Current TRP Stock Info

On November 9, 2017 TransCanada Corporation (ticker: TRP) announced the company’s financial results for the third quarter of 2017. In the company’s press release, TRP reported a net income attributable to common shares for third quarter 2017 of $612 million or $0.70 per share compared to a net loss of $135 million or $0.17 per share for the same period in 2016.’

Finical highlights from Q3 2017 include:

  • Net cash provided by operations of $1.2 billion
  • Placed the $0.9 billion Grand Rapids pipeline in service
  • Received approval from Canada’s National Energy Board (NEB) to commence service on the Canadian Mainline long-term fixed price service effective November 1, 2017
  • After careful review of changed circumstances, announced the termination of Energy East and related projects and expect an estimated $1 billion after-tax non-cash charge will be recorded in fourth quarter 2017
  • On October 25, announced an agreement to sell our Ontario solar portfolio for approximately $540 million with proceeds to be used to partially fund our near-term capital program. The transaction is expected to result in an estimated $100 million after-tax gain to be recognized upon closing
  • In November, the $1 billion Northern Courier pipeline achieved commercial in-service, and TRP placed the US$0.4 billion Rayne XPress pipeline and the US$0.3 billion Gibraltar project in service. TRP expects to bring the US$1.6 billion Leach XPress project in service in early January 2018
  • Advanced the Portland XPress and Buckeye XPress projects to move additional gas across our pipeline network


Pipeline Operations

Canadian natural gas pipelines

  • Canadian Mainline: Earlier this year, TransCanada announced that it will no longer be proceeding with the proposed Energy East Pipeline and Eastern Mainline Instead of constructing the entire pipeline in Canada, the pipeline was connected to a pre-existing pipeline on the other side of the U.S. border. On September 21, 2017, the NEB approved the long-term fixed price (LTFP) service, as filed, with an effective date of November 1, 2017. This new service allows us to transport 1.5 PJ/d (1.4 Bcf/d) of natural gas at a simplified toll of $0.77/GJ for a ten year term from the Alberta / Saskatchewan border to the Dawn Hub in southern Ontario and provides shippers with toll certainty and improved market access.

Source: TransCanada Corporation

  • NGTL System: In March 2017, TRP filed an application with the NEB for a variance to the existing approvals for the North Montney project on the NGTL System to remove the condition that the project could only proceed once a positive final investment decision is made for the Pacific Northwest LNG project (PNW LNG). North Montney is now under-pinned by restructured, 20-year commercial contracts with shippers and is not dependent on the LNG project proceeding. On September 7, 2017, the NEB provided notice that a public hearing process would be used to consider our variance application. The NEB also stated it would consider the continued appropriateness and applicability of the tolling decisions and associated conditions of the original approval. On October 26, 2017, the NEB issued the Hearing Order indicating the oral portion of the hearing will begin the week of January 22, 2018 with a decision to follow within 12 weeks after the hearing conclusion.

Source: TransCanada Corporation

  • Prince Rupert Gas Transmission: In July 2017, TRP was notified that PNW LNG would not be proceeding with their proposed LNG project and that Progress Energy (Progress) would be terminating their agreement with us for development of the PRGT project, effective August 10, 2017. In accordance with the terms of the agreement, all project costs incurred to advance the project, including carrying charges, are fully recoverable upon termination. As a result, TRP received a payment of $0.6 billion from Progress in October 2017.
  • Grand Rapids: In late August 2017, the Grand Rapids pipeline, jointly owned by TransCanada and PetroChina Canada Ltd., was placed in service. The 460 km (287 mile) pipeline plays a key role in connecting producing areas northwest of Fort McMurray, Alberta, to terminals in the Edmonton/Heartland region.
  • Northern Courier: Northern Courier, a 90 km (56 mile) pipeline which transports bitumen and diluent between the Fort Hills mine site and Suncor Energy’s terminal located north of Fort McMurray, Alberta, achieved commercial in-service on November 1, 2017.


U.S. natural gas pipelines

  • Rayne XPress: Rayne Xpress was placed in service November 2, 2017. This Columbia Gulf project will transport approximately 1.1 PJ/d (1.0 Bcf/d) of supply from an interconnect with the Leach XPress pipeline project, and another interconnect, to markets along the system and to the Gulf Coast.
  • The Gibraltar Midstream project, a 1,000 TJ/d (934 MMcf/d) dry gas header pipeline in southwest Pennsylvania, was placed in service November 1, 2017.
  • Leach XPress: The Leach XPress project is expected to have a US$100 million increase in its capital project cost due to delays caused by weather on the project’s construction schedule and the resulting increase in contractor costs. Leach XPress is expected to be placed in service in early January 2018.
  • Keystone XL: Given the passage of time since the Keystone XL Presidential Permit application was previously denied in November 2015, TRP is updating the shipping contracts and anticipates the core contract shipper group will be modified with the introduction of new shippers and reductions in volume commitments by other shippers. TRP anticipates commercial support for the project to be substantially similar to that which existed when they first applied for a Keystone XL pipeline permit. In July 2017, TRP launched an open season to solicit additional binding commitments from interested parties for transportation of crude oil on the Keystone Pipeline and for the Keystone XL pipeline project from Hardisty, Alberta to markets in Cushing, Oklahoma and the U.S. Gulf Coast. On September 6, 2017, TRP extended this open season to October 26, 2017 due to the impact caused by Hurricane Harvey to Houston, Texas and parts of the U.S. Gulf Coast. TRP is currently analyzing the results of the open season. In February 2017, TRP filed an application with the Nebraska Public Service Commission (PSC) seeking approval for the Keystone XL pipeline route through that state. In August 2017, the Nebraska PSC concluded the public hearing for the Keystone XL pipeline and final written submissions were submitted in September 2017. The Nebraska PSC will review all comments gathered from the public meetings, the written submissions and the hearing before making a final decision on the route permit which is expected by the end of November 2017.

