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 Maneta, Vice President, Investor Relations. Please go ahead, Mr.
Maneta.
Thanks very much, and good afternoon, everyone. I'd like to welcome you to TransCanada's 2016 Q1 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 Carl Johansen, President of our Natural Gas Pipelines Business Paul Miller, President of Liquids Pipelines Bill Taylor, President of Energy and Glenn Manus, 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 dotcom. It can be found in the Investors section under the heading Events and Presentations. Following their prepared remarks, we will turn the call over to the conference coordinator for questions from the investment community. If you are a 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 2 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'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 and Exchange Commission. I'd also like to point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, earnings before interest taxes, depreciation and amortization or EBITDA, 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 U. S. Securities law, it will be filed on Colombia's EDGAR profile and TransCanada's EDGAR and SEDAR profiles.
With that, I'll now turn the call over to Russ.
Thank you, David. 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. But in the midst of those challenges, TransCanada's energy infrastructure assets continue to perform well, allowing the company to deliver record comparable earnings and funds generated from operations in 2015. Our $64,000,000,000 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 flow stability throughout this energy market downturn.
On March 17, we announced the US $13,000,000,000 acquisition of Columbia Pipeline Group. This development represents a transformational change for the company and creates an industry leading pro form a $24,000,000,000 portfolio of near term growth projects that will support and may augment our expected 8% to 10% annual dividend growth through 20 20. In addition, our suite of $45,000,000,000 of medium to longer term projects has the potential to further transform this company as we move into the future. Focusing on the Q1, comparable earnings were up 6% over Q1 to $494,000,000 or $0.70 per share. Despite the weakness in power prices, comparable earnings comparable EBITDA was $1,500,000,000 and funds generated from operations were $1,100,000,000 similar to the Q1 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 financial results, I'd like to provide you with a brief update on our major on progress on some of our major projects. Starting with the Columbia transaction, the largest one 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 1 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 U. S, Northeast, Midwest, Mid Atlantic and Gulf Coast regions. Its assets include Columbia Gas Transmission, which operates 18,000 kilometers of pipelines and 286,000,000,000 cubic feet of storage capacity in the Marcellus and Utica and Columbia Gulf Transmission, which is a 5,400 kilometer system that extends 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, Colombia is currently advancing US7 $300,000,000 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 25.5 dollars per share, representing an aggregate transaction value of approximately US13 $1,000,000,000 including the assumption of approximately $2,800,000,000 of debt. Columbia's proxy statement for a special meeting of shareholders to approve the acquisition was filed with the SEC on April 8. The special meeting of Columbia shareholders is scheduled for June 22, 2016 to vote on the transaction. On April 4, notifications were filed with the U. S.
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 twenty sixteen 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 form a EBITDA coming from regulated long term contracted assets. Looking forward, the modern monetization of our U. S.
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 1st full year of operation to earnings. Later, Don will provide you a little bit 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 Villadore 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 $550,000,000 pipeline is underpinned by a 25 year transportation service contract with Mexico 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 $500,000,000 U. S.
Tula Tuxpan natural gas pipeline, which is also underpinned by a 25 year contract with CFE. Construction is expected to begin in 2016 and that pipeline should be operational in the Q4 of 2017. The $1,000,000,000 Topolobabo project and the $400,000,000 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 Villas del Rey pipeline, our investment in Mexico now sits at about $3,500,000,000 On our NGTL system, in the Q1 this year, dollars 100,000,000 of new facilities became operational and $600,000,000 more are currently under construction. The NGTL system continues to develop $7,300,000,000 of new supply and demand facilities.
