightly different than a contested toll application. It's more of an abbreviated process, and the Board typically wants to see more support for the settlement and maybe a little bit of different process than what we ultimately did to achieve that LDC settlement. So the Board came back and informed us that they will not process it as a settlement application, and invited us to make an amended application and come back as a tolls application, which is what we were doing right now.

You can expect an amended application to go out some time next week, and we will proceed through the process as a contested toll application. The Board has come back and told us they're willing to expedite this hearing, so we do expect to get this hearing, the process completed before the end of the year still.

So the amended filing, does that have any impact on the financials of the filing, or is it really just a change in the process?

No, we're actually going to keep our original filing and we've just added some supplementary information to it, that the Board had a couple questions in their order, so we're just clarifying a couple of the questions that they had just to make it for fulsome for a rate filing. So the base filing that we did is still on the record, and we'll still be using that as our application.

And just wondering if there's any updates on negotiations with the Ontario government in terms of refurbishment of the remaining units 3 to 6 on the Bruce Power, if there's any update there, and thoughts on does the Ontario election change anything, is there a delay from that, or any impacts from that?

Sure, it's Bill Taylor speaking. First part of your question, with regards to the discussions, I can report that Bruce Power is continuing in its discussions with the Ontario government, through their agent, the Ontario Power Authority. Those discussions are ongoing, and so nothing really to report on the results of that, other than to mention that the discussions continue.

And on the second item, with the news today regarding the lack of support for the Ontario's tabled budget and the election that will ensue here in June or July, at this point, we don't have any perspective on how that may affect negotiations. We anticipate that they will continue through that period, while the election is underway.

Okay, and just do you have any thoughts in terms of when the negotiations might be concluded? Is this a 2014 event?

At this point, I don't have any visibility on that.

Okay, thank you.

Thanks, Paul.

The next question is from Carl Kirst from BMO.

I just wanted to focus a little bit on ANR, certainly, congratulations for getting that contracted, and my question is really twofold around ANR. First is with both the 2 Bcf a day that was signed as well as potential incremental, is any of that gas potentially going to move north? And is it possible then that maybe this could lead to firming up of some of the earnings on Great Lakes?

So that's one question and then sort of the secondary question is just, sort of noticing here on the first-quarter results that ANR was down year-over-year, I think attributable to lower storage revenues, despite the winter weather, and I guess, perhaps leading in with the recontracting of the Niska storage and dropping off capacity, I take that to mean you don't see any change in the storage market coming any time soon.

It's Karl again, so let me deal with the first part of that first. We've contracted about 2 Bcf a day of new volumes on that system. That volume will be coming on starting later this year, it will be fully up in 2016.

About half of it is going north, so we will see quite a bit of that. Half is going south and about half is going north. Will that make its way down to Great Lakes? It's a potential.

At this time it hasn't but it is a potential, if our customers want to access the Dawn market for example, they go up into Great Lakes and then through St. Clair into our system at Dawn, right? But right now, we haven't really sold any paths like that, but it is a potential, there is quite a lot of volumes there, and we are, as you can imagine, we're probably actively marketing that right now.

The second question was ANR was down this last quarter and yes, that's correct. Although our commodity -- our transportation revenues were higher, we did have higher costs, mostly O&M costs, mostly related to the TBOs we had to carry on other pipelines, we had higher costs there. And we just had lower storage spreads in our area for that season so it was modestly down, yes.

Okay, and just maybe a quick follow-up, staying with pipes but shifting gears to the far north in Alaska, I was just curious, obviously very far-off project, but as the new framework comes into being, what does that mean for TransCanada's net development costs? Is that capped out?

I'm not sure what you mean by capped out. Is the development costs that we'll incur over the next few months are fairly minimal, as we sort of do a pre-investment decision analysis. Those costs will be capitalized, because under the contractual structure, they're recoverable if the project doesn't move forward. So they aren't going to be material, but they won't affect earnings, either.

Okay that's helpful, thank you so much.

Our next question is from Matthew Akman from Scotiabank.

A couple questions on the main line and then on KXL. Regarding the main line, I read the NEB judgment that they really had no issue of substance with your application but more of process. So in that context I'm wondering if when you file in the coming weeks, whether you have any more support or consultation you've done to enhance the filing you made previously?

