TC Energy Corporation
Q3 2014 Earnings Call Transcript

Published: 4 Nov 2014

[Operator:]

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2014 Third Quarter Results Conference Call. I would like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations. Please go ahead, Mr. Moneta.

[David Moneta:]

Thanks very much and good morning everyone. I would like to welcome you to TransCanada’s 2014 third 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, Executive Vice President and President of Development; Karl Johannson, President of our Natural Gas Pipeline business; Paul Miller, President, Liquids Pipelines; Bill Taylor, President, Energy and Glenn Menuz, our Vice President & 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 Investors section under the heading Events & 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 will 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 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 U.S. Securities Exchange Commission. And finally, I would 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, and funds generated from operations. These and certain other comparable measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are provided 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 will now turn the call over to Russ.

[Russ Girling:]

Thank you, David and good morning everyone and thank you very much for joining us. I am very pleased to announce today that our three core businesses

[Don Marchand:]

Thanks, Russ and good morning everyone. For a review of our third quarter results in detail, I would like to highlight a few key messages. Our core asset base generated solid third quarter results with $3.5 billion of new assets making notable contributions. We secured $4.7 billion of new Canadian regulated natural gas pipeline investment opportunities that are expected to enhance near-term growth and earnings and cash flow. And finally, we remain well-positioned to fund our $46 billion portfolio of commercially secured projects with predictable and growing cash flow, a strong balance sheet and access to most attractive external funding sources. Now, moving to our consolidated results shown on the next slide. Net income in the third quarter was $457 million or $0.64 per share compared to $481 million or $0.68 per share in the same period in 2013. Excluding unrealized gains and losses from changes in various risk management activities, comparable earnings in the third quarter of $450 million or $0.63 per share were in line with results for the same period last year. New contributions from the Keystone Gulf Coast Extension and the Tamazunchale Extension in Mexico, strong Bruce Power results, along with higher realized capacity prices at U.S. power were offset by reduced earnings from Western Power. Turning to our business segment results at the EBITDA level, our natural gas pipelines business generated comparable EBITDA of $750 million in the third quarter of 2014 compared to $684 million for the same period last year. Canadian gas pipelines’ comparable EBITDA of $557 million increased $38 million compared to 2013 principally due to flow-through items on both the Canadian Mainline and NGTL, which do not have an impact on net income. Net income from the Canadian Mainline was $6 million lower compared to the same period last year as a result of a lower average investment base as well as carrying charges owed to shippers stemming from a positive total stabilization account balance. NGTL’s net income increased $4 million in the third quarter to $61 million due to the positive impacts of a larger average investment base and a higher allowed return on equity of 10.1%. Our recently filed settlement with shippers on the NGTL System will see the current allowed return on equity and capital structure extend another year through 2015. The one-year deal also includes a continuation of 2014 depreciation rates and a mechanism for sharing variances above and below fixed OM&A expense amount. U.S. and international Natural Gas Pipelines’ comparable EBITDA of $188 million increased $16 million compared to the third quarter of 2013, primarily as a result of the commencement of contract revenues being recognized from the Tamazunchale extension and the positive impact of a stronger U.S. dollar. Moving to liquids pipelines, the Keystone pipeline system generated $275 million of comparable EBITDA in the third quarter. This represents an $82 million year-over-year increase and is the result of the Keystone Gulf Coast extension which was placed into service in January along with the favorable impact of the stronger U.S. dollar. Turning to energy, comparable EBITDA was $387 million in the third quarter compared to $410 million for the same period last year. The $23 million decrease was the result of a combination of factors. Western Power comparable EBITDA declined $38 million due to lower realized power prices. Despite robust pricing in July, strong coal fleet availability and new wind generation led to weaker prices overall. The third quarter average pool price was $64 per megawatt hour compared to $84 in same period last year. Equity income from Bruce Power increased $6 million to $111 million in the third quarter compared to 2013 primarily due to lower depreciation and operating expenses at Bruce A, partially offset by recognition of higher lease expenses. Unit five at Bruce B is presently undergoing a planned two-month maintenance outage that began at the beginning of October. The remaining seven units at Bruce Power are currently operating at full power and no further maintenance outages are planned for the remainder of the year. U.S. power comparable EBITDA increased $13 million in the third quarter compared to last year, primarily due to higher realized capacity prices in New York and the favorable impact of the stronger U.S. dollar. In late September, the 972 megawatt unit 30 at Ravenswood experienced an unplanned outage as a result the problem with the generator associated with the high pressure turbine, because in extent to the necessary repairs is currently under investigation. Insurance is expected to cover the cost of repairs and lost revenues from the outage. As a result the outage is not expected to have a significant impact on earnings. Natural gas storage comparable EBITDA of $3 million was down $6 million compared to the same period in 2013 due to lower realized storage spreads. Now turning to the other income statement items on Slide 19, comparable interest expense rose $69 million in the third quarter to $304 million from $235 million in 2013. This increase was primarily due to interest charges on recent U.S. dollar debt issues, higher foreign exchange on interest denominated in U.S. dollars and lower capitalized interest. As I have highlighted in the past, the exposure to U.S. dollar income is largely offset with U.S. dollar denominated interest expense and financial derivatives. The net impact being that currency movements are not expected to have a material impact on earnings over a rolling 12 month forward period. In the third quarter $57 million of interest was capitalized to assets under construction compared to $80 million for the same period in 2013. Lower capitalized interest due to the completion of the Gulf Coast extension of the Keystone system was partially offset by higher capitalized interest for Keystone XL and other liquids and LNG related pipeline projects. Comparable interest income and other in third quarter 2014 rose $33 million compared to the same period in 2013 primarily due to increased AFUDC related to our rate regulated projects. These include Energy East and our Mexico pipelines, which qualify for rate regulated accounting. Partially offsetting the increase in AFUDC were higher realized losses on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar income and the impact of the strengthening U.S. dollar on translating foreign currency denominated working capital balances. Comparable income tax expense for the third quarter 2014 increased $58 million versus the same period last year due to higher pretax earnings, changes in the proportion of income earned in higher tax jurisdictions as well as higher flow-through taxes on Canadian regulated pipelines. Excluding Canadian regulated cost of service pipelines, the consolidated effective tax rate in 2014 is expected to be approximately 27% to 28%. Net income attributable to non-controlling interests increased $8 million compared to the same period last year primarily due to the resumption of TCPL Series U preferred shares in October 2013 and Series Y preferred shares in March 2014. Preferred share dividends of $24 million were $4 million higher in third quarter 2014 as a result of the $450 million Series 9 issue completed in January 2014 at TransCanada Corporation. Now, moving on to cash flow and investing activities on Slide 20, cash flow remains solid with funds generated from operations of approximately $1 billion in the quarter and $3.1 billion year-to-date. Capital expenditures were $853 million in the third quarter driven principally by Mexican Pipelines, NGTL System expansions, Energy East and construction activities on the Houston Lateral and Tank Terminal. Equity investments of $66 million in the quarter reflect activities related to the Grand Rapids Pipeline and Bruce Power. Finally, three additional solar facilities in Ontario were acquired at the end of September at a cost of $181 million. Now, turning to Slide 21, our liquidity and access to capital markets remain strong. At September 30, our consolidated capital structure consisted of 40% common equity, 5% preferred shares, 2% junior subordinated notes, and 53% debt net of cash. We have $698 million of cash on hand, along with $5 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 U.S. remain well supported and continue to provide flexible and very attractive sources of short-term funds. On October 1, we closed the sale of our remaining 30% interest in the Bison Pipeline to our limited partnership, TC PipeLines, LP for cash proceeds of $215 million. The Bison transaction advances our previously stated commitment to sell the remainder of our U.S. natural gas pipeline assets to the partnership on a systemic basis. The U.S. gas pipes that continue to be directly held by TransCanada are expected to generate approximately $480 million of EBITDA in 2016 and beyond. Dropping the remainder of these assets into the LP in a conveyor belt-like approach on a more sizable frequent basis into the LP is considered the optimal approach for providing us with significant cash proceeds to help fund our capital program. This will also serve to enhance the size and diversity of the Partnership’s asset base and position it with visible high-quality future growth going forward. As Russ highlighted, our strategic asset footprint continues to provide us with tremendous opportunities to invest capital in our core businesses. Today, we have approximately $13 billion to $14 billion of secured small to midsize projects that are expected to be placed into service over the next several years providing strong visibility to future earnings and cash flow. We remain well-positioned to fund this suite of shorter cycle projects with predictable and growing internally generated cash flow from our three core businesses and senior debt consistent with our A grade credit rating. Other sources of subordinated capital, including further LP dropdowns, preferred shares and hybrid securities will also form part of our financing strategy. Beyond these funding sources, as we progress our $29 billion of large scale capital projects, we will also consider additional portfolio management activities, the introduction of partners, selective use of project financing and reinstatement of our dividend reinvestment program from Treasury as alternatives to large scale common equity. In closing, the company produced solid third quarter results, which highlight the benefits of our broad base of blue-chip pipeline and energy assets. $3.5 billion of new assets have been placed into service in 2014 and are now contributing to earnings and cash flow, including the Keystone Gulf Coast Extension, the Tamazunchale Extension, as well as various expansions of the NGTL system. An additional $180 million of newly acquired solar facilities is set to add to this list in the fourth quarter. Furthermore, we continue to make significant progress in advancing our $46 billion of commercially secured projects and are well-positioned to finance the capital program that lies ahead. This industry-leading portfolio of critical energy infrastructure projects is expected to generate significant growth in earnings, cash flow and dividends for our shareholders the remainder of the decade. That’s the end of my prepared remarks. I will now turn the call back over to David for the Q&A.

