TC Energy Corp (TRP) 2016 Q1 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2016 first-quarter results conference call. I would now like to turn the meeting over to Mr. David Moneta, Vice President Investor Relations. Please go ahead, Mr. Moneta.

Thanks very much and good afternoon, everyone. I would like to welcome you to TransCanada's 2016 first-quarter conference call. With me today are: Russ Girling, our President and Chief Executive Officer; Don Marchand, Executive Vice President of Corporate Development and Chief Financial Officer; Alex Pourbaix, Chief Operating Officer; Karl Johannson, President of our Natural Gas Pipelines Business; Paul Miller, President of Liquids Pipelines; Bill Taylor, President of Energy; and Glen Menuz, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other Company developments.

Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at 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 questions from the investment community. If you are member of the media please contact Mark Cooper or James Miller following this call and they would be happy to deal with your questions. 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 detailed financial models, Stuart and I would be pleased to discuss them with you following the call.

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

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; funds generated from operations; and distributable cash flow. 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. They are used to provide you with additional information on our operating performance, liquidity and our ability to generate funds to finance our operations.

Finally, this presentation may be deemed to be solicitation material in respect to the proposed acquisition of Columbia Pipeline Group by TransCanada. Therefore, pursuant to US securities law it will be filed on Columbia's EDGAR profile and TransCanada's EDGAR and SEDAR profiles.

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

Thank you, David. And good afternoon, everyone, and thank you for joining us late on Friday afternoon. As I mentioned earlier in my speech to shareholders today, 2015 has been a very challenging one for the energy industry. In the midst of those challenges TransCanada's energy infrastructure assets continued to perform well, allowing the Company to deliver record comparable earnings and funds generated from operations in 2015.

Our $64 billion North American energy infrastructure asset base are largely underpinned by cost of service, regulated models or long-term contracts that has provided our shareholders with cash [eligibility] throughout this energy market downturn. On March 17 we announced the $13 billion acquisition of Columbia Pipeline Group. This development represents a transformational change for the Company and creates an industry leading pro forma $24 billion portfolio of near-term growth projects that will support and may augment our expected 8% to 10% annual dividend growth through 2020. In addition, our suite of $45 billion in medium to longer term projects has the potential to further transform this Company as we move into the future.

Focusing on the first quarter, comparable earnings were up 6% over Q1 to $494 million or $0.70 per share. Despite the weakness in power prices, comparable EBITDA was $1.5 million, and funds generated from operations were $1.1 billion, similar to the first quarter of last year.

Today our Board of Directors declared a quarterly dividend of $0.565 per common share for the quarter ending June 30, 2016. This equates to $2.26 per share on an annualized basis.

Before I turn the call over to Don to give you more details on our financial results. I would like to provide you with a brief update on progress on some of our major projects. Starting with the Columbia transaction, the largest acquisition TransCanada has done. On March 17, as I said, we entered into an agreement and a plan of merger to acquire Columbia Pipeline Group.

Columbia owns one of the largest interstate natural gas pipeline systems in the United States, providing transportation, storage and related services to a variety of customers in the US Northeast, Midwest, Mid-Atlantic and Gulf Coast regions. Its assets include Columbia Gas Transmission, which operates 18,000 kilometers of pipeline and 286 billion cubic feet a day of storage capacity in the Marcellus and Utica, and Columbia Gulf Transmission which is a 5,400 kilometer system that expands from the Appalachia to the Gulf Coast. The acquisition provides us the opportunity to invest in an extensive and competitively positioned growing network of regulated natural gas pipelines and storage assets in the Marcellus and Utica, which is the fastest-growing production basins in North America.

In addition, Columbia's currently advancing $7.3 billion of commercially secured projects and modernization investments that are largely expected to be in service by 2018. This is an all-cash transaction where Columbia shareholders will receive $25.50 per share, representing an aggregate transaction value of approximately $13.0 billion, including the assumption of approximately $2.8 billion of debt.

Columbia's proxy statement for a special meeting of shareholders to approve the acquisition was filed with the SEC on April 8. A special meeting of Columbia shareholders is scheduled for June 22, 2016 to vote on the transaction. On April 4 notifications were filed with the US Federal Trade Commission, and we have also submitted filings with the Committee on Foreign Investment in the United States.

We continue to expect the acquisition to close in the second half of 2016 subject to shareholder and regulatory approvals. Consistent with our strategy the addition of Columbia Gas Transmission's network to our portfolio will improve the stability and predictability of our earnings and cash flow with 92% of our 2015 adjusted pro forma EBITDA coming from regulated long-term contracted assets.

Looking forward the monetization of our US Northeast power business will result in virtually all of our EBITDA being underpinned by cost of service regulated business models or long-term contracts. We expect this acquisition would be accretive in the first full year of operation to earnings. Later Don will provide you a little more detail on how this acquisition will be financed.