Yes, we are, as you can imagine, we are talking to all the stakeholders that did not support that application. First of all, I kind of agree with your assessment, the Board was talking critical to the process when they made that letter out, and that's what we'll take care of when we file the amended application, we do plan on filing and putting more information in there that will hopefully solve some of the questions that they raised in their letter, and we are consulting with the stakeholders that did not support the application. Right now, I think it's too early to say if we're going to be able to bring the stakeholders on site with the application but we certainly are trying hard, yes.

So just to confirm, this application is still separate from Energy East, correct?

Yes, this is really -- we're working right now on what we call the LDC settlement, it's a settlement we made for segmentation of our system and to allow the customers in the east part of our system to access other supply basins, so anything within Energy East will be filed with the Energy East application.

Okay thanks for that. On Keystone XL, maybe this is hard to answer, but I guess this is for Russ. Reading the Department of State language and what they said in their press conference, I mean is there any way you can really construe their reasons for delaying as part of a national interest test? To me, those were more really local parochial issues. How does that factor into a national interest test?

Well I think we would have the same questions. Our view is that they don't. I mean, I think the three reasons they gave, firstly that they need to give the agencies more time to complete their comments. I guess our view is after 5.5 years, our thoughts would be that the agencies would have supplied all of their comments by this point in time.

The second reason was that they needed more time to process 2.5 million comments, and that some of those comments had unique characteristics to them. We're in the process of responding to those, but I think our view at this point in time after 17,000 pages that it's not 2.5 million comments, it's one comment 2.5 million times. So again, I can't really see a reason why we have to, why the process gets delayed.

And then with respect to the third issue in Nebraska, it's a particular legal issue. It's got nothing to do with the merits of the pipe. It really is a question of who has jurisdiction to make the decision and to approve the pipeline. Is it the Governor of Nebraska or the Public Utilities Commission?

All the work was done by the Nebraska Department of Environmental Quality and embedded through the Department of State, so anything that happens there isn't going to have a material impact on the national interest determination, so I guess our view is maybe I'm just agreeing with you, that there really isn't a reason for this delay. At the current time, we would hope that we can work through these issues as quickly as we possibly can, and get the process to a point of a decision.

Okay thanks. Those are my questions.

Our next question is from Steven Paget from FirstEnergy Capital.

Could you please comment maybe on the dollar amount of non-committed projects under development, or under evaluation?

I'm not sure I understand the question, Steven, but if it's the amount of extent that we have for projects that we're working on that haven't been capitalized yet, we expense all of that, and it would sort of flow through as part of our business development expense.

Steven, is it fair to say you're wondering about the order of magnitude of the portfolio on a capital cost basis, of opportunities that we may be looking at?

Exactly. Over and beyond the CAD36 billion that you discussed at the AGM.

Oh, okay sorry about that Steven. I misinterpreted the question. So no, I could tell you the numbers, probably another CAD30 billion or CAD40 billion. If you add up things like the Bruce Power restart, that's probably a CAD10 billion to CAD15 billion kind of project.

Alaska is CAD60 billion-ish will end up with something probably between 10% and 25% of that project at the end of the day. We're working on various things in Mexico for example, but they've announced five or six new pipelines. The NGTL system, additional connection to more LNG facilities and continued expansions of the NGTL system, so I think you add up that bundle of stuff and it probably gets you to another CAD35 billion or CAD40 billion of what I'd call real kinds of tangible things we're working on currently.

Excellent, thanks, Russ. With Keystone, looking at the map, you could see that there's a pipeline that goes from Alberta all the way to the Gulf Coast, so there is system and it needs an extension piece, XL, but how has the development of the Gulf Coast extension affected flows through Keystone? Or in other words, how much of Keystone's oil now continues down the Gulf Coast extension?

This is Paul Miller here. The flows on Keystone continue to flow at about 530,000 barrels a day. What we're seeing is those flows on Keystone continuing down to the Gulf Coast, probably about CAD0.20, there's some very big loads that Keystone feeds in the Upper Midwest and at the Cushing market and we continue to serve those markets

But the added flexibility that Keystone is affording the market has seen some of those barrels divert down to the Gulf Coast, about 20%. And we're also seeing loads, barrels being picked up right at the Cushing market as well. So from a Gulf Coast flow perspective we're flowing about 300,000 to 400,000 a day south of Cushing down to the US Gulf Coast.