Currently, dollars 2,500,000,000 of those facilities have received regulatory approval and a further $1,900,000,000 are currently being reviewed by the regulator. And we continue to work on applications for the approval to build and operate the additional $2,900,000,000 of facilities. Earlier this month, we filed a request with the National Energy Board for 1 year extension of the Certificate of Public of Convenience and Necessity for the North Montney mainline project. The requested shares or regulatory approvals remain valid and do not expire before the final investment decision for the Pacific Northwest LNG project. So with US7.3 billion dollars or about CAD9.6 billion of projects from the Columbia Pipeline Group underway, Our portfolio of near term projects will increase to about $24,000,000,000 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, essentially 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 $45,000,000,000 portfolio of a larger scale longer term projects, Starting with the PGRT project, Pacific Gas or Prince Rupert Gas Transmission Project, where we signed 2 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 Rupert project, following the confirmation of a final investment decision from Pacific Northwest LNG. On the Coastal GasLink project, the LNG Canada joint venture participants anticipate reaching final investment decision on the Kitimat based LNG project in late 2016. We continue to advance the Energies project through the regulatory process with the NEB announcing its schedule this week.
And lastly, we continue to work to submit estimates for the first of 6 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. 2nd, we'll close the U. S.
$30,000,000,000 Columbia Pipeline Group acquisition and complete our asset sales. 3rd, we'll bring our pro form a combined $24,000,000,000 of near term projects through the approval process, construction and into operation. 4th, we will advance our $45,000,000,000 portfolio of long term projects. And 5th, 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 on some more details of our financial performance. Don?
Great. Thanks Russ and good Friday afternoon to everyone. As highlighted earlier, we reported net income attributable to common shares in the Q1 of $252,000,000 or $0.36 per share, which compares to net income in the same quarter of 2015 of $387,000,000 or $0.55 per share. The year over year decrease stems primarily from net after tax charges of $211,000,000 for a number of specific items in Q1 2016, including $176,000,000 relating to the remaining net book value associated with our investment in the Alberta PPAs as a result of our termination decision, $26,000,000 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 Q1 2016 increased 6% to $494,000,000 or $0.70 per share compared to $465,000,000 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 from the Keystone system, Eastern Power, U. S. Power and Western Power. In terms of our business segment results at the EBITDA level, in the Q1, comparable EBITDA was slightly lower than the same period last year.
Our Natural Gas Pipelines business generated comparable EBITDA of $898,000,000 in Q1 2016 compared to $864,000,000 a year earlier. Canadian Gas Pipelines comparable EBITDA of $507,000,000 was largely in line with 2015. For the quarter, net income from the Canadian Mainline increased by $3,000,000 primarily due to higher incentive earnings, partially offset by a lower average investment base in 2016. No incentive earnings were recorded in the Q1 of 2015. The NEB approval of compliance tolls related to the LVC settlement was not received until June 2015.
The NGTL Systems quarterly net income increased $9,000,000 year over year to $73,000,000 mainly due to a higher average investment base. When measured in U. S. Dollars, comparable EBITDA 2015. This was the net effect of higher ANR Southeast mainline transportation revenues offset by a Q1 2015 non recurring customer settlement, lower contributions from Mexico pipelines and higher transportation revenues from Great Lakes.
In Canadian dollar terms, the stronger U. S. Dollar in Q1 2016 had a positive impact on the Canadian dollar equivalent comparable earnings from our U. S. And international operations.
In liquids, the Keystone Pipeline system generated $307,000,000 of comparable EBITDA in the Q1, a $4,000,000 decline from the same period in 2015. The decrease was the net effect of lower contract fit volumes on the Keystone pipeline system and lower volumes on Market Link, partially offset by the positive impact of the stronger U. S. Dollar. Turning to energy, comparable EBITDA of $329,000,000 in the first quarter declined $57,000,000 in the same quarter last year due to the net effect of 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 Beckancorp, 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 planned out higher planned outage days. There were lower earnings in the U. S. 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 in 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 $420,000,000 in the Q1 increased by $102,000,000 compared to the same period last year. This was primarily due to long term debt issuances in 2015 Q1 2016 partially offset by Canadian and U. S.