Continuing on the gas front, we had a bit more good news during the quarter. Recently, on April 11, we were awarded the contract to build, own and operate the Tula-Villa de Reyes pipeline in Mexico. This project complements our existing network in Mexico and advances our strategy of owning and operating highly contracted regulated assets that generate stable predictable earnings and cash flow in that region. The $550 million pipeline is underpinned by a 25-year transportation service contract with Mexico's state-owned power company, CFE, and we expect it to be operational in early 2018.

Progress continues in Mexico on the other natural gas pipeline projects that we have. In November we were awarded the contract to build, own and operate the $500 million Tula-Tuxpan natural gas pipeline, which is also underpinned by a 25-year contract with the CFE. Construction is expected to begin in 2016, and that pipeline should be operational in the fourth quarter of 2017.

The $1 billion Topolobampo project in the $400 million Mazatlan natural gas pipeline are in the final stages of construction and are expected to be operational in 2016. With the addition of the Tula-Villa de Reyes pipeline, our investment in Mexico now sits at about $3.5 billion.

On our NGTL system, in the first quarter this year $100 million of new facilities became operational, and $600 million more are currently under construction. The NGTL system continues to develop. $7.3 billion of new supply and demand facilities, currently $2.5 billion of those facilities have received regulatory approval and a further $1.9 billion are currently being reviewed by the regulator. And we continue to work on applications for the approval to build and operate the additional $2.9 billion in facilities.

Earlier this month we filed a request with the National Energy Board for a one-year extension of the certificate of public convenience and necessity for the North Montney Mainline project. The request ensures our regulatory approvals remain valid and do not expire before the Final Investment Decision for the Pacific Northwest LNG project.

With $7.3 billion, or about CAD9.6 million of projects from the Columbia Pipeline Group underway, our portfolio of near-term projects will increase to about $24 billion. As you can see, these projects are in all three of our business lines: natural gas, liquids, and energy, and span all three of our core geographies: Canada, the United States and Mexico. In addition, potentially all of the projects are underpinned by regulated business models and/or long-term contracts.

In addition to our short-term projects we continue to advance our $45 billion portfolio of the larger scale, longer term projects, starting with the PGRT project, Prince Rupert Gas Transmission project, where we signed two further project agreements with BC First Nations during the quarter, bringing the total number of agreements signed to 11. We remain on target to begin construction of the Prince Ruper project following the confirmation of a Final Investment Decision from the Pacific Northwest LNG.

On the Coastal GasLink project, the LNG Canada joint venture participants anticipate reaching Final Investment Decision on the [titamet] base LNG project in late 2016. We continue to advance the Energy East project through the regulatory process with the NEB announcing its schedule this week. Lastly, we continue to work to submit estimates for the first of six reactor refurbishments of Bruce Power.

Looking forward, our priorities remain straightforward. First of all, we will operate our existing assets safely, maximizing the utilization and continuing to deliver stable and growing cash flows. Second, we will close the $13 billion Columbia Pipeline Group acquisition and complete our asset sales. Third, we will bring a pro forma combined $24 billion of near-term projects through the approval process, construction and into operation. Fourth, we will advance our $45 billion portfolio of long-term projects. And, fifth, and as, always we will continue to finance our business in a way that maximizes our financial strength and flexibility to fund our growth program and to pay a stable and growing dividend.

I'm very confident execution of these priorities will continue to grow shareholder value for many years to come.

With that I'll pass it over to Don to fill you in on some more details of our financial performance. Don?

Thanks, Russ. And good Friday afternoon to everyone. As highlighted earlier, we reported net income attributable to common shares in the first quarter of $252 million or $0.36 per share, which compares to net income in the same quarter of 2015 of $387 million or $0.55 per share.

The year-over-year decrease stems primarily from: net after-tax charges of $211 million for a number of specific items in first-quarter 2016, including a $176 million relating to the remaining net book value associated with our investment in the Alberta PPAs as a result of our termination decision; $26 million relating to costs associated with the Columbia acquisition and other smaller items. Both periods were also affected by certain risk management activities.

Excluding these items, comparable earnings for first-quarter 2016 increased 6% to $494 million or $0.70 per share compared to $465 million or $0.66 per share for the same period last year. A higher contribution from Bruce Power and improved net corporate financial results were partially offset by lower earnings in the Keystone System, Eastern Power, US Power and Western Power.

In terms of our business segment results at the EBITDA level, in the first quarter, comparable EBITDA was slightly lower than the same period last year. Our natural gas pipelines business generated comparable EBITDA of $898 million in first-quarter 2016 compared to $864 million the year earlier. Canadian Gas Pipeline's comparable EBITDA of $507 million was largely in line with 2015.

For the quarter, net income from the Canadian Mainline increased by $3 million, primarily due to higher incentive earnings, partially offset by a lower average investment base in 2016. No incentive earnings were recorded in the first quarter of 2015. The NEB approval of compliance tools related to the LDC settlement was not received until June 2015.