Thanks, Paul. Those are my questions.

Our next question will be from Robert Kwan from RBC Capital Markets.

Just to start on ANR, I'm just wondering with the new contracting, if you can give a sense of just the magnitude of the upside, or the recovery in results that you anticipate? And then just shifting to the expansion potential. Just any color on potential magnitude of volumes, how big that could be, and then would that be compression or looping?

Yes, Robert. This is Karl here. The financial implications of that, keep in mind that we're going to see about half the volumes starting to come on later this year, and the other half during next year. So we'll see the full impact of the FY16.

We're expecting, come 2016, we're expecting to be back at an EBITDA number for ANR that would be consistent with say 2010, so back to what we consider a normal run rate. If we get a recovery of the storage market, it might even be better, but the 2010 EBITDA was in the CAD300 million range, so we are expected to get back in that range in 2016.

Your second question on the expansion, we are working with some of our customers right now on an expansion of that system. I'm not sure there will be so much as a loop, but it will be almost a new pipeline and we're going to be routing it through to the Chicago area, interconnecting with the southwest portion of the ANR, and landing the volume in and around the Chicago area, so it will be a lot of new pipe rather than just looping the existing infrastructure.

So we are just in the early processes of putting that together and looking for foundation shippers so there will be more to come on that, as time goes by. Volumes that we're looking at right now, probably in the neighborhood of 2 Bcf a day.

That's great. My other question relates to the New York City capacity prices, the May auction cleared at almost CAD19 here. I'm just wondering if you have any color on what's a pretty nice increase year-over-year, as well as you go forward here, just your thoughts on the process as to where capacity prices you think are going?

Sure, Robert. It's Bill. First thing I would say with regards to that, is that you may recall that there was -- the demand curve reset had established the capacity price parameters slightly down year-over-year as a result of that three-year reset.

But so against that headwind, the increase that you note has really been driven primarily by some reductions in available capacity in the city. I know in our own outlooks, we were anticipating the return of some units that had previously come out of service due to forced outage, and I think my explanation as to what's going on at the present time with that price would be that some of those units have been a little slower to come back.

So you'd expect some of those mothballed units to come back online?

That's our view at the moment, yes.

That's great, thank you.

Thank you. Our next question will be from Linda Ezergailis from TD Securities.

Thank you. I'm wondering from a capital expenditure perspective, what is the minimum spend on Keystone XL for 2014 and 2015 that you're obligated to do, based on existing contracts?

Hi Linda, it's Alex. We are, I think our commitment for the balance of the year is in the range of, give or take -- for the entire year is in the range of about 225, but the lion's share of that is taken up with prior commitments, pipes, pumps, et cetera, that have already -- that we've already accounted for.

Okay, thank you, and 2015?

We're obviously doing everything we can to minimize the expense. It is going to be a -- in go-forward years, it's going to be a small fraction of that.

Linda, I guess our 2015 spend will really depend upon timing of a permit and if we're fortunate enough to get a permit in early 2015, our attempt would be try to hit that summer construction window if we can, but we will be very cautious about how we spend our money in 2015. I think unfortunately, as we will be ramping down the costs this year as we ramp them down into next year, most of that is there's a lot of people that are in place planning and supporting this pipeline, getting ready for construction, and I think that the current decision means that we won't be constructing this summer, so we will be ramping down bodies and if we need to ramp down more into next year, if it continues to get delayed, we'll just have to do that.

Okay, that's unfortunate. And the Houston Lateral is still targeted to be in service the second half of 2015?

Yes, that's correct.

Thank you and just one other clean up question. How much cash was collected in main line revenues above your regulated revenue booking, on your become statement?

Are you asking for a forecast of 2014?

Well, I'd love that too but I think that would be a little bit a gas call; just for Q1 would be great.

It was pretty substantial in Q1, and was probably in the neighborhood of CAD350 million overcollection of our revenue requirement in Q1. We are forecasting, and we will be filing some reports with the NEB up here next week or so, showing that our full year collections will be substantially greater than our revenue requirement. Revenue requirement for the full year will be about CAD1.6 billion, and our collections will be slightly over CAD2 billion.