[David Moneta:]

Great, thanks, Don. Just a reminder before I turn it over to the conference coordinator to take questions from the financial community first. And once we have completed that, we will then turn it over to the media. And with that, I will turn it to the conference coordinator for your questions.

[Operator:]

Thank you, Mr. Moneta. (Operator Instructions) And the first question is from Paul Lechem from CIBC. Please go ahead.

[Paul Lechem:]

Well, thank you, good morning. Just with regard to the NGTL System expansions you have announced this morning, in the press release you mentioned 3.1 BCF a day of volume relating to firm receipt service. I was wondering if you can give us some details around that, where the 3.1 BCF a day of demand coming from? Is any of that specifically related to LNG, any of the LNG products on the West Coast? Is any of this 3.1 BCF a day at risk if some of these projects don’t proceed?

[Karl Johannson:]

Hi, Paul, it’s Karl. Yes, I could say that all this volume, all this receipt volume is what we call organic growth. It is not contingent on any LNG projects going forward. It is meant to go into our overall system and through our net system and diverse markets on our system. So, it wouldn’t be contingent to any LNG going forward. I would say that of our announcement here that 3.1 BCF a day is made up of 21 different receipt sites and projects. So, it’s well-diversified through our system and from various receipt points.

[Paul Lechem:]

Thank you. Switching gears to Keystone XL, just couple of related questions maybe just on the cost increase, you mentioned in the presentation that there is a threshold in terms of the split of 75-25 split, can you give us some details around when that threshold or what level does it switch over to the 50-50? And then secondly, given the increase in the cost now, can you give us some sense of what it will cost on a per barrel basis from Alberta down to the Gulf Coast if you shipped Keystone XL versus through Energy East and then on a tanker down to the Gulf coast, can you give us some sense of how those two measure up? Thank you.