The NGTL systems quarterly net income increased $9 million year over year to $73 million, mainly due to a higher average investment base. When measured in US dollars, comparable EBITDA for US and the international pipelines was consistent for the three months ended March 31, 2016 compared to the same period in 2015. This was the net effect of: higher ANR's Southeast Mainline transportation revenues, offset by a first-quarter 2015 nonrecurring customer settlement; lower contributions from Mexico pipelines; and higher transportation revenues from Great Lakes. In Canadian dollar terms, the stronger US dollar in first-quarter 2016 had a positive impact on the Canadian dollar equivalent comparable earnings from our US and international operations.

In liquids, the Keystone pipeline system generated $307 million of comparable EBITDA in the first quarter, a $4 million decline from the same period in 2015. The decrease was the net affect of lower contracted volumes on the Keystone pipeline system and lower volumes on MarketLink, partially offset by the positive impact of the stronger US dollar.

Turning to energy, comparable EBITDA of $329 million in the first quarter declined $57 million in the same quarter last year due to the net effect of the largely flat results in the Canadian power segment due to lower contribution from the sale of unused natural gas transportation, and less contractual earnings at [bekken-core], as well as reduced earnings from Western Power resulting from lower realized power prices, and PPA volumes following the termination of the PPAs. This was largely offset by higher earnings from Bruce Power stemming mainly from greater levels of contracting activities, lower depreciation, and our increased ownership interest, partially offset by higher planned outage days.

There were lower earnings from US Power, mainly due to: decreased margins on sales to wholesale, commercial and industrial customers; the impact of lower realized prices in both New England and New York; and lower capacity prices in New York. This was partially offset by incremental earnings from the Ironwood power plant in Lebanon, Pennsylvania that we acquired on February 1. Lastly, the higher earnings from natural gas storage as a result of better realized natural gas storage price spreads than in 2015.

Now turning to the other income statement items on slide 16, comparable interest expense of $420 million in the first quarter increased by $102 million compared to the same period last year. This was primarily due to long-term debt issuances in 2015 and first-quarter 2016, partially offset by Canadian and US dollar denominated debt maturities, a stronger US dollar and its effect on interest expense on US dollar-denominated debt, and lower capitalized interest on Keystone XL and related projects following the November 6, 2015 denial of a US presidential permit, partially offset by higher capitalized interest on LNG pipeline projects and the Napanee power-generating facility.

Comparable interest income and other increased by $133 million for the three months ended March 31, 2016 compared to the same period in 2015, as a result of realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate, fluctuations on US dollar-denominated income, and increased AFUDC related to our rate-regulated projects, including Mexico pipelines, NGTL system expansions and Energy East.

Comparable income tax expense for the first quarter decreased by $67 million compared to the same period in 2015, mainly as a result of lower pretax earnings in 2016, changes from the proportion of income earned between Canadian and foreign jurisdictions, and by lower flow-through taxes in 2016 on Canadian-regulated pipelines. Net income attributable to noncontrolling interests increased by $21 million for the three months ended March 31, 2016 compared to the same period in 2015, primarily due to the sale of two TC PipeLines LP of our remaining 30% direct interest in GTN in April 2015, and a 49.9% direct interest in PNGTS on January 1, 2016, as well as the impact of a stronger US dollar on the Canadian dollar-equivalent earnings from TC PipeLines LP. Preferred share dividends were $22 million for the three months ended March 31, 2016, similar to 2015 levels.

Now moving on to cash flow and investing activities on slide 17, cash flow remains solid with funds generated from operations of approximately $1.1 billion in the quarter, consistent with 2015. For the first quarter, comparable distributable cash flow was up modestly to $970 million or $1.38 per common share, which represents an increase from $1.35 per common share in the first quarter of 2015.

Maintenance capital expenditures on our Canadian-regulated natural gas pipelines were $55 million and $52 million in first-quarter 2016 and 2015, respectively, which contributed to their respective rate bases of net income. Capital spending totaled $903 million in the first quarter, driven principally by expansions of the NGTL Canadian Mainline and ANR systems and construction activities on Mexico Pipeline's Northern Courier and Napanee.

Equity investments of $170 million in the quarter related to our share of spending at Bruce Power in Grand Rapids. Acquisitions of approximately $1 billion reflect the purchase of Ironwood on February 1, 2016 for $657 million, as well as an additional interest in Iroquois Gas Transmission for $54 million. Our ownership in Iroquois is now 49.35%.

Now turning to slide 19, our liquidity and access to capital markets remains strong. At March 31, our consolidated capital structure consisted of 30% common equity, 5% preferred shares, 4% junior subordinated notes, and 61% debt net of cash. At quarter end we had $1.2 billion of cash on hand.