Dollar denominated debt maturities, a stronger U. S. Dollar and its effect on interest expense on U. S. Dollar denominated debt and lower capitalized interest on Keystone XL and related projects following the November 6, 2015 denial of a U.
S. 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 133,000,000 for the 3 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 U. S. Dollar denominated income and increased AFUDC related to our rate regulated projects including Mexico pipelines and GTL system expansions and Energy East.
Comparable income tax expense for the Q1 decreased by $67,000,000 compared to the same period in 2015, mainly as a result of lower pre tax earnings in 2016, changes in 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 non controlling interests increased by $21,000,000 for 3 months ended March 31, 2016 compared to the same period in 2015, primarily due to the sale of 2 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 U. S. Dollar on the Canadian dollar equivalent earnings from TC PipeLines LP. Preferred share dividends were $22,000,000 for the 3 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 $1,100,000,000 the quarter consistent with 2015. For the Q1, comparable distributable cash flow was up modestly to $970,000,000 or $1.38 per common share, which represents an increase from $1.35 per common share in the Q1 of 2015. Maintenance capital expenditures on our Canadian regulated natural gas pipelines were $55,000,000 $52,000,000 in Q1 2016 and 2015 respectively, which contributed to their respective rate basis net income. Capital spending totaled $903,000,000 in the Q1, driven principally by expansions of the NGTL Canadian mainline and ANR systems and construction activities on Mexico pipelines, Northern Courier and Napanee.
Equity investments of $170,000,000 in the quarter related to our share of spending at Bruce Power in Grand Rapids. Acquisitions of approximately $1,000,000,000 reflect the purchase of Ironwood on February 1, 2016 for US657 million dollars as well as an additional interest in Iroquois gas transmission for US54 million dollars Our ownership in Iroquois is now 49.35 percent. Now turning to Slide 19, our liquidity and access to capital markets remain strong. At March 31, our consolidated capital structure consisted of 30% common equity, 5% preferred shares, 4% junior subordinated notes and 61 percent debt net of cash. At quarter end, we had $1,200,000,000 of cash on hand.
On April 20, 2016, we completed a public offering of 20,000,000 preferred shares at a price of $25 per share, resulting in gross proceeds of $500,000,000 The initial fixed dividend rate for these preferred shares is 5.5 percent per annum and will reset every 5 years to a rate equal to the sum of the applicable 5 year Government of Canada bond yield plus 4.69%, provided that such rates shall not be less than 5.5% per annum. We remain well positioned to finance our industry leading pro form a $24,000,000,000 capital program with multiple attract funding options available, including predictable and growing internally generated 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 coordinated 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 Columbia Pipeline Partners LP going forward. We will turn our attention to this post completion of the transaction.
The US13 $1,000,000,000 Colombia acquisition includes approximately US2.8 billion dollars of assumed debt. The remaining US10.2 billion dollars 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 U. S. 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 US6.9 billion dollars In total, including the full exercise of the underwriters over allotment option, we issued 96,600,000 subscription receipts at $45.75 per receipt for gross proceeds of approximately $4,400,000,000 Each subscription receipt will automatically convert to one common share upon closing of the Columbia acquisition.
While the 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 at a financing and the planned asset monetization to be accretive to earnings per share in our 1st full year of ownership. In closing, during the Q1 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 $1,100,000,000 were consistent with the same period last year. We remain well positioned to finance both the Columbia acquisition as well as our combined pro form a $24,000,000,000 portfolio of near term growth projects supported by our internal 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 $4,400,000,000 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 U. S. Northeast power assets and minority interests 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 and A.
Great. Thanks, Don. Just a reminder, before I turn the call back over to With that, I'll turn it to the conference
The first question is from Linda Ezergailis from TD Securities. Please go ahead.