[Paul Miller:]

Hi, it’s Paul Miller here. In regard to the first question with this new cost estimate for Keystone XL, we have rebased our total at the new cost estimate in the 50-50 sharing begins at this point. In regard to the tolls down to the Gulf coast, we haven’t published those tolls yet. I can’t tell you though relative to the other opportunities, relative to the other land-based opportunities, Keystone XL toll at this capital cost remains competitive, it remains under the other land-based opportunities and it remains under the opportunities to Energy East and then moving down to the Gulf coast.

[Paul Lechem:]

Okay, thank you.

[Paul Miller:]

You are welcome.

[Russ Girling:]

Thanks, Paul.

[Operator:]

Thank you. The next question is from Linda Ezergailis from TD Securities. Please go ahead.

[Linda Ezergailis:]

Thank you. Just a follow-up question on the new Keystone XL cost estimate, can you give us a sense of either what you are assumed in service date is embedded in cost or how much contingency you have provided for further delays in a Presidential permit, i.e., what’s the risk of that cost increasing further? And can you just give us an update on your expected returns from the project we could probably calculate it, but you obviously have a better sense of that than we do?

[Alex Pourbaix:]

Sure, Linda, it’s Alex. I would say right now, where we are in the process, as Russ said we are really kind of in a bit of a just a waiting mode on Keystone XL. So, we have really limited capital and any sort of growth in capital cost right now. So, I don’t expect a lot of impact. And in that number that we quoted, we do have a contingency that we think is reasonable to get the project done. As for returns, we are still in that range that we have quoted in the past.

[Linda Ezergailis:]

Okay, that’s helpful. And with respect to capital cost, the $1 billion drop versus prior plan in 2014, is that a shift to 2015 or sort of a change in scope, maybe you could provide some context?

[Don Marchand:]

Yes, hi, Linda, it’s Don here. It’s – firstly, it’s fairly across the board. There is no specific project that are – that can pin down with the $1 billion move. It is largely a time shift as we just look at different construction profiles and regulatory approval processes.

[Linda Ezergailis:]

Okay, that’s helpful. Thank you.

[Russ Girling:]

Thanks, Linda.

[Operator:]

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

[Carl Kirst:]

Thank you. Good morning, everybody. Maybe if I could start, I just, Russ, like to kind of get a little bit better clarification on the Eastern Mainline project and I think in your prepared remarks, you said that this is specifically going towards to replace capacity to the export market, to the U.S. markets and not necessarily to address I think some of the concerns the utilities have. I guess I am just trying to kind of get a better sense of what perhaps some of the contentious issues are still out there and what still needs to be overcome?

[Russ Girling:]

Well, I think the two issues that have been raised are firstly, will there be sufficient capacity available to meet the needs of Eastern Canadian consumers? And the answer to that is yes, I would say that we are committed to doing that. And that the costs that are borne by our Eastern Canadian gas shippers should not be negatively impacted by the Energy East project and again we have said that, that won’t occur. We have committed to that. And in fact in our filing the way that we have structured it with the Eastern Mainline project and the contributions and whatnot that we made that all details in the filing results in a savings through to 2030 of about $950 million. So, we believe we have satisfied those questions. And maybe I can just provide some clarity on that? My comment that this is export capacity, the Eastern delivery area of our system has a capacity of 3.2 billion cubic feet a day. What we have said that we are going to do is we are going to remove about 1.2 billion cubic feet a day of that capacity and via the Eastern Mainline project will add back 600 million cubic feet a day. So, essentially we are reducing the capacity from 3.2 to 2.6 and historically that system has been used probably 50-50 I would say by gas shippers – or by export gas shippers and domestic gas shippers. Domestic shippers were contracted to the tune of about 1.6 billion cubic feet a day and in recent times they have increased that contractual level to about 1.8 billion cubic feet a day and slightly greater than 1.8 billion cubic feet a day. So, we feel totally comfortable at 2.6 billion of installed capacity that will have ample opportunity to meet domestic load. On the flipside, export contracts have fallen from about 1.6 billion cubic feet a day that we had in 2007 to about 700 million cubic feet a day today. So, we have lost about 900 million cubic feet a day of export contract and it is that export contract capacity that we are converting that 900 million, we take it about 600 million of it and we have converted into Energy East. So, our view is simply if there is efficient capacity to meet the needs, we have held several open seasons and we will continue to converse with our customers to ensure that we understand their need to make sure that the capacity is available, but certainly, our objective is to make sure that we’d right-size our system and to optimize its usage for all the users of it, if we optimize the usage for all users. Certainly, unit costs come down and unit cost reductions, means everybody saves and we think that’s a good thing. And as I said that is detailed in our application.

[Carl Kirst:]

Very helpful color. Thank you. So, just to be clear than the Eastern Mainline is basically an integral where it’s incorporated into the larger Energy East filing, it’s not good and not going to have its own procedural schedule?

[Russ Birling:]

It will have its own procedure. There are two separate applications that are tied together and that was from the National Energy Board to have the application separate, but together if you will.

[Carl Kirst:]

Excellent. And then one clarification just on the cost of Energy East and certainly appreciate the $1.7 billion guidance on EBITDA, I think historically we have talked about the $12 billion of Energy East being sort of what you might call the external capital. Is it correct we should still be using $1 billion of asset transference from the mainline? And then it looks like with the Eastern Mainline there maybe an additional $250 million sort of contribution, so should we think of Energy East $13.25 billion and $1.7 billion of EBITDA. Are those the apples-to-apples numbers we should think about?

[Russ Birling:]

I think that’s a good way to look at it Carl. And in addition there is another $250 million in there because there is a $500 million contribution but essentially that $250 million will be absorbed by TransCanada if you will and they won’t go into the Energy East rate base.