On April 20, 2016 we completed a public offering of 20 million preferred shares at a price of $25 per share, resulting in gross proceeds of $500 million. The initial fixed-dividend rate for these preferred shares is 5.5% per annum, and will reset every five years to a rate equal to the sum of the applicable five-year government of Canada bond yield plus 4.69%, provided that such rate shall not be less than 5.5% per annum.

We remain well-positioned to finance our industry-leading pro forma $24 billion capital program, with multiple attractive funding options available, including predictable and growing internally generate cash flow, senior debt, preferred shares, hybrid securities, portfolio management, and equity through our dividend reinvestment program. As well, we will continue to evaluate LP dropdowns against alternate sources of subordinated capital.

At this point we remain focused on completing the acquisition of Columbia Pipeline Group and, as such, we have not formed any firm views on the specific roles of TC PipeLines LP and the Columbia Pipeline Partners LP going forward. We will turn our attention to this post completion of the transaction.

The $13 billion Columbia acquisition includes approximately $2.8 billion of assumed debt. The remaining $10.2 billion cash to close is expected to be funded through the subscription receipts offering completed on April 1, as well as through the planned monetization of our US Northeast power assets, and a minority interest in our Mexican natural gas pipeline business. In the interim, a syndicate of lenders has committed to provide debt-bridge financing in the amount of $6.9 billion.

In total, including the full exercise of the underwriters over-allotment option, we issued 96.6 million subscription receipts at $45.75 per receipt, for gross proceeds of approximately $4.4 billion. Each subscription receipt will automatically convert to one common share upon closing of the Columbia acquisition. While those subscription receipts remain outstanding, holders will be entitled to receive cash payments per subscription receipt equivalent to dividends paid on each TransCanada common share. As indicated previously, we expect the acquisition, net of financing and the planned asset monetization, to be accretive to earnings per share in our first full year of ownership.

In closing, during the first quarter of 2016 our diverse portfolio of high-quality long-life assets generated steady results in what continues to be a challenging environment. Comparable earnings increased by 6%, while funds generated from operations of $1.1 billion were consistent with the same period last year. We remain well-positioned to finance both the Columbia acquisition as well as our combined pro forma $24 billion portfolio of near-term growth projects supported by our growing internally generated cash flow and access to capital consistent with our enduring financial strength.

We are extremely pleased with investor support for the issuance of $4.4 billion in subscription receipts that closed on April 1, which represented the largest equity offering in Canadian history. This equity, in addition to the planned monetization of our US Northeast power assets and minority interest in our Mexico gas pipeline business are expected to provide the permanent financing for the Columbia transaction.

Our industry-leading suite of critical energy infrastructure projects is expected to generate significant growth in earnings and cash flow for our shareholders. The Columbia acquisition supports and may augment our expected 8% to 10% annual dividend growth through 2020.

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 the call back over to the conference coordinator for questions from the investment community, we ask that you limit yourself to two questions. If you have additional questions please reenter the queue.

With that. I will turn it to the conference coordinator.

(Operator Instructions)

Linda Ezergailis, TD Securities.

Thank you.

I'm wondering how much the first-quarter results benefited from your cost savings initiative. Is it reasonable to assume that it was approximately a quarter of your CAD50 million, or is there a ramp in the year?

Linda, it's Glenn. Yes, I think that's a fair estimate. We're still on track for what we expect.

That's great. And just as a follow-up, with respect to the new carbon tax in Ontario, I understand, based on precedents, that you expect contracts to be amended to preserve the economic value of your assets there. But I'm just wondering, in the unlikely event that the government of Ontario doesn't amend it, can you give us a sense of materiality, if any, of what that might entail?

Sure. Linda. It's Bill. To your question, the discussions have only just begun on that question with the Ontario independent system operator. As you said, precedent would suggest that there will be some amendments.

The nature of how the tax would flow through to our various contracts is actually unique by contract because there is slightly different wording in various contracts. So, that's a matter that the impact will depend on the outcome of those discussions. So, it's hard to say. But we also don't expect it to be material given just the general nature way those contracts work.

Thank you.

Paul Lechem, CIBC.

Thank you, good afternoon.

I realize it hasn't been long since you announced the Columbia acquisition, but I was wondering if you can give us some sense of the level of interest for the assets packages that you're selling, and any timing from here on in in terms of when you expect indicative pricing, and how you expect the two processes to unfold.

Hi, Paul, it's Don here.

The processes are underway. We have advisors retained, data rooms are being populated, CIMs are being prepared. We're about to move through a traditional two-stage auction process here. The Northeast power process is probably running a couple weeks ahead of the Mexican one.

Interest to date has been substantial from strategics and financials for both asset packages, from indications of interest at this point. We will move through that process, and probably tracking to something in third quarter, mid to late third quarter at this stage in terms of hopefully getting through that process. Closing would then be probably several months to maybe a couple quarters after that.

And in terms of the New England power assets, do you anticipate selling those as a portfolio? Do you see them selling them separately? How do you think that's going to unfold?

