David Moneta - Vice President, Investor Relations Russ Girling - President and Chief Executive Officer Don Marchand - Executive Vice President, Corporate Development and Chief Financial Officer Alex Pourbaix - Chief Operating Officer Karl Johannson - President, Natural Gas Pipelines Paul Miller - President, Liquids Pipelines Bill Taylor - President, Energy Glenn Menuz - Vice President and Controller.

Linda Ezergailis - TD Securities Paul Lechem - CIBC Robert Kwan - RBC Capital Markets Andrew Kuske - Credit Suisse Jeremy Tonet - JPMorgan Ben Pham - BMO Capital Markets Faisel Khan - Citigroup Harry Mateer - Barclays Steven Paget - FirstEnergy.

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, 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 Glenn Menuz, Vice President and Controller.

Russ and Don will begin today with some opening comments in our financial results and certain other company developments. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com. It can be found in the Investors section under the heading Events 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 Marc 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, Stewart and I will be pleased to discuss some 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 U.S. Securities and Exchange Commission.

I would 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 maybe deemed to be solicitation material in respect of the proposed acquisition of Columbia Pipeline Group by TransCanada. Therefore pursuant to U.S.

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.

During 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 has provided our shareholders with cash flow stability 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 of 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 earnings or comparable EBITDA was $1.5 billion 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 the 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 one as far as the 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 U.S. 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 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 is 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 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 U.S.

Federal Trade Commission and we have also submitted filings with the committee on foreign investments 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 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 first full year of operation to earnings. Later, Don will provide you a little bit 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 are awarded a 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 state-owned power company, CFP, 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 U.S. 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 [indiscernible] project in the $400 million 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 of facilities.

Earlier this month, we filed a request with the National Energy Board for 1-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.

So with $7.3 billion or about CAD9.6 million on 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, 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 billion portfolio of larger scale longer term projects.

Starting with the PRGT projects, which is the gas – Prince Rupert Gas Transmission project where we signed two further project agreements with BC First Nations during the quarter, bringing the total number of agreement 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 Energy East project through the regulatory process, with NEB announcing its schedule this week. And lastly, we continue to work to submit estimates for the first of six reactors refurbishments at 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 $30 billion Columbia Pipeline Group acquisition and complete our asset sales.

Third, we will bring our 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. And very confident execution of these priorities will continue to grow shareholder value for many years to come.

With that, I will pass it over to Don to give you some are 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 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 the first quarter 2016, including $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 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 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 the first quarter 2016 compared to $864 million the year earlier. Canadian gas pipelines 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 lower average investment base in 2016. No incentive earnings were recorded in the first quarter of 2015. The NEB approval of compliance related to the LDC settlement was not received until June 2015.

The NGTL System’s quarterly net income increased $9 million year-over-year to $73 million, mainly due to a higher average investment base. When measured in U.S. dollars, comparable EBITDA for U.S. and international 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 Southeast Mainline transportation revenues offset by a first quarter 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 first quarter 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 million comparable EBITDA in the first quarter, a $4 million decline from the same period in 2015.

The decrease was the net effect of lower un-contracted volumes on the Keystone Pipeline System and lower volumes on Marketlink, partially offset by the positive impact of the stronger U.S. dollar.

Turning to energy, comparable EBITDA of $329 million in the first quarter declined $57 million from the same quarter last year due to the net effect, 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 Bécancour 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 – 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 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 that 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 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 million for the three months ended March 31, 2016, compared to 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 in U.S. 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 non-controlling 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 TC PipeLines LP of our remaining 30% direct interest in GTN on 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 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 related natural gas pipelines were $55 million and $52 million in the first quarter 2016 and 2015 respectively, which contributed to their respective rate base of that 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 pipelines, Northern Courier and Napanee. Equity investments of $170 million in the quarter related to our share of spending at Bruce Power and Grand Rapids.