[Carl Kirst:]

Understood. And then last question if I could just for Don and this – I mean Don as you try and manage here the portfolio and just thinking the potential lumpiness here for if Petronas moves forward, if XL moves forward, etcetera. As you get some larger projects happening and I guess perhaps in light of the current volatility we are seeing in the equity markets today, how comfortable are you with the equity requirements being sort of perhaps if we have a three year project for instance the equity requirements can be done over a period of three years or if we feel the sudden $10 billion plus worth of projects, we need to somehow raise all that equity be at synthetic or otherwise very quickly upfront. I didn’t know if that was something you can give more color to?

[Don Marchand:]

Yes. It’s a good question. And we would take some comfort from the fact that pretty much the entire portfolio is contracted or cost of service regulated assets, so very low volatility assets. I will walk you through the thought process starting with the small to mid-size projects which totaled probably $12 billion to $13 billion. We do have debt capacity within the constraints of the credit rating. We pointed to the amount of assets we are going to vend into the Pipe LP. And then we will look to preferred shares and hybrid securities to probably about 12% of our capital structure, they are around 7% right now. So that part of the portfolio looks imminently financeable with those instruments. As we move to the bigger more bindery outcome projects here a couple of points to note there. For the LNG projects to the West Coast, we would consider project financing of those. They are very tightly commercially constructed and that’s something that we would potentially be able to attract a different source of capital for those projects. So that’s something that we would definitely look at for those. As the balance sheet grows we will again shoot through the cheaper sources of capital, eventually we will get to a point where we will either have to sell something, introduce partners or issue equity. And at that point in time we will weigh the various costs of those various alternatives. We are not emotionally again selling assets, but again be weighed against those other two potential sources of capital. We will receive a lot of inbound calls from parties looking at co-invest in these projects. So we think partners are certainly something that is eminently introducible into all of the large projects before we start getting to equity. Equity, we look at in two forms. Firstly, would be turning on the dividend reinvestment program. Generally, we could – believe we can attract $100 million to $125 million a quarter of common equity by turning the DRIP on, that line is up very nicely with a long tail construction program where money is going off the door on a continuous basis, but we have got equity capital coming in. In terms of large-scale equity, we would put that at the bottom of the list and again it’s really somewhat dependent on how many of these goes and what timeframe they go into. So not the clearest of answers here, but that’s our thought process as we look at this. We view it as a high grade problem to have with many of these did move forward in the same timeframe. They are large dollar figures. But again given the very solid cash flows in blue-chip energy infrastructure qualities of all of them we think the capital is available there.

[Carl Kirst:]

Excellent. Thanks so much for the color guys.

[Russ Girling:]

Thanks Carl.

[Operator:]

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

[Matthew Akman:]

Hi, good morning or yes, good morning. Thank you. A few questions on the power business, one is just on the U.S. power business and I noticed that your capacity payments continue to trend upward, but there was – and production is also trending upward, but there was a reduction in EBITDA, I am just wondering if that’s primarily due to compressed margins at Ravenswood for the energy portion of the revenue?

[Don Marchand:]

I think the answer to your question in this quarter anyway would relate more to, there is some timing differences with some of our marketing transactions that affected U.S. power, where given the structure of the way some of our retail transactions are put together, flat pricing is applied to customer loads and then we can end up getting movement of revenue between quarters and that’s primarily what’s going on with Q3 in the U.S.

[Matthew Akman:]

So, is that a more normal quarter or was it kind of abnormally high in prior quarters?

[Don Marchand:]

I’d say it was a little abnormal in light of some of the success we had with some of our load marketing businesses in terms of that.

[Matthew Akman:]

Okay.

[Don Marchand:]

We put some term on in the load side that pushed things out for a couple of years.

[Matthew Akman:]

Okay, thanks for that. Moving to Alberta, the acquisition of a little bit more PPA through Genesee, I am just wondering strategically what’s behind the thought process, is that about the Alberta power prices are sort of bottoming out here? Is it just enhancing the overall presence in Alberta and I guess the strategic direction in Alberta generally given the reduction in price we have seen?

[Don Marchand:]

Yes, I think you have – you are correct with those reasons as to why we found this attractive. I mean, we are always active in the market. This opportunity only comes up periodically. And we believe that the market in Alberta is at the moment suffering I guess a little bit from some very good performance on the fleet overall. And as Don mentioned in his remarks, wind generation has been high. So, yes, one could conclude that we maybe looking at some sort of structural lows here right now for the market, so not a bad time to be a buyer.

[Matthew Akman:]

Good, okay, thanks. And then my last question on power is you guys have had good success in Mexico on pipeline, is there any interest in the company in doing contracted power in Mexico as well?

[Don Marchand:]

Yes, for sure. We, as you know I mean have just highlighted, we have had good success overall with our program in Mexico and that continues. And we are looking indeed at the opportunities that are on the horizon on the power side.

[Matthew Akman:]

Okay, great. Thanks. Those are my questions guys.

[Russ Girling:]

Okay, thanks Matthew.

[Operator:]

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

[Andrew Kuske:]

Thank you. Good morning. I guess just a question maybe directed to Russ on Alaska and just an update on what’s going on there as I guess there are some few things to ask about Alaska, just to the extent that you have really done a lot of new things versus just really knocking the dust off of some of the old files, because I guess this has been in the portfolio in one way or another for the last 30, 35 years. So, I just – give us some perspective on that and then really the momentum behind this at this point in time?