They're being marketed as a portfolio. We will see what interest levels are for specific assets, but they are currently being marketed as portfolio.

Thank you very much.

Robert Kwan, RBC Capital Markets.

Thank you.

If I can just maybe follow up on asset sale process, you've got what I'm assuming, Don, you were referring to non-binding indications of interest. I'm just wondering, based on what you've received to date, does that have you on track to the asset sale proceeds?

And then specifically around the US Power side you've moderated the outlook. Does that change how you're thinking about that or did you have that outlook when you set the target of asset sale proceeds when you announced Columbia?

It's pretty early days, Robert, on where we're going to land. We remain of the view that the CAD7 billion area is certainly achievable. We recognize the weakness in the Northeast power business due to warmer winter weather right now. But the buyer universe will focus on the long-term fundamentals and the positioning of those assets. So, no change in our outlook.

Okay.

If I can just turn to pipeline development, and specifically as it relates to Columbia, oil pipeline permitting has obviously been challenging as you live through the thick of that. That being said, I'm just wondering how you're viewing what happened on Constitution, or just with Columbia in the somewhat vicinity, do you see that as being a New York thing or a Constitution thing? Just your thoughts as you think about the Columbia business and their growth projects.

Robert, it's Karl. We have a number of pipeline projects, none in New York, that we will be proceeding with permits. Many are in the pre-filing stage right now. Many of them have actually been filed.

We don't see the same issues that maybe Constitution had with their filing in New York. First of all, most of the projects that Columbia has in their portfolio are projects that are pretty close to their existing right-of-ways.

They're all brownfield. Most of them are compression. There's very little new pipe. Of the US7 billion of their construction, there's only like 200 miles of new pipe included. So, most of them are brownfield in their existing right-of-ways.

They're in jurisdictions -- they're in Ohio, they're in West Virginia, they're on the Columbia Gulf, going down the Gulf coast -- most of them are in jurisdictions that are actually very positive towards pipeline development in support of the benefits pipeline development ring. As of right now we view the Constitution issues to not be reflective of what we're working in. But having said that, we do appreciate that Columbia has a good team on the ground. And their presence in the communities and whatnot, they're still working really hard to make sure that there are no problems with the permitting.

That's great. Thanks, Karl, thanks Don.

Andrew Kuske, Credit Suisse.

Thank you, good afternoon.

The question is for Russ, and others might want to chime in as I ask this. Clearly you've got the schedule for Energy East that's been put forth. It seems like there's a much more constructive tone coming from Prime Minister Trudeau than, say, prior to the election.

So, how do you think about the developments of Energy East and then just the LNG pipes to the West Coast, and really anything else from Canada at this state as a pipeline? And then, really, just for the broader energy industry ramification, how do you think of that at this stage? Are you more positive, less positive than you may have been previously?

I think with respect to process we're feeling like we're headed in the right direction. You look at the West Coast LNG projects we're pretty close to the end of those. One of the worries is always how long these processes take and having to wait them through business cycles. And we've seen the impact of that before.

I would say that we are still cautiously optimistic that we will be able to get these things through the regulatory processes. It appears that on all fronts, whether they be the West Coast LNG projects or things like Energy East, I think there is a greater understanding of the impact that the developments of those can have on the economy and economic development, job creation, and that they're fundamental to the long-term prosperity of our country.

They have to be done in a safe manner. I think we all agree on that, as well. But it appears that there is some harmony around the importance of getting these things done in a timely way. Market is always an issue, but I would say from a tone perspective we're feeling fairly positive on things here currently in aggregate with all of our projects.

Okay, that's helpful. And then if I may ask a follow-up, and it's probably more directed at Karl, as it relates to just the Mainline. If we think of the Mainline as an asset, you've got a rate base right now of about CAD4.4 billion. If we went back 15 years or so ago it was about CAD10 billion.

I appreciate this pretty significantly. If Energy East goes ahead, a chunk of that is coming off. So, how do you think of just the relative competitiveness of the Mainline versus other proposed options to east to Ontario and Quebec?

It's a good question. When our LDC settlement comes into full force and effect, which is 2020, the Mainline will actually be two different utilities -- the Eastern triangle, which I think is going to be very difficult for somebody to duplicate or get around.

The Eastern triangle, which will have the majority of the capital from what we know as the Mainline today, is, I think, a pretty solid utility. I think it's tough for people to get around and I think that it will be around for years and highly used.

The Western system will have only about CAD1 billion in capital left after 2020. And that system still has about CAD800 million a day of captive load on it, load that as considered can't go elsewhere. So, it's still got a pretty decent load on it.

Pricing-wise for that particular part of the Mainline, I think we're going to have lots of flexibility. We are expecting to be somewhat more lightly regulated on what we call the Western system. We should have some flexibility to make lines move as we see fit.