For the full year, okay. Wow, that's great. Thanks.

Thank you. Our next question is from Juan Plessis from Canaccord.

With the recent long term contracts you've negotiated for ANR, would you see that system as sufficiently contracted for consideration as a sale into the LP, or would this be considered only after assessing future expansion potential for the system?

I guess the short answer is yes. We are targeting as part of our financing program for this CAD38 billion of capital projects to probably bid in over time all of our assets in the US and the LP, so certainly the contracting and the work we're doing in ANR is making it more attractive for the LP to take, and more stability and longer term contracts.

We would also, as part of our ongoing support for the LP, we would be continuing to do the expansion projects within TransCanada, and bidding those projects in afterwards even if we had amended into the LP. So I think the short answer to your question is yes, it is on our financing plan and our radar that these plants are probably more efficiently held in the LP, and as we need money for our capital program, we'll be bidding them all in, and this particular outcome is actually quite good for that.

That's great, thanks, and this question perhaps for Bill. In the MD&A, you've given us the hedged amount for US Power in 2014 and 2015. Can you tell us what percentage of expected western power sales volumes are hedged for the rest of the year, and for 2015?

Actually I can't. We've refrained from giving that detailed information, given the competitive sensitivity of it in the Alberta market, but I can tell you that our approach at the present time to hedging is similar to that which we've pursued in the past.

Okay, thanks for that.

Thank you. Our next question will be from Andrew Kuske from Credit Suisse.

I guess my question is for Alex, and this is a bit of maybe bigger picture, longer term question. There's been some talk in the Ontario power market on potentially going to a capacity market in the future. I guess, what's your thoughts as one of the biggest generation holders or owners in the province aside from OPG, on any potential transition to a capacity market, because you do have, obviously, capacity market exposure elsewhere?

Andrew it's Alex. I'd love to answer that but Bill will probably throw his pen at me, so maybe I'll let Bill give his thoughts on that.

I guess I would start by saying that the experience in US markets with capacity markets has been an evolving process, and as you know from studying it yourself, I'm sure there's been some challenges in the NEPOOL context, for example, in terms of refining that market, and similarly in New York. I mean I guess our perspective on Ontario is that the market at present is largely an energy balancing market, and the number between direct rate regulation in the form of OPG or direct contracting in the form of the bulk of the other generation in Ontario, some of which we own and operate, and included in that category would be Bruce Power. The bulk of the market is largely under contract, so the notion and support of behind the need for a capacity market in Ontario, our view is that that's questionable.

Well I guess longer term it's really driven in part by their balance sheet and the inability to afford some of the contracts, but I digress. Do you see this potential though in, say, the mid 2020s, for some of the PPAs roll off for a capacity market?

Well I think at this juncture, the conversation seems to be driven more by the need by the ISO's concern over relating the Ontario market to adjacent markets, as well as the systems turnover concerns that they have. So we're kind of engaged in that process right now, with the ISO in Ontario, relative to looking at that and we haven't really turned our attention to that capacity market being a replacement for end of contract time periods. It's just more been trying to address the immediate need, as to whether this is something that really needs to be done right now.

That's very helpful. And then I guess more specific to the here and now, do you see any opportunities in the foreseeable future to really expand the nuclear presence, and not just at the Bruce, the Bruce is obvious, but with some of the OPG holdings at Darlington?

Our focus right now is just relative to the effort that is under way at Bruce Power. I think you may be referring to some comments that Bruce Power made in the media a few weeks ago, and I think those comments were maybe largely misconstrued.

The reality is that the government has in the past encouraged Bruce Power and OPG to consider where they can find efficiencies between the efforts that they're undertaking in the market, and we of course, are supportive of Bruce trying to do that, because any efficiencies that can be gained would be helpful to Ontarians, and potentially to Bruce Power. But we're not really looking beyond that effort at Bruce.

Okay, great, thank you.

Our next question is a follow-up question from Steven Paget from FirstEnergy Capital.

Thank you. You've discussed potential in the past regarding the extension of NGTL under Coastal GasLink, and the second hub in Central BC. Is that still a possibility?