[Russ Girling:]

Thank you. As you pointed out, we have been at this for sometime in Alaska and yes, it transcends a few careers here. We have had a few folks retire that started their career working on the project and actually ended their project with another two who are on the project. So, it has taken some time. What we know about Alaska is that the gas is produced. There is associated gas with the oil. It’s in the neighborhood of about 7 to 8 BCF a day today. It’s re-injected into the gas capital. At some point in time, the gas to oil ratio gets to a point, where it’s uneconomic to produce or to continue to re-inject the gas and produce the oil in that way. We are not the reservoir owners or developers. So, we don’t know when that exact date is going to arise, but our feeling is that it’s sometime into the next decade. And that’s why we are seeing the continued push to want to redirect that gas to market. As I said it’s being produced today, it just needs to be redirected to market. So, I think the most positive thing about the recent developments in Alaska is that we have all parties working on the same project in the same direction. There is ourselves obviously but probably more importantly, the three core producers, ConocoPhillips, ExxonMobil and BP as well as the Alaska government all working and rolling in the same direction on a single export project, and that’s what gives me confidence that we are rolling in the same direction. This is the first time in my history at the company working on a project that we are all working in the same direction. Obviously the capital costs are enormous, but I think given that the resource itself, you can think of it as having almost zero cost. So you look at the competitiveness of that product into the LNG market on a unit basis. If you built a large-scale pipeline and liquefaction facility and your resource cost is essentially zero, you are in a pretty competitive situation. And I think that’s the way that producers are looking at it. The key issue remains what are the fiscal terms under which that gas is going to get produced and that’s what I am saying just talk about taxes and royalties again things that aren’t our purview necessarily to be involved in, but we understand that those conversations are active between the producers in the state and again I think all rolling in the same direction because if you get those right, that will give the producers the confidence to make the capital investments and bring that product to market. So it’s out there into the next decade, but we are as a group spending money on the feasibility. And I am confident that at the end of the day that gas will go to market and it will go through a pipeline. So our guess is sort of early to mid-decade that they will have a pretty good handle on when that’s going to happen.

[Andrew Kuske:]

Okay, that’s helpful. And I guess this is a follow up to that if we look back I guess about 10 years ago when Conoco and BP were pursuing the Denali project. And you were allying with Exxon, now that you are all under one roof, so to speak that gives you a lot more confidence if something happens in the – early in the next decade?

[Russ Girling:]

Yes, I think that’s a hugely significant development. Everybody is moving in the same direction for the project.

[Andrew Kuske:]

Alright. If I can just get one other question in on a warmer climate on any interest in electricity transmission in Mexico?

[Russ Girling:]

Transmission in Mexico is not something that we have been focused on at the moment. We have over time looked at a few opportunities to enter that space in Canada and a couple in the U.S., which you may recall but it’s a highly competitive space and not something that we have historically done. We are not adverse to do that side of the power business, but we would look carefully at it before jumping into that.

[Andrew Kuske:]

Okay, that’s very helpful. Thank you.

[Operator:]

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

[Robert Kwan:]

Good morning. If I can just follow-up here just on your power outlook and the Genesee PPA, I guess I am wondering should you probably don’t want to get specifically into price, but it’s fair to say that you buy the PPA materially below the curve instead of just going out to the market and buying back 100 megawatts of hedges?

[Don Marchand:]

Yes, to your point, I am not sure I want to get into specifics of the pricing approach that we took, but I guess I would just suggest that you can assume that purchase price was competitive with the market, with the caveat that as you know there is a fair bit of thinness in the forward market in Alberta. So there is people taking views on that three year outlook including ourselves.

[Robert Kwan:]

Okay, I guess just with that three-year term, obviously you are seeing upside from current levels and even what the curve might imply. Can you just talk about the timing over that three-year period as to how you see the price evolving, is it something where you think that the price expectation right out of the gate into ‘15 is too low or do you think its more something that will evolve as we this through the shepherd capacity?

[Russ Girling:]

Well a couple things as Don mentioned and I guess reiterated in my prior answer the Alberta market at the present time has been played with some really excellent performance out of the current fleet. That drives a lot of the future volatility. We are somewhat bullish on that ‘15 being above certainly where it’s currently trading. And I guess, I would leave it at that, and say that we are comfortable with the Genesee acquisition that we made. And we hope that it will be a good transaction for our overall portfolio.

[Robert Kwan:]

Okay. If I can just ask you one more shifting to Energy East, there has been some articles here just around some local opposition in and around the Cacouna part of the project. Just with the St. John deepwater port how integral is Cacouna to energy did you guys see?

[Alex Pourbaix:]

It’s Alex, so I will take a shot of that I mean and Paul might want to jump in but obviously Québec Marine Terminal was very integral to our service offering in this project and it makes a lot of sense for a lot of our shippers depending on where their ultimate markets for that oil are.

[Paul Miller:]

Yes. And Rob, it’s Paul Miller here. I don’t have much to add. We have said – as we have said in the past we anticipate to serve both the Eastern Canadian market as well as export markets and the Québec location at Cacouna is an ideal port to access some of those nearer markets. And so it’s a real economic opportunity for our shippers to move their crude out of the Cacouna Port. So I think from a total integrated perspective both St. John and Cacouna provide tremendous opportunities for the shippers and we would look to move forward with both facilities.

[Robert Kwan:]

Sorry go ahead.

[Russ Girling:]

Just to be clear I guess this is a – it is an integral part of our service offering. We have customers that have signed up to that location. The folks in Cacouna would like to see a terminal built there, it will create a significant amount of economic activity as well as probably drawing further economic activity. So it’s something that I think all parties want to happen. That said is like with any part of the project if it has the material negative impact on the community, in this case on the beluga whales. And once we collect the information if that’s determined to be the case then we just won’t be able to do it in that way and we will have to figure out how we are going to do this project in a different way. And so it’s integral, but at the end of the day our objective is to build the project that is acceptable and workable for all parties and we are committed to that not just in Cacouna but right across the pipeline.

[Robert Kwan:]

That’s great. Just to be clear that was – is that just because the way you set out the terminal in St. John the ideas that you will just be bottlenecked with the VLCCs coming in there that you wanted to have that extra port to put the smaller boats in?