I think that Mainline will remain competitive. I think people have to understand that there is a merit order of which pipelines go where and what their costs are. When you take a look at the cheapest ways out of the WCSB right now, going down into Chicago, going into GTN down in California, and whatnot, I don't think the Mainline will ever beat out the CAD0.35 GTN has from down into California border.

I do think it probably will still remain to be a more expensive alternative than, say, Chicago or California. But I think that as time goes on we're going to see more flexibility, we're going to have more tools at our disposal for the Western system, and I think we will be able to get enough loads on there, certainly to collect our remaining CAD1 billion rate base, and hopefully more.

Okay, that's helpful. Thank you.

Jeremy Tonet, JPMorgan.

Good afternoon.

I was just wondering if you could speak to the Columbia transaction and if this impacts your overall strategy towards growth capital spend. Specifically in Mexico we see the potential to divest some assets, while at the same time to build some new assets. Just wondering if you could speak to the little bit.

I think that we've built market positions in our core geographies. If there is attractive business to be had we will continue to pursue those businesses. We have the capacity to bid in, construct and put these assets into operations. That's a huge value-adding step.

And then we can take some capital out of them by selling down our interest and recirculate that capital into things like the Columbia acquisition or into further projects in places like Mexico or elsewhere on our portfolio. But monetizing certain pieces of our portfolio doesn't mean that we are no longer interested in those businesses. We just think that's a better way to manage our capital.

So, as I think about Mexico, I think there's going to be continued opportunity to grow our investment base there. But that doesn't necessarily mean that we need to use 100% of TransCanada's capital to permanently finance those assets for the long haul.

Okay, great. Thanks for that. And just a high-level philosophical question; you've seen a trend in the US towards corporate simplification where there's been a folding in of MLPs. I'm just wondering if that would ever makes sense for TRP, or just how you think about that trend in general.

I'll take a quick shot and I'll pass it over to Don. We have had MLPs or LP-like structures that we've used for a number of years. We've had one in the power side of our business, we've had one in the midstream side of our business, and we've had one in the pipeline side of our business. Through their timely [pat-on base], they have been fundamentally financing vehicles for us. And if at a point in the cycle they can offer financing alternatives that has a cost of capital that is cheaper than our other alternatives, we would utilize them.

We have bought them back in in the past and we've also sold them off. In the case of our TC PipeLines LP, it's been in place since 1997, if I recall. I would say that we continue to look for value opportunities, but at the current time we don't have any plans on restructuring our portfolio.

It's Don here.

When you look it us on the complexity spectrum in the sector here, I think we're more at the simplistic end in terms of understandability and the number of public vehicles here. As Russ mentioned, these vehicles are there to be used judiciously. But we weigh them against alternate sources of subordinated capital. At present preferred shares are very attractive and the hybrid market's improving. So, that is what we weigh these things against.

It's entirely conceivable we use our LP for a vehicle high-quality but smaller-scale acquisitions going forward, things that could move the dial of the LP but really don't move the dial of the big Parent Company. So, there's a role there but within constraints.

Great. And just one really quick follow up to that, is there any need for two going forward, or is that something you'd talk about at a later date?

That's something we will talk about at a later date. Today we really haven't advanced our analysis on this, and there's really nothing concrete to convey in terms of our thinking, the process or timing, We're still legally prohibited from intervening in managing Columbia's business.

Great. Thank you.

Ben Pham, BMO Capital Markets.

Thanks. Good afternoon, everybody.

Your financing plan you highlighted at investor day had a pretty big chunk of MLP dropdowns, and there are more specifically TC pipes in that scenario. Is that still your plan right now, or should we view the preferred issuance as replacing that potential drop-down this year and potentially going forward?

This is Don here. We look at it continuously, depending on market conditions. As I mentioned, at this point in time the pref market is quite attractive to us. The hybrid market in the US is convalescing quite quickly here. Both of those offer 50% equity credit and substantive deal sizes. We will continue to evaluate the MLP market versus those, specifically.

When you look at the bigger picture here, assuming we can get past the acquisition closing here, we are looking at a capital program north of CAD20 billion over the next three years. Maintaining our credit ratings is quite critical to raising that amount of capital. So, if you look at the merit order of how we're going to finance that -- senior debt within the A grade credit metrics, we'll look at the hybrids and prefs, mezzanine capital to about 12% of our capital structure. That's where we've always indicated we see an inflection point in equity credit there.

We will look at a dividend reinvestment program. That nicely matches our organic build profile at this magnitude. Then beyond that we will look at portfolio management, which includes LP drops, outright asset sales, and the like. A long-winded way of saying it's really at a point in time, but we certainly recognize the reality is the MLP market right now and the cost of capital there.

Okay, thanks, Don. I was wondering, switching to your results in the oil pipeline side, if you could provide some color on what is driving the lower uncontracted volumes. I know you're guidance is based on contracted, but I was just curious just the magnitude, is it volumes moving elsewhere, or differentials closing in between cushion and Texas? And, really, are you more positive or negative on your remarketing ability down there?