Thank you. I'm wondering how much the first quarter results benefited from cost your cost savings initiative. Is it reasonable to assume that it was approximately a quarter of your $50,000,000 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. Yes, to your question, the discussions have only just begun on that question with the Ontario independent system operator. And as you say, precedent would suggest that there will be some amendments. The nature of how the tax would flow through to our various contracts is it's actually unique by contract because there is slightly different wording in various contracts.
So that's a matter that will depend on the impact will depend on the outcome of those discussions. So it's kind of hard to say it, but we also don't expect it to be material given that just the general nature of the way those contracts work.
Thank you. The following question is from Paul Linjamb from CIBC. Please go ahead.
Thank you. Good afternoon. I realize it's not 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 asset packages that you're selling? And any timing from here on in terms of when you expect indicative pricing and how you expect the process the two processes to unfold?
Hi, Paul. It's Don here. Yes, the processes are underway. We have advisors retained, data rooms are being populated, CIMs are being prepared. So, we're about to move through a 2 stage traditional 2 stage auction process here.
The Northeast power process is probably running a couple of weeks ahead of the Mexican one. Interest to date has been substantial from strategic and financials for both asset packages and from indications of interest at this point. So, we'll move through that process and probably tracking to something Q3 mid to late Q3 at this stage in terms of hopefully getting through that process. Closing would then be probably several months to maybe in a couple of quarters after that. Gotcha.
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. But if we'll see what interest levels are for specific assets, but they are currently being marketed as a portfolio.
Okay. Thanks very much.
Thanks, Paul.
Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.
Great. Thank you. If I can just maybe follow-up on the asset sale process. You've got what I'm assuming, Don, you're 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 U. S. Power side, you've moderated the outlook. Does that change how you're thinking about that? Or did you kind of have that outlook when you set the target of asset sale proceeds when you announced Columbia?
It's pretty early days, Robert, on forgot where we're going to land, but we remain of the view that the 6 $7,000,000,000 area is certainly achievable. Yes, 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 Colombia, oil pipeline permitting has obviously been challenging as you've lived through the thick of that. But that being said, I'm just wondering how you're viewing what happened on Constitution. Do you see that as being or just with Columbia in the general, somewhat general vicinity, you see that as being a New York thing or a constitution thing and just kind of your thoughts as you think about the Columbia business and their growth projects?
Robert, it's Carl. Yes, we have a number of pipeline projects, none in New York that we will be proceeding with permits. Many of them 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 our projects most of the projects 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 $7,000,000,000 in U. S.
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 and supportive of the benefits pipeline development brings. So 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 are they're still working really hard to make sure that there are no problems with the permitting.
That's great. Thanks, Karl. Thanks, Don.
Thanks, Robert.
Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.
Thank you. Good afternoon. I guess the question is for Russ and others might want to chime in as I ask this. So 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 in Canada at this stage as a pipeline or and then really just for the broader energy industry ramifications, how do you think about that at the stage you're 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. If you look at the West Coast LNG projects, we're pretty close to the end of those. One of the worries always is how long these processes take and having to wait them through business cycles and we've seen the impact of that before. So I would say that we're still cautiously optimistic that we'll 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's a greater understanding of the impact that the development of those can have on the economy, economic development, job creation And that they're fundamental to the long term prosperity of our country.
They have to be done in any safe manner. I think we can all we all agree kind of on that as well, but it appears that there is some harmony around the importance of getting these things done in a timely way. So 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 Carl as it relates to the just the mainline. And so if we think about the mainline as an asset, you've got a rate base right now about C4.4 billion. If we went back 15 years or so ago, it was about CAD10 1,000,000,000. Appreciate this pretty significantly. If Energy East goes ahead, the chunk of that's coming off.
So how do you think of just the relative competitiveness of the mainline versus other proposed options to really use to Ontario and Quebec?
Well, it's a good question. When our LDC settlement comes into full force, in fact, which is 2020, we will actually the mainline will actually be 2 different utilities. The Eastern Triangle, which I think is going to be very difficult for somebody to duplicate or get around. So the Eastern Triangle, which will have the majority of the capital from what we know is the mainline today, is I think a pretty solid utility. I think it's tough for people to get around it.