Yes, Steven, it's Alex. We did, we held a request for service. We did get a significant amount of interest from parties requesting service in the Vanderhoof area, so as I understand, Karl might want to jump in, but I think we're working with those parties to finalize their interests, and if we get that commercial underpinning, NGTL will file an NEB application.

Thanks, Alex.

Our next question is a follow-up question from Robert Kwan from RBC Capital Markets.

Thanks, actually just following on the NGTL topic. Just when you move the system into NEB regulation across-the-board, you face pretty minimal resistance on rolled-in tolls. I'm just wondering, as the projects get bigger and maybe a little more specific to certain producers, I'm wondering if you're seeing any greater opposition to rolled-in tolls?

That's a good question. I guess the answer today is that the opposition to rolled-in tolls is typically coming from our competitors, and not the people, not the customers on our system. So as of today, I would say no greater opposition of rolled-in tolls.

I would tell you, the Board is mindful of that. I think that a year or two years ago, we had an application turned down because they didn't feel there was enough support for rolling in the particular toll, that was the Komie North application, so I know the Board is mindful of it. But as for our actual shippers on our pipeline we haven't seen any resistance for them, or any initiative on their part to try and change how we roll in our tolls, but certainly, we do get some interventions from competitors who would prefer we not do that.

Okay, thanks, Karl. And just a very quick last question, just on Bruce. I think you're booking the B units based on the floor. I'm just wondering, are you able or are you quantifying what the deferred revenue amount on the revenues you earned but didn't book during the quarter?

Yes, obviously we're tracking that, but for the first quarter, the amount, had we recorded it would have been roughly CAD0.035 but because we don't feel that we'll realize that over the course of the year, we did not record that into our first quarter earnings.

Sure, makes sense. Okay, thank you.

Our next question is also a follow-up question from Carl Kirst from BMO.

Thanks. Appreciate the time here. Russ, this is really just more of an XL follow-up, and I guess the question, just so I'm thinking about it correctly is, if we have the Attorney General of Nebraska already filing an appeal, and we already have a route that's been approved by the DEQ, is there any downside from taking a parallel path filing with the utility commission, just to get the clock to start ticking?

Carl, it's Alex. Right now, the position we're taking, I think that is an option that is available. We'll obviously consider that option, but I think right now, we're focused on the legal route through the appeal, the Attorney General, and the governor. They feel that they have a very strong case, so we're going to be focused on that, but at the same time, we're going to make sure we keep our options open.

Okay, fair enough, and just a quick follow-up for Don. You had mentioned with respect to the first quarter income tax rate of 27%, when you exclude the pass through items. Is that something that we should expect for the rest of the year?

Yes, I think for the rest of this year and actually first look in 2015, something in the 27% to 28% area looks reasonable right now. A little higher than the Canadian statutory rate. What's driving that is growing income from higher tax jurisdictions, mainly in the US with Gulf Coast coming on, some expected recovery in ANR and US Power.

Okay, thank you so much.

We will now take questions from members of the media.

(Operator Instructions)

Our first question is from Chester Dawson from the Wall Street Journal.

My question is in regard to rail terminals, and whether it's due to the Keystone delay, or otherwise. Can you provide anymore specificity on how seriously you're looking at that, and how soon you might move into it, if it's an area that you do want to get into?

I'll take a first cut at it and then Paul or Alex might take a shot at answering that as well, Chester. Obviously with the delays, production in Canada and the US has continued to rise. The whole notion that delaying the pipeline is going to somehow delay production is obviously misguided, given that production is up about a million barrels a day in Canada and 2 million barrels a day in the US.

So rail volumes are on the rise. Our customers have asked us to look at a rail bridge between Alberta and US points and places like the delivery points on our Keystone pipeline system. I'd say that since the delays, the intensity of those calls has gone up quite substantially, and our team is engaged in active discussions with them, to determine whether or not they're commercially viable. And if they are, then we'll bring them forward, but I would say that the last couple weeks, that activity has obviously increased quite a bit.

I'd only add that our shippers recognize fully the value of Keystone as the preferred mode of transportation, but they also recognize the value of having rail as a bridge to pipeline development, so we'll have conversations with them. We'll review this opportunity and progress it, as the parties feel is appropriate.

Thanks, and just a follow-up quickly on that. Is that something that you've already begun planning in terms of blueprints for routes, or is it just very much in the conversational stage? And secondly what about beyond that route? Are there other areas where you think rail terminals might be a solution?