Acquisitions of approximately $1 billion reflect the purchase of Ironwood in February 1, 2016, for $657 million as well as an additional interest in Iroquois Transmission for $54 million. Our ownership in Iroquois is now 49.35%. 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% 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 5 years to a rate equal to the sum of the applicable 5-year government accounted 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 forma $24 billion capital program with multiple attractive 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 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 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 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 $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 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, 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 internal – growing internally generated cash flow and access to capital consistent with our enduring financial strength.

We are extremely pleased with investors 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 U.S.

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 will now turn the call back over to David for the Q&A..

Great, 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..

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

Thank you. I am wondering how much the first quarter results benefited from your cost savings initiative.

Is it reasonable to assume that was approximately a quarter of your $50 million or is there a ramp in the year?.

Linda, it’s Glenn. Yes, I think that’s a fair estimate. We are 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 am 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 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 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..

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

Thank you. Good afternoon. I realize it’s not have 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 are 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 advisers retained. Data rooms are being populated. CIMs are being prepared. So, we are about to move through a two-stage, traditional two-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 big from strategics and financials for both asset packages and from indications of interest at this point. So, 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 of quarters after that..

Got it.

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 are being marketed as a portfolio, but if – we will 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 have got what I am assuming, Don, you are referring to nonbinding indications of interest. I am just wondering based on what you have received to-date, does that have you on track to the asset sale proceeds? And then specifically around the U.S.

power side, you have moderated the outlook.

Does that change how you are thinking about that or did you kind of have that outlook when you set the target of asset sale proceeds when you announced Columbia?.

Yes, it’s pretty early days, Robert [indiscernible], but we remain of the view that the $7 billion area is certainly achievable. Yes, we recognized 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 permittings, obviously been challenging as you have lived through the thick of that.

But that being said, I am just wondering how you are viewing what happened on Constitution, do you see that as being or just with Columbia in general, somewhat general vicinity, do you see this as an 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, this is Karl. We have a number of pipeline projects, none in New York. We will be receiving 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 way, they are all Brownfield, most of them are compression. There is very late little new pipe of the $7 billion of their construction there is only like 200 miles of new pipe included.

So most of them are Brownfield in their existing right away, they are in jurisdictions in Ohio, they are in West Virginia, they are on the Columbia Gulf going down to Gulf Coast. Most of them are in jurisdictions that are actually very positive towards pipeline development and support of the benefits pipeline development brings.

So as of right now we view the Constitution issues to not being reflective of what we are working in. But having said that, we do appreciate that Columbia has a good team on the ground and their presence in the community and whatnot or they are 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 who might want to chime in as I ask this.

So clearly, you have got the schedule for Energy East, that’s been put forward, it seems like there is 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 stage as a pipeline and then really just for the broader energy industry ramifications, how do you think about at this stage you are more positive, less positive than you may have been previously?.

I think with respect to process and we were feeling like we are headed in the right direction is if you look at the West Coast LNG projects, we are pretty close to the end of those. One of the worries, which is how long these processes take and having to weight them through business cycles and we have seen the impact of that before.

So 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 it would 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 developments, job creation and that they are fundamental to the long-term prosperity of our country.

They have to be done in a safe manner that 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 are feeling fairly positive about things here currently in aggregate with all of our projects..

Okay, that’s helpful. And then if I may ask a follow-up and is probably more directed to Karl as it relates to the just the Mainline and so if we think about Mainline as an asset, you have got a rate base right now about CAD4.4 billion, if we went back 15 years or so ago, it was about CAD10 billion, I appreciate this pretty significant way.

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 build at East Ontario and Québec?.

Well, you asked a good question, but we – when our LDC settlement comes into full force and effect, which is 2020, we will actually – 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.

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. And I think it will be around for years and highly used.

The Western system will have only about $1 billion in capital left after 2020 and that system still has about $800 million a day of capital load on it, load that is considered critical [ph] elsewhere. So we have still got a pretty decent load on it.

Pricing wise for that particular part of the Mainline, I think we are 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 the lines 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 from 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 California border.

So I do think it will probably remain to be a more expensive alternatives than like say Chicago or California. But I think that as time goes on, we are going to see more flexibility, we are going to have more tools at our disposal for the Western system.