I think that it'll be around for years and highly used. The Western system will have only about $1,000,000,000 in capital left after 2020. And that system still has about 800,000,000 a day of captive load on it, load that has considered Panko elsewhere. So still got a pretty decent load on it. Pricing wise for that particular part of the mainland, 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. And we should have some flexibility to make volumes move as we see fit. So I think the 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, right? When you take a look at the cheapest ways out of the WCSB right now, going down in Chicago, going into GTN down into California and whatnot.
I don't think the mainline will ever beat out the $0.35 that GTN has from down into down in the California border. So I do think it probably will still remain to be a more expensive alternatives than like 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'll be able to we'll be able to get enough flows under, certainly to collect our remaining $1,000,000,000 rate base and hopefully more.
Okay. That's helpful. Thank
you. Thanks, Andrew.
Thank you. The next question is from Jeremy Tonet from JPMorgan. Please go ahead.
Good afternoon. Hi, Jeremy. I was just wondering if you could speak to the Columbia transaction and if this impacts your kind of overall strategy towards growth capital spend. Specifically in Mexico, we see the potential to divest some assets while at the same time build some new assets. Just wondering if you could speak to that a little bit.
I think that we've built market positions in our core geographies and we're if there's attractive business to be had, we will continue to pursue those kind of 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 could take some capital out of them by selling down our interest and then recirculate that capital into things like Columbia acquisition or into further projects in places like Mexico or elsewhere in our portfolio. But monetizing certain pieces of our portfolio doesn't mean that we're 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 continue to grow our investment base there, but that doesn't necessarily mean that we need to use 100% of Trans Canada'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 U. S.
Towards corporate simplification where there's been folding in of MLPs. I'm just wondering if you could ever speak to if that would ever make sense for TRP or just how you think about that trend in general?
I'll take a quick shot
at it and I'll sort of pass it over to Don. But we have had MLPs or LP like structures that we've used for a number of years. We've had 1 in the power side of our business. We've had in the midstream side of our business and we've had 1 in the pipeline side of our business. And through their times we've had them, they have been fundamentally financing vehicles for us.
And if at a point in the cycle, they can offer financing alternative that has a cost of capital that's 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. And in the case of our TC pipelines LP, it's been in place since 1997, if I recall. So 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.
Yes, it's Don here. When you look at us on the complexity spectrum in 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 and are very attractive in hybrid markets improving. So that's what we weigh these things against. It's entirely conceivable.
We use our LP for a vehicle for high quality, but smaller scale acquisitions going forward, things that can 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 real quick, I guess, follow-up to that. Is there any need for 2 going forward? Or is that something you would talk about at a later date?
Yes, it's something we'll talk about at a later date. Today, we really haven't advanced our analysis on this. And there's really nothing really concrete to convey in terms of our thinking, the process or timing. And we're still legally prohibited from intervening and managing Columbia's business.
Great. Thank you.
Thanks, Jeremy.
Thank you. The next question is from Ben Pham from BMO Capital Markets. Please go ahead.
Okay. Thanks. Good afternoon, everybody. So your financing plan, you highlighted Investor Day had a pretty big chunk of MLP dropdowns in there or more specifically TC pipes in that scenario. Is that still your plan right now?
Or should we view the preferred share issuance as replacing that potential drop down this year and potentially going forward?
Well, we look at it it's Don here.
We look at
it continuously depending on market conditions. As I mentioned, at this point in time, the prep market is quite attractive to us. The hybrid market in the U. S. Is convalescing quite quickly here.
Both of those offer 50% equity credit and substantive deal sizes. So 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're looking at a capital program north of $20,000,000,000 over the next 3 years. Maintaining our credit ratings is quite critical to raising that amount of capital. So 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 crafts 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 of this magnitude. And then beyond that, we'll look at portfolio management, which includes LP drops, outright asset sales and the like.