Ben, it's Paul Miller here.

We have seen lower volumes on the Keystone System this quarter compared to both Q1 and Q4 of 2015. And it is a result of the lower differentials. Relative to Q1 of 2015, this quarter did see lower spot volumes on ex-Alberta volumes. But recall late last year we added 15.000 barrels per day of new 20-year contracts, bringing the total contract position on Keystone to 545,000 barrels per day.

With these new contracts our Q1 ex-Alberta volumes from Canada to Cushing were flat over the last quarter. Where we're seeing the primary volume reduction is on the segment of the system moving south of Cushing. This quarter saw lower volumes relative to both Q1 and Q4 2015. And, again, this is due to narrowing differentials. If you take a look at the forward curve, we don't anticipate these differentials to recover in the foreseeable future, so we will continue to move our contract volume and take opportunities to move spot volumes when they present themselves.

Okay. Thanks, Paul. Thanks, everybody.

Faisel Khan, Citigroup.

Thanks. Good afternoon. Thank you for the details in the press release. Just a couple questions.

On the asset sale program, I was just curious if you'd looked at maybe retaining more of Mexico and maybe selling more of the power assets, to try to understand the calculus behind the mix of mix of asset sales given that you still have the strong growth rate in Mexico with even the new pipeline that you announced and you'd want to bid on. So, just wanted to see how you're thinking about the mix of asset sales there.

It's Don here.

Obviously we're still very enamored with Mexico. We believe the minority interest that we are looking to sell there will attract a premium valuation given the quality of those assets. That's part of the equation.

In terms of selling more power assets, what's on the block right now is largely merchant assets, and it's a very longstanding profitable business that will give somebody a very solid core position in that market. So, it should be of keen interest to strategic buyers.

Moving beyond that asset base, you're starting to look at pretty much heavily contracted assets, which have credit rating supportive attributes and dividend paying attributes. The other thing we look at closely is the tax incident of selling anything.

We look at a tax basis in all these assets, as well, because beyond that you get after-tax proceeds not just pretax proceeds. We think this combination of asset sales checks all the boxes here and will allow us to get to CAD7 billion-ish of net proceeds to form the cash component required to close Columbia here and maintain the credit ratings.

Thanks, that makes sense.

And then just a follow-up, on the synergies between the Columbia pipeline system and your Mainline system, can you discuss what the potential commercial synergies could be? Are there projects that you might have at the high level that you think could be connected between the two pipeline systems? Just trying to understand how you are looking at the vision of this transaction going forward.

Yes, it's Karl.

The synergies that we've come out with, which is CAD250 million, they are approximately, I would say, about 40%-ish of them would be financing synergies. The remainings are basically cost synergies, a little bit of revenue synergies in it. Those are synergies that we've announced, assuming we're going to get them half in 2017 and half in 2018.

What you're talking about is how do we connect these system, what type of revenue will we get from the combined systems, what are those synergies. We haven't actually gone that far on the analysis yet. But I can tell you that those are outside of the 2017 and 2018 timeframe. And those are things that we've looked in the future probably maybe end of the decade or so.

But they're very hard to speculate on right now. Obviously we haven't closed the deal, and once we close it we will be able to start looking at the assets in that light a little bit closer.

Okay. And the last question for me, how are you working on a retention policy for the key management or key people in place on the CPGX?

It's Alex. That's an issue that we're very cognizant of and we're confident that we will have arrangements in place that will see the people sticking around that are going to be carrying forward with the Company.

Great. Thank you for the time.

Harry Mateer, Barclays.

Hi, thanks. Two for me.

The first one, can you just talk a little bit about the CPGX debt that's outstanding? Do you have any intention of guaranteeing that, or are you more likely to treat this like the ANR purchase where those bonds were not explicitly guaranteed?

It's Don here. We're just working through that now. We don't really have anything to add on that front. These are asset level bonds. They are supported by a fairly stable revenue stream. But we really haven't crossed that bridge yet as to what we might do with that.

Would financing in the future occur at the CPGX entity, or would your intention be to do that at TransCanada itself?

Again, to be determined. These are FERC assets, so there are unique aspects to them in terms of for capital structures and the like. But we haven't made that determination.

Okay. And then just on the ratings, you mentioned A credit ratings a long time, or you've mentioned it a couple times, and you've been A for a long time. S&P went to a negative outlook after the deal announcement, so I'm just trying to get a sense for how critical those A ratings are to you, and where you think you will ultimately shake out with S&P.

We certainly value the A credit rating, and we use the term, it's not worth anything until it is, and then it's worth a lot. It allows us to do things that all points of the economic cycle. As we look at a combined CAD24 billion capital program, certainly continuous access to capital on attractive terms is critical to getting full value and actually executing that.