And I think we will be able to get enough flows and there are certainly to collect our remaining $1 billion 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 toward 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 built market positions in our core geographies and we are – if there is attractive business to be had, we will continue to pursue those kind of businesses. We have the capacity to dig 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 re-circulate that capital into things like Columbia acquisition or into and into further projects in places like Mexico or elsewhere in our portfolio. But monetizing certain pieces of our portfolio doesn’t mean that we are no longer just in those businesses.

We just think that’s a better way to manage our capital. So as I think about Mexico, I think there is 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 TransCanada’s capital budget to finance those assets for long haul..

Okay, great. Thanks for that. And just a high-level philosophical question, you have seen a trend in the U.S.

towards corporate simplification where there has been folding in of MLPs, I am 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 will take a quick shot at and so pass it over to Don. But we have had MLPs or LP-like structures that we have used for a number of years. We have had one in the power side of our business. We have had one in the midstream side of our business and we have had one in the pipeline side of our business.

And through the time that we have had on, they have been fundamentally financing vehicles for us. And at a point in the cycle, they can offer financing alternatives that has a cost of capital that’s cheaper than our other alternatives. We would utilize them. We have bought them back [indiscernible]. And we have also sold them off.

And in the case of our TC PipeLines LP, it was 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 and in the sector here, I think we are more at the simplistic end in terms of understandability and the number of public vehicles here. Yes, 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 is 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 is a role there, but within constraints..

Great.

And just one real quick I guess follow-up to that, is there any need for two going forward or is that something you talk about at a later date?.

Yes, it’s something we will talk about at a later date. Today, we really haven’t advanced our analysis on this and there is nothing really concrete to convey in terms of our thinking, the process or timing. And we are 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 the 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 share issuance as replacing that potential dropdown this year and potentially going forward?.

Well, we look at it – its 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 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 are looking at a capital program north of $20 billion 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 are going to finance that senior debt within the A grade credit metrics. We will look at the hybrids and prefs, mezzanine capital to about 12% of our capital structure. That’s where we have always indicated we see an inflection point on equity credit there.

We will look at a dividend reinvestment program that nicely matches our organic profile of this magnitude. And then beyond that, we will look at portfolio management, which includes LP drops, outright asset sales and the like.

So, longwinded way of saying it’s really at a point in time, but we certainly recognized 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 some fair bit of color on what’s driving the lower un-contracted volumes? I know your guidance is based on contracted, but I was just curious just the magnitude of is it volumes moving elsewhere or differentials closing in between cushion and taxes? And really how does that – are you guys more positive or negative on your remarketing ability down there?.

And 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 ‘15, this quarter did see lower spot volumes on ex-Alberta volumes.

But you recall 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 are 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. Taking 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 volume when they present themselves..

Okay. Thanks, Paul. Thanks everybody..

Thanks, Ben..

Thank you. The next question is from Faisel 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 am just curious if you 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 had announced and you would want to bid on.

So, just want to see how you are thinking about sort of the mix of asset sales there?.

Yes, it’s Don here. Obviously, we are still very enamored with Mexico. And 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 which – and it’s a very longstanding profitable business that will – can give somebody very solid core position in that market. So, it should be of keen interest to strategic buyers.

Moving beyond that asset base just 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 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 billionish 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, just on the synergies between the Columbia Pipeline System and 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 two pipeline systems? I am just trying to understand how you guys are looking at the vision of this transaction going forward..

Yes, it’s Karl. So, the synergies that we have come out with, which is $250 million, they are – well, approximately I would say about 40%ish of them would be financing synergies. The remainings are basically cost synergies, little bit of revenue synergies.

And those are synergies that we have announced assuming we are going to get them kind of half in 2017, half in 2018. What you are talking about is how do we connect these systems, what type of revenue will we get from the combined systems with one of those synergies? Well, we haven’t – we actually gone that far on the analysis yet.

But I can tell you that those are outside of the ‘17 and ‘18 timeframe and those are things we would look in the future probably maybe end of the decade or so, but they are 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 will be able to start looking at the assets in that a little bit closer..