So long winded way of saying it's really at a point in time, but we certainly recognize the realities of the MLP market right now and the cost of capital there.
Okay. Thanks, Don. And I was wondering switching to your results in the oil pipeline side, I was wondering if you could provide someone could provide a bit of color on what's driving the lower uncontracted volumes. I know your guidance is based on contracted, but I was just curious just the magnitude of the volumes moving elsewhere, differentials closing in between Cushing and Texas? And really, how does that are you guys more positive or negative on your remarketing ability down there?
Ben, it's Paul Miller here. So we have seen lower volumes on the Keystone system this quarter compared to both Q1 and Q4 of 2015 and then as a result of the lower differentials. Relative to Q1 of 'fifteen 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. So with these new contracts, our Q1, let's call it 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 of 2015. And again, this is due to narrowing differentials. 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 our spot volume when they present themselves.
Okay. Thanks, Paul. Thanks, everybody.
Thanks, Ben.
Thank you. The next question is from Faisal Khan from Citigroup. Please go ahead.
Thanks. Good afternoon and thank you for the details on the press release. Just a couple of questions. On the asset sale program, I'm just curious if you had looked at sort of maybe retaining more of Mexico and maybe selling more of the power assets. I mean, just trying to understand the sort of calculus behind the mix of asset sales, given that you still have the strong growth rate in Mexico with even the new pipeline that you'd announced and you'd want to bid on.
So just wanted to see how you're thinking about sort of the mix of asset sales there?
Yeah. It's Don here. Obviously, we're still very enamored with Mexico. And we believe the minority interest that we're looking to sell there will attract a premium valuation given the quality of those assets. So that's part of the equation.
In terms of selling more power assets, what's on the block right now is largely merchant assets, which and it's a very long standing 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. So we look at a tax basis in all these assets as well, because at the end of the day, you get after tax proceeds, not just pre tax proceeds.
So we think this combination of asset sales checks all the boxes here and will allow us to get to 7,000,000,000 ish of net proceeds to form the cash component required to close Colombia here and maintain the credit ratings.
Thanks. That makes sense. And then just a follow-up, just on the synergies between the Colombia pipeline system and the main line your Mainline system, can you discuss sort of 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 2 pipeline systems? And I'm just trying to understand how you guys are looking at the vision of this transaction going forward.
Yes, it's Carl. So the synergies that we've come out with, which is $250,000,000 They are approximately, I'd say about 40% of them ish would be financing synergies. The remainings are basically cost synergies, a little bit of revenue synergies in it. And those are synergies that we've announced assuming we're going to get them kind of half of twenty seventeen and half of twenty
what type of revenues will we get from the
combined systems, what are those what type of revenues will we get from the combined systems, what are those synergies? We haven't actually gone that far on the analysis yet. I can tell you that those are outside of the 'seventeen and 'eighteen timeframe. And those are things that we'd look in the future probably maybe end of the decade or so. But they're very hard to speculate on right now.
We haven't gotten actually obviously, we haven't closed the deal. And once we close it, we'll be able to start looking at the assets in that light a little bit closer.
Okay. And the last question for me. And then how are you guys working on a retention policy for the key management or key people in place on the CPGX?
That's an issue it's Alex. By the way, that's an issue that we're very cognizant people sticking around that are going to be
carrying forward with the company.
Thank you. The next question is from Harry Mateer from Barclays. Please go ahead.
Hi, thanks. 2 for me. I guess 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 you might look 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're not we don't really have anything to add on that front. These are asset level bonds. They're supported by a fairly stable revenue stream there.
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 to 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 FERC 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 and you've been or you mentioned a couple of times, you've been single A for a long time. S and P went to a negative outlook after the deal announcement. So I'm just trying to get a sense for how critical those single A ratings are to you and where you think you'll ultimately shake out with S and P?