In terms of the negative outlook from S&P, we would hope that executing on our asset sale program is a significant step to resolving that. It's not an inconsequential number, CAD7 billion of asset sales, but we hope that getting that done is a major step to getting that removed.

Got it. Thanks very much.

Steven Paget, FirstEnergy.

Good afternoon and thank you. We're seeing some Mainline long-haul to short-haul conversions. Could you please comment on the impact, if any, of these conversions on future Mainline earnings?

Yes, Steven, it's Karl.

These Mainline conversions, I think we lost -- I won't say lost because TransCanada is keeping these volumes -- they're just moving from Empress to Dawn -- 200 million cubic feet a day at April 1, and I think we are expecting about 600 million cubic feet a day come at the end of the gas year, which will be October 31. And then there are probably more. This is what all anticipated in the Mainline.

This was actually the essence of the LDC settlement. We would debottleneck the southern tip of the Eastern triangle in exchange for the commercial arrangements we got from the LDC, the eastern LDCs. We've actually forecasted all of these movements in our tolling. We are well covered on our tolling and we don't expect any issues of not collecting any of our revenue on this system.

Thank you, Karl. A very useful answer.

Second, Columbia, you talked about a possible augment here to dividend growth rate. First, you mean a dividend growth rate that may be higher than 10%? And when might we know if the Columbia acquisition might result in the dividend growth being augmented through 2020?

It's Don here. Key steps in our consideration -- we get the transaction closed, execute the capital program, and deliver on the synergies. I can't give a specific point in time. But as we move along that process we will have a better sense as to what our financial capacity is to relook at the dividend.

But I'm not misreading the word augment as possibly greater than 10%?

Augment, yes -- the definition is higher rather than lower.

Excellent. Thank you.

Linda Ezergailis, TD Securities.

Thanks. Just some follow-ups.

I realize you're deemphasizing your merchant exposure, but we are potentially moving to somewhat of a hybrid market in Alberta. And I'm just wondering, you do have some capacity there, although it's somewhat de minimis, I'm wondering what your interest is, if any, in participating potentially in the renewal process of natural gas-fired generation, and what parameters might need to be in place for you to invest in that province?

Sure, Linda. It's Bill.

We are watching the developments that are unfolding on the renewable procurement side very carefully. That process has begun in earnest. I guess I would call it the study phase by the Alberta ISo, They are expected in the coming few months to be starting to release details of that.

We have had opportunity to input to them directly as to our thoughts on how that may be structured or how that may be best structured. As Russ mentioned in his remarks, we would continue to be seeking solid investment opportunities across all of our businesses, and that would include renewable power in Alberta.

And what about gas-fired generation?

Gas-fired is a little bit more challenging, given the market circumstance that exists in Alberta right now. I think that it's clear that the renewal generation approach will be involving some subsidization of that, and we're not exactly sure what that would look like. It's not clear what they're going to do, if anything, with regards to gas-fired.

I think certainly in most jurisdictions that we have built new gas-fired generation, like our Napanee facility that we've got under construction right now, that construct is something that makes sense to us going forward. And we continue to look for.

To the extent that Alberta moves that far down the curve in terms of restructuring market, obviously that becomes something that's very attractive to us. But we have to wait and watch and see how they structure the market here in Alberta going forward.

Okay, thank you.

And just a follow-up question on less core business operations. Columbia has a small but growing midstream operation. And I realize you're probably not focused on that right now, but have you had any thought more broadly to potentially reentering the midstream arena, not just within Columbia pipelines but in your other geographies, as well?

Linda, it's Alex. We have not given a lot of thought to a significantly larger scale reentry into the midstream business. I will tell you that we have had the opportunity to sit down with Columbia management. They have a very attractive, relatively small-scale midstream business. As time goes on and we're able to spend more time with them we will develop a more wholesome view on that.

To the extent of getting the larger question, Linda, on getting into the midstream business, we have been in the business in the past. And I would distinguish what we like from what we didn't. It didn't fit with us. The frac spreads business isn't a business that we're ever likely to get into again. But a fee-based processing business isn't something that we're afraid of.

To the extent that some of these projects move forward, moving gas to the West Coast on a large scale, if there's straddle plant fee-based arrangements for extracting the liquids from those pipelines, certainly that's something we would be attracted to and the kind of things that we're thinking about. But it's more in that context of what I would call fee-based business that is consistent with how we are operating the rest of our businesses.

Thank you.

Steven Paget, FirstEnergy.

Thank you. Now that you've put the Sundance and Sheerness PPAs back to the pool, do your contracted sales in Western Power for the remainder of 2016 now exceed your supply? And if so, how do you plan to wind up these contracts?

Steve, it's Bill here. We don't disclose specific data on our hedge book percentages and the like in light of the commercial sensitivity of that data. But suffice it to say that we've previously guided that we operate in a 30% to 70% range. And you can assume that we are on the higher end of that range in light of the termination of the PPAs.

All right. Thank you, Bill.

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

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

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