On the routing perspective, TransCanada's interest would be limited to the onloading facilities and the offloading facilities. The intent would be to use existing rail infrastructure.

And then in regard to location for those particular terminals, again we would view those terminals to be optimally placed at obviously the supply side, as well as the market side, proximate to our existing infrastructure or our planned infrastructure. So we've done a lot of work in scoping out locations. We've done some work in regard to design, and so it does position us well to the extent that our customers want us to proceed on this, and again to the extent that we can reach appropriate agreements with them to do so.

It is something, Chester, that we could move on relatively quickly. We've done a pretty substantial amount of work at the terminal end at both the receipt and delivery points, and that's really what our key role in here would be. A lot of the tankage is already in place, so it's a matter of building rail sidings and those kinds of things, which aren't overly complicated, and we have spent some time engineering those things.

Okay, thank you.

(Operator Instructions)

Our next question is from Iris Kuo from Argus Media.

First of all, what are your thoughts on the bill in the Senate that would force the approval of Keystone XL? Is this something that you support, or think is likely to pass?

We can't make any comments on the likelihood, or anything like that. I guess our view is that anything that advances the decision on Keystone pipeline is something that we would support. There's a lot of work that's been done to date. Obviously 5.5 years, 17,000 pages and five environmental reviews, there's enough information available to make a decision.

Our focus though isn't on political process. Our focus is on the regulatory process, which is to continue to work with the State Department, and to try to answer all of their questions, and bring this to a point where they no longer have any questions and they can move to recommendation, and make a decision. That's our focus at the current time, but obviously, we continue to appreciate the support of many others that want to see this decision made as soon as possible.

Got you. Then just to confirm something that was said earlier, was it the throughputs on Gulf Coast pipeline are about 300,000 to 400,000 barrels a day; was that correct?

Yes, that's correct. 300,000 to 400,000 barrels a day.

Okay, great. And can you tell us how much of that is heavy crude?

I don't have that mix. It does have the ability to take the domestic lights, as well as any heavies that find their way down to the Cushing market, so it is a combination of the heavies and the light. I just don't know what the percentage is.

Okay, and then just sort of a more general question. Cushing inventories are, I think it's five-year lows and Gulf Coast inventories are at record highs, and that's something that's attributed obviously to the start-up of the Gulf Coast pipeline. Could you just share any general thoughts on just US inventory dynamics, as well as what the current situation might be expected, what kind of impact it might be expected to have on throughputs on the pipeline?

Sure. Maybe I'll start with the second question first. With regard to the throughput, we anticipate throughput probably averaging north of 400,000 barrels per day this year, as we ramp up the capability of the system.

Of that, let's call it mid-400,000 range, more than three quarters of that is contracted. It's contracted under take or pay contracts which means that the shipper is obligated to pay us for that capacity, whether they ship or not. So from a throughput perspective, we are watching the inventory levels at Cushing, but we're also watching the new production coming out of the Permian, as well as some inbound pipelines that we anticipate later on this year. So don't see any, certainly don't see any decrease in the throughputs on our extension down to the Gulf Coast, and in fact we do see throughput increasing as the year goes.

In regard to the general inventory levels at the Gulf Coast, we do see barrels continuing to flow down from Cushing down to the US Gulf Coast. Domestic production has pushed out the foreign light. I think with blending and other techniques, the domestic production will continue to push out the medium, and perhaps medium sours, and I do see movement from Gulf Coast up to other points within the United States and Canada, of some of that domestic crude that's coming in from the likes of Eagle Ford.

So I think you'll see changing market dynamics going forward. I think you'll see a general build of inventory on the Gulf Coast, which will necessitate additional storage, but I think will also mean additional barrels moving to other parts of the United States and Canada.

Got you, and I apologize. Who was just speaking?

I'm sorry, it's Paul Miller.

Okay, thank you very much.

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

Okay thanks very much, and thanks to all of you for your interest.

I'm sorry, we have not heard all your closing comments.

Sorry, we may have got cut off there. Again I'd like to thank all of you for your interest in TransCanada. We very much appreciate your time this afternoon. We know its been a bit of a long day with our AGM and other things, but once again, thanks, 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.