[Paul Miller:]

No, Robert, it’s Paul Miller here. The way we will operate our pipeline is we will run full line rates effectively to the Cacouna Port, while we are loading Cacouna and we will full line rates to St. John. So when you ask specifically about the St. John, it’s a great deepwater port, it would have the capacity to facilitate full line rates and full movements to the VLCC. So I don’t anticipate there would be any debottlenecks under that scenario.

[Robert Kwan:]

Okay, that’s great. Thank you.

[Operator:]

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

[Steven Paget:]

Thank you and good morning, still. Mainline earnings are down 8% year-to-date but EBITDA is up 15%, how much of the incremental EBITDA flows through the cash flows?

[Karl Johannson:]

Well, Steven, this is Karl. Most of that EBITDA increase is flow through items. It’s mainly because of the over collection that we have had this year for accounting and taxes paid on that, so most of it does flow-through to our customers.

[Steven Paget:]

Okay. Thanks, Karl. And this question I am not sure who it will be for, but TransCanada has had success as an active participant in the Alberta power market, but its long-term presence in the market, long-term presence will decrease considerably within just over six years when all the PPAs are expired, so how should we think of TransCanada’s future in Alberta power, are you considering active measures to increase your Alberta presence in the next decade or increase beyond the PPAs?

[Russ Girling:]

Well, I think what I can tell Steven is Alberta is a core market for us. We do have a pretty significant generation position that we have built outside of the PPAs, so that will be core and (indiscernible). And I would say that we see the reduction in the coal fleet as an opportunity to add new generation to this marketplace going forward. We have a lot of experience in both the market itself from a commercial perspective as well from a technical perspective and a construction perspective. So we think we are well-positioned to compete as the market transitions from what is primarily a coal-fired fleet today to whatever that’s going to look like in the future and we suspect that there is going to be a fair bit of gas added to that portfolio. So, we continue to look for opportunities to do that, but under the right structures and at the right time, those kinds of things will make sense to us. So, it’s our strategic intent to continue to be a long-term player in the Alberta business.

[Steven Paget:]

Well, thank you, Russ. If I could follow-up, would that Alberta market need to have capacity pricing or would you build into the merchant market as it now is?

[Russ Girling:]

Well, I think that those are all dependent upon how things unfold over the coming years. So, certainly we have built some capacity in this merchant market, but it’s been limited. If the marketplace gives us the right signals, we go down that path, but I think that there is the question looms as to what will the market structure be in order to make that transition from the sort of the coal-fired base load that exists today to whatever that future is going to look like? And I think that’s an element of government policy that is yet to be written, but what I can tell you is that we have participated in both structured markets, and what I call sort of open markets who are in New York, New England, Québec, Ontario, Alberta and various other markets in Pacific Northwest and the like. So, I understand all the different structures. All of them have their pros and cons and we will look at those structures and determine how best to invest under those structures.

[Steven Paget:]

Thank you, Russ and Karl. Those are my questions.

[Russ Girling:]

Thanks, Steven.

[Operator:]

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

[Ted Durbin:]

Thank you. The first question here is just coming back to B.C. LNG and thoughts around whether it’s Prince Rupert or Kitimat move into FID here, particularly given the lower oil price environment we did see one of the other Prince Rupert developers it looks like they pushed other development timeframe. I wonder if you could just talk about that?

[Alex Pourbaix:]

Sure. It’s Alex. I think if you look at the two projects were involved in the Petronas project in Prince Rupert and the Shell consortium in Kitimat. Petronas is I think they are very focused on moving to an FID in the relatively near future. Certainly, we are going to have done our work to allow them to be in a position to make an FID decision around the end of the year and I expect that decision will be made either around there or shortly thereafter. And obviously, we believe that we are going to have all the permits in place then or about then for that project to go ahead. I would say the same thing with our Coastal GasLink project. With Shell, it’s probably following about give or take, about a year behind, but once again we think we will be in position for them to make those decisions. I think in terms of the competitiveness of the project, I think both of those counterparties benefit from being at the front-end of this process and being among if not the most advanced projects and certainly from our perspective, they look to be – they still look to be very commercially viable.

[Ted Durbin:]

Okay, great. Second one just on Energy East now that you have the filing in there, can you just walk us through the timeframes that we should be thinking about in terms of the milestones that you expect to hit from a regulatory perspective?

[Alex Pourbaix:]

Sure. Here is kind of the simple way to think about it. We are – now that we have filed, the regulator, the NEB now has to come back with a determination that the filing is complete. There is no legislative timeframe for that, but probably historically it’s been anything from 2 to 5 months. Then once they determine that the filing is complete, they are mandated by legislation that they have to make a decision within 15 months, then it goes to the cabinet, the federal cabinet, and they have a short period in which to make a decision. So, we are – right now, we are probably thinking sometime around mid-2016 as to get through the entirety of the regulatory process.

[Ted Durbin:]

Very helpful. Thank you. And then if I can get one more in the just thinking about you have really highlighted in your language recently you are evaluating your approach to capital allocation, I wonder if you could spend on that. You have sort of talked about it, Don, but especially as we look at the dividend here is moving to year end is usually when you consider it, I am just trying if you can balance your dividend growth versus potential equity needs and financing needs given the large capital program?

[Don Marchand:]

Yes. The dividends generally looked at by the board in the February timeframe. We wouldn’t constrain dividend growth to backfill equity for the capital program. Our thought process going into this cycle of dividend consideration would be looking at some of the advances we have made and some of core assets here I think the mainline is in pretty good shape here. A&R is fully contracted. We got the Gulf Coast completed to Texas. That will form part of our thinking. And as we announced another $4.7 billion of near-term projects today, I think that gives us greater visibility on the near to mid-term growth outlook for earnings. So, those are the elements that we are looking at right now, but don’t look for us to constrain dividend growth just to hold back equity for the capital program.