Yeah, we certainly value the A credit rating and we use the term it's not worth anything till it is, then it's worth a lot. It allows us to do things at all point to the economic cycle. As we look at a combined $24,000,000,000 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 and P, we would hope that executing on our asset sale program is a significant step to resolving that. So that's I think it's not an inconsequential number of $7,000,000,000 of asset sales.
But we hope that is getting that done is a major step to getting that removed.
Got it. Thanks very much.
Thank you. The next question is from Steven Paget from FirstEnergy. Please go ahead.
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, Stephen. It's Karl. These mainline conversions, I think we lost we I won't say lost because TransCanada is keeping these volumes. They're just moving from Empress to Dawn. 200,000,000 cubic feet a day at April 1, and I think we're expecting about 600,000,000 cubic feet a day come at the end of the gas year, which will be October 30 1.
And then there are probably more. This was 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 LDCs, the Eastern LDCs. And so we've actually forecasted all 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 the system.
Thank you, Carl. That's a good very useful answer. 2nd, Columbia, you talked about augment a possible augment to your 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?
Yes, it's Don here. Well, I guess key steps in our consideration, we get the transaction closed, execute the capital program and deliver on the synergies. So I can't give a specific point in time, but as we move along that process, we'll 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.
Thanks, Steven.
Thank you. The following question is from Linda Ezergailis from TD Securities. Please go ahead.
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, renewable process and natural gas fire generation?
And what sort of parameters might need to be in place for you to invest in that province?
Sure, Linda. It's Phil. We're watching the developments that are unfolding on the renewable procurement side very carefully. You may know that that process has begun in earnest. It's that I guess would call it sort of the study phase by the Alberta ISO and they are expected in the coming few months to be starting to release details of that.
We've had opportunity to input to them directly as to our thoughts on how that may be structured or how that may be best structured. So 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?
Well, gas fired, it's a little bit more challenging, I guess, given the market circumstance that exists in Alberta right now. I think that it's clear that the renewable generation approach will be involving some subsidization of that and we're not exactly sure what that would look like. 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 fire generation like our Napanee facility that we've got on our construction right now. And that construct is something that makes sense to us going forward. And we continue to look for. So to the extent that Alberta moves that far down the disturbed interest 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 kind of less core business operations. Colombia 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 Colombia pipelines, but in your other geographies as well?
Linda, it's Alex. We have not given a lot of thought to sort of a significantly larger scale reentry into the midstream business. I will tell you that we've had the opportunity to sit down with Columbia Management. They have a very attractive, relatively small scale midstream business. And as time goes on and we're able to spend more time with them, we'll develop a more fulsome view on that.
I think to the extent
of getting the larger question, Linda, on getting into the midstream business, we've been in the business in the past, and I guess I would distinguish what we like and what we didn't it didn't fit with us. But the frac spread business isn't just business that we ever likely to get into again. But a fee based kind of processing business isn't something that we're afraid of. So 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 to be kind of based arrangements for extracting the liquids from those facilities from those pipelines. I mean, certainly, that's something we'd be attracted to and kind of things that we're thinking about.
But it's more in that context of what I would call sort of a fee based business that's consistent with how we're operating the rest of our businesses.
The next question is from Steven Paget from FirstEnergy. Please go ahead.
Thank you. Now that you've put your the Sundance and Sureness PPAs back to the pool, do your contracted sales for 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 Phil 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 previously guided that we operate in sort of a 30% to 70% range. And you can assume that we're on the higher end of that range in light of the cancellation of the or the termination of the PPAs. All right.
Thank you, Bill.
Thanks, Stephen.
Thank you. There are no further questions registered at this time. I would now like to turn the meeting back over to Mr. Mineta.
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 speaking with you again soon. Bye for now.
Thank you. The conference has now ended. Please disconnect your lines at this time.