Okay. And then last question for me.

And then how you guys working on the retention policy for the key – for 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 are very cognizant of. And we are 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..

Great. Thanks, Faisel..

Thank you. The next question is from Harry Mateer from Barclays. Please go ahead..

Hi, thanks. Two for me, I guess.

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

It’s Don here. We are just working through that now. We are not – we don’t really have anything to add on that front. These are asset level bonds, supported by fairly stable revenue stream. But we are – we really haven’t crossed that bridge 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 they are our 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 long time and you been or you mentioned a couple of times that you have been A for a long time, S&P went to a negative outlook after the deal announcement, so I am just trying get a sense for how critical those A ratings are to you and where you think you ultimately shake out with S&P?.

Yes. We certainly value the A credit rating. And we use the term, it’s not worth anything until it is and its worth a lot. It allows us to do things at all points of the economic cycle.

As we look at a combined $24 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.

So that’s – I think that it’s not an inconsequential number, $7 billion of asset sales, but we hope that is getting that done as 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 are 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 are 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 was all anticipated in the Mainline. This was actually the essence of the LDC settlement. We would de-bottleneck the southern tip of the Eastern Triangle in exchange for the commercial arrangements we got from the LDCs, the Eastern LDCs. And so we have 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 the system..

Thank you, Karl. That’s very useful answer. Second, Columbia, you talked about augment, a possible augment to your dividend growth rate.

First, you mean the dividend growth rate that may be higher than 10% and when might we know of 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 will have a better sense as to what our financial capacity is to really look at the dividend..

But I’m not misreading the word augment was 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 realized you are de-emphasizing your merchant exposure, but we are potentially moving to somewhat of a hybrid market in Alberta.

And I am just wondering you do have some capacity there, although it somewhat de minimis, I am wondering what your interest is if any in participating potentially in the renewable process in natural gas fire generation and what sort of parameters might need to be a place for you to invest in that?.

Sure, Linda, it’s Bill. We are watching the developments at around that’s holding on the renewable procurement side very carefully. You may know that that process has begun in earnest. It’s I guess I would call it sort of a study phase by the Alberta and 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. So as Russ mentioned in his remarks, we would continue to be seeking solid investment opportunities across all of our businesses and that that will 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 exist in Alberta right now. I think that it’s clear that the renewable generation approach will be involving some sensitization of that and we are not exactly sure what that would look like.

It’s not clear what they are going to do, if anything with regards to gas fired..

I think certainly in most jurisdictions that we have new gas fired generation like our Napanee facility that we are kind of on construction right now. And that construct is something that makes sense to us going forward. And we continue to look for it.

So to the extent that Alberta moves that far down, just in terms of restructuring market, obviously that becomes something that’s very attractive to us. But we have to wait and watch to 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, Columbia has a small but growing midstream operation and I realize you are 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?.

Hi Linda, it’s Alex. We have not given a lot of thought to sort of 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.

And as time goes on and we are able to spend more time with them, we will develop a more full some view on that..

I think 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 guess I would distinguish what we like and what we didn’t – it didn’t stay with us. But the frac spread business isn’t just the business that we ever likely to get into again.

But our fee based kind of processing business isn’t something that we are afraid of. So the extent some of these projects move forward moving gas to the West Coast on a large scale, get those plants speed kind of based arrangements for extracting the liquids from those facilities, from those pipelines.

I mean certainly that’s something we would be attracted to and kind of things that we are thinking about. But it’s more in that context of what I will call sort of fee based business, it’s consistent with that with how we operating the rest of our businesses..

Thank you..

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

Thank you.

Now, that you have put the Sundance ensuring those 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 that commercial sensitivity of that data. But suffice it to say that we have previously guided that we operate in sort of a 30% to 70% range.

And you can assume that we are on the higher end of that range in light of this to cancellation of the – or the termination of the PPAs..

Alright. Thank you, Bill..

Thanks, Steven..

Thank you. 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 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. Thank you for your participation..