[Ted Durbin:]

Great. I will leave it at that. Thank you.

[Russ Girling:]

Thanks Ted.

[Operator:]

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

[Faisal Khan:]

Thanks. Good morning. I wonder if you could just elaborate a little bit more on the – you talked about the conveyor belt of MLP dropdowns into TC PipeLines, what’s the pace of that conveyor belt, is it Bison sort of dropdown every quarter or how are you looking at that?

[Don Marchand:]

Yes, it’s Don here. We don’t have any specific timeframe on that. What we have indicated is and part of our thought process here is what’s the use of proceeds keeping the conveyor belt running for visibility and then putting these assets into the LP, and thirdly capacity limits at the LP as well. So again, we are trying to extract cash for our capital program from this strategy here. As the LP gets bigger and bigger, it’s about $5 billion enterprise right now, which we are looking at probably putting $5 billion of assets into there. So, we have to bear capacity limits in mind if we are going to extract cash from that. So, probably look for a couple of transactions a year of size here, that’s not hard and fast in terms of a rule to be more to be less, but it will be somewhat driven by our needs for the capital program.

[Faisal Khan:]

Okay, that makes sense. And then just you talked about sort of other sources of sort of equity capital as you move – as you potentially move forward with your lumpier projects. I was wondering one of the things that I didn’t hear that you could dropdown the existing Keystone oil pipeline into the MLP, so I was wondering is that completely off the table or is that also sort of a potential source of capital if you move forward with these sort of large larger or lumpier projects in the next few years?

[Don Marchand:]

Yes, I was remiss in not including that. Based on probably $750 million of U.S. based EBITDA on the base Keystone system and a multiple on that of 11, 12, 13 times, you are probably looking at something of $8 billion to $10 billion that we could extract in terms of cash to fund the capital program. That is still something that we would consider.

[Faisal Khan:]

Okay, understood. And then just on the Mainline, the Eastern Triangle expansions of roughly $475 million of expansion, what are the contract terms on those – on that short-haul capacity as it is rolled into the Eastern triangle rates?

[Karl Johannson:]

Yes, it’s Karl here. This is in response to LDC settlement and two open seasons that we have held and the contract terms on both of those open seasons were 15 years.

[Faisal Khan:]

Okay, great. Understood. And then also on the NGTL expansions the $2.7 billion you announced, what are the duration on those contracts and how do those work into the rates still?

[Karl Johannson:]

Those contracts are generally between 8 and 10 years.

[Faisal Khan:]

Okay, understood.

[Russ Girling:]

I would also highlight, Faisal, it does also fall under if you will be Canadian cost of service approach if you will. So, I think Karl has highlighted for you the contract terms associated with it, but the expectation would be that the capital would form part of right base and a return of a non-capital would be captured over time obviously.

[Faisal Khan:]

So, that’s a 10% ROE?

[Russ Girling:]

That’s currently 10.1% on 40% equity.

[Faisal Khan:]

Got it, okay, great, thanks for the time, I appreciate it.

[Operator:]

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

[Robert Kwan:]

Great, thanks. Just I want to ask a quick follow-up on the Ravenswood outage. The insurance proceeds at least your expectation of what you are going to get back. Is that going to cover as well the lost revenue associated with the reduction in UCAP on the rolling basis over the next or as we go forward here?

[Bill Taylor:]

Yes, Robert. It’s going Bill here, the insurance coverage that we have in place for Ravenswood includes both physical damage and a business interruption element. So our answer would be yes subject to as Don mentioned the deductables that would apply there.

[Robert Kwan:]

Right, but to be clear is it lost, but it’s a combination of both the lost revenue while the unit is completely out and then it will also include the rollback in on the UCAP?

[Russ Girling:]

Yes, that’s right, that the business interruption element of it. It does cover that loss revenue, yes.

[Robert Kwan:]

Perfect. Thank you.

[Operator:]

Thank you. We will now take questions from the media. (Operator Instructions) And the first question is from Nia Williams from Reuters. Please go ahead.

[Nia Williams:]

Hi there. Thanks for taking my question. I just wanted to ask looking at the U.S. it looks like the Republicans are going to make some major gains and possibly even recapture the Senate do you think that will help with cause in any way?

[Russ Girling:]

I don’t know, I mean it’s we have since 2008 the Keystone project has enjoyed the support of the majority of the Americans we continuously pull in just 25 poles that we have tracked. Since that point in time and the number appears to be two-thirds on a continuous basis. From a conventional perspective I think that we enjoyed majority of supporting both the house and the Senate. The project is in the international interest, so I guess what we would hope is that a decision gets made somehow or another as quickly as possible, and we can get on with construction and providing job opportunities for thousands of Americans that wanted to go to work. So I can't really sort of predict what the outcome of this particular election might have on Keystone. I guess maybe just suffice to say that we are supportive of any process that can help advance decision on the project given that the environmental review is completed and at this point in time we are just waiting for someone to say go.

[Nia Williams:]

Okay, thanks.

[Operator:]

Thank you. The next question is from Chester Dawson from the Wall Street Journal. Please go ahead.

[Chester Dawson:]

On my question in – just got a quick question in regard to the pipelines to the West Coast for the potential LNG projects, which you addressed earlier, what I’m interested in knowing is I’m wondering how close are you to finalizing the route particularly for the Prince Rupert project which will be used for the Petroas facility especially if they're that close to making decision, how close are you to finalizing your route. And how many first nations do you still need to deal with in order to finalize that.

[Russ Girling:]

So we have a proposed route that has been filed with the provincial regulator. I mean we are – I would say we’re in the process now, where we are considering relatively modest route changes in response to requests of our stakeholders including aboriginal groups. I think we have on the PRTT right-of-way we are presently negotiating with give or take around 19 or 20 first nations. And I would describe those negotiations are going well. I think we have a productive dialogue with them. We certainly have a great deal of respect for their position. And I am personally pretty confident that over the next few months we’re going to reach agreement with the vast majority of those groups. Just maybe to be clear on what we are hoping to get on the PGRT route is there are main assessments that we have asked for. One is BC Environmental Assessment Office and we would expect them to issue environmental assessment certificate probably sometime we are hoping towards the end of this year or early next year. And the second one is permits from the BC Oil and Gas Commission. And again we expect regulatory process to conclude around that same time in Q1. So we are trying to be in a position where we will have all of our approvals or regulatory approvals, our key regulatory approvals for Petronas to make their final investment decision.

[Chester Dawson:]

Okay, great. Thank you.

[Operator:]

Thank you. The next question is from (indiscernible) from Bloomberg. Please go ahead.

[Unidentified Analyst:]

Hi there. Good afternoon. My question is basically with regards to your Energy East project, we have seen that you recently there had been some Canadian crude exports from Montreal and with that in mind and since you have noted that you have some 20-year contracts in place in support of Energy East. I was wondering you can shed some color maybe detail about whether you are in any talks to supply crude to foreign buyers through the Energy East project like any kind of term contract you might have in place or maybe in discussions and if not, if you can’t really talk about all those companies maybe you can tell us what those destinations are for those supplies via the Energy East project? Thank you.

[Paul Miller:]

Hi, Sheila, it’s Paul Miller here. We provide the transportation service for our shippers and our shippers include producers and refiners. So our obligation is to accept their crude at various receipt points and deliver it to the delivery points which include Montréal, Cacouna and St. John. From that point it’s up to the shippers to determine the use and the further movement of that crude oil. So we are not in any discussions with any foreign purchasers of crude oil. And frankly we are not in any discussion with any domestic purchasers of crude oil. We leave that to the producers.

[Unidentified Analyst:]

Okay. Thank you.

[Paul Miller:]

Thank you.

[Operator:]

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

[Blake Clayton:]

Hi, thank you. Just a quick question from us, this is Blake Clayton of Citi. Our question is regarding what have been kind of the incremental costs associated with XL getting up to that $8 billion figure, if you could provide some color around what additional costs have come into play there?

[Alex Pourbaix:]

Sure, it’s Alex the, I would say that that difference my recollection was that previous number that we had sort of talked about and it held stable for many years was $5.3 billion, give or take. And as we said sort of at the time two or three years ago, we are going to hold off on updating – we just didn’t see the value in updating it quarter-to-quarter. We think now it probably is worthwhile to give some color on that hence we came out with $8 billion. Just to give you an idea I would say that the difference between those numbers is really overwhelmingly the presidential permit delays. And if you kind of break it down we go into this process, we have probably anticipated somewhere in the region of about a two-year regulatory process in line with what we saw for our base Keystone project. We are now in a six to seven year process. So you can imagine the costs that are associated with that, with that regulatory process. On top of that there is also just frankly at the time we proposed this project, it was a pretty good market for constructing pipeline projects, it’s a lot tighter market now in North America and we had six or seven years of inflation. So you kind of add those two together and you get the lion share of the difference between the $5.3 billion and the $8.0 billion. Just one other comment I would say on that the losers in this whole process ultimately are consumers of energy in North America because that’s who ultimately bear the cost for these kind of delays and the cost impacts.

[Blake Clayton:]

Thanks. That’s all for us. I appreciate it.

[Alex Pourbaix:]

No problem. Thanks.

[Operator:]

Thank you. The next question is from Elsie Ross from Daily Oil Bulletin. Please go ahead.

[Elsie Ross:]

Hi. Just the first question about the proposed Merrick Mainline, you are saying it’s going to be delayed into the first quarter of 2016, the application to the NEP, what’s – is there any special reason to that?

[Don Marchand:]

No. There is no particular reason for that. We are just right now doing our field work and prepping the application and that’s really the reason for revised data. This is the project that the Merrick project is the project that Apache and Chevron are sponsoring and there has been some questions over the status of that, but I could tell you that there was a word we are getting from our – from the project proponents is full steam ahead. So, the delay has nothing to do with the ownership issues or potential for Apache to leave the partnership. It’s more of just from a process perspective on the application.

[Elsie Ross:]

Okay, thank you.

[Operator:]

Thank you. The next question is from Geoff Morgan from the Financial Post. Please go ahead.

[Geoff Morgan:]

Hey, good morning. Thank you for taking my question. My question is with regards to your announcement this morning of the Canadian Mainline system and development of natural gas infrastructure for collaboration between Gaz Metro and Union Gas, how has this announcement, I guess improved relations with those two companies in light of the fact that they are looking for cheaper gas for their customers?

[Karl Johannson:]

Well, it’s Karl. I guess what I can say is the facilities we are putting in place really are a result of the collaboration that we had with all the Eastern Canadian LDCs. Couple of years ago, when we did the original LDC settlement, we have been to the Board now and the Board has adjudicated this and we are awaiting for decision, which should come before the end of the year. So, the LDC settlement as you may recall from previous discussions, it was a settlement design that we open up more capacity in our Eastern Triangle for Marcellus and Utica and other sources of natural gas into the system. And in conjunction with that, the LDC is a great concern for visions like the no bypass provision for 15 years and to pay the full cost of service of that system. So, from that perspective, their relationship with the LDCs on that particular settlement and adjudication was very, very good. As you can see right now in the newspaper, we may have some different opinions on the energies with them, but certainly with our construction to fulfill our obligations to bring in more diversity supply in the Eastern Triangle is going pretty good with our LDC partners.

[Geoff Morgan:]

Thank you.

[Operator:]

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

[David Moneta:]

Okay, thanks very much and thanks to all of you for participating today. We very much appreciate your interest in TransCanada and we look forward to talking to you again soon. Bye for now.

[Operator:]

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