Source: TransCanada Corporation


On October 24, 2017, TRP entered into an agreement to sell our Ontario Solar portfolio, comprised of eight facilities with a total generating capacity of 76 MWs, to Axium Infinity Solar LP for approximately $540 million. The sale is expected to close by the end of 2017, subject to certain regulatory and other approvals, and will include customary closing adjustments. The transaction is expected to result in an estimated gain of $130 million before tax ($100 million after tax) to be recognized upon closing.

Q&A from TRP Q3 conference call

Q: I have a question about the mainline. I don’t know if this will be maybe addressed at your upcoming Investor Day, but I’m just curious to know if you have any preliminary thoughts on how your long-term fixed price service is going, is it unfolding as expected and how might this influence in anyway perhaps, a resetting of tools for 2018 or post 2020 as contemplated potentially a couple years back might be required?

Executive President and Vice-President, Karl Johannson: Yeah, well, certainly. So the system isn’t fully contracted for the long period of time as other contracts follow up and they’ll get picked up, there will be capacity that comes back on the system. So there will be opportunity for people to buy more capacity  if they want to, just not this — not for a couple of months here as the beginning of the winter starts. But I guess the one part of the comment on that is that, yes, if you take a look at our entire infrastructure coming out of WCSB from NGTL to the mainline, end of volatility in prices on NGTL which says to me when the prices are volatile that people should have to — should find more export markets out of the WCSB.

We will be looking at potential expansions of the mainline. Right now, as you’re aware, we have some latent capacity in the mainline that all — that what we have to do is we have to finish the maintenance, we have to do the pressure maintenance, in line inspections, do the digs and we can bring that capacity back onto the mainline and that’s something we’re looking at right now as an option for our NGTL shippers who want to find the extra — export out of the WCSB. So short answer to your question is yes, we’re taking a look at that right now.

Q: I’ll just continue first with the mainline. Just given the high level of contracting that you are at for 2018, are you able to give a bit of a sense as to the ability for discretionary pricing revenues and where you might expect the achieved ROE and where the LTA might move through year end?

Karl Johannson: On the discretionary pricing revenues, we never actually really got a lot of revenues from discretionary pricing from the actual pricing of the surplus services itself. Discretionary prices acted I think as a — as an incentive for our customers to buy FT contracts. And also on the additional purchase of those FT contracts that we’re able to over perform our revenue requirement and earned this in the last couple years. As you’re probably aware, we’ve earned up to 11.5% which is the maximum what we can earn on the mainline.

My expectation going into next year, don’t forget, we’re going to reset all of our numbers, all of our billing terms for reset and then these higher revenues will come into our — will come into our incentive setting mechanisms. So, is it going to be really easy doing that 11.5%? Probably, no. I suspect as we go through the hearing and we reset all of our — all of our billing determinants, we’ll have a new target set for earning those discretionary revenues. So we’ll be debating with that with our customers and then potentially the regulator here coming in the year as to what the new billing determinants that we have to exceed and what their incentives will be.

So I think we’ve had a couple of good years, I think we earned those incentives, we’ve had a lot of value to the mainline and it’s my hope that we’ll come out of the hearing that we’ll have a reasonable incentive program back in place so that we can continue to be incented to over perform on the system.

Q: If I can then maybe turn to KXL. So on one hand, you’re still analyzing the open season results, but on the other hand, you said that you anticipate commercial support to be substantially similar to the initial projects. So is it fair to say based on what you’re seeing, in terms of the submissions that you pretty much have the volumes that you need, but that — obviously there is some conditions and other things that you need to work through?

Executive Vice-President and President, Liquid Pipelines, Paul Miller: Your comment is accurate. We do have various conditions attached to the interest and we are working through those to fully understand what they need, that will take us till the end of the month, but we’re quite encouraged by the results we have seen.

Q: Just want to turn over to the wind down of US power contracts and was wondering if you might build a share a bit more color with regards to the duration and ratability of kind of the cash flow there or should we just kind of expect volatility in results until those expire?

Karl Johannson: I could talk a little bit about kind of how we’re winding down what remains of the US Northeast. We still have a book there. When I look at kind of the earnings that we’re expecting out of the book and all the credit that we put for those earnings into the book, we’re looking at about CAD200 million, I think, of it. That will come back to us probably substantially all of it, 95% of it within next the years, of course weighted to the front end as we wind down that book. We are still in discussions trying to sell what remains of that book so maybe we can get it wound down a little early. Today, we have not concluded anything, but we still are in discussions, so it might come a little earlier than that if we’re able to sell all of it or pieces of it. So — but I would say, about 95% of it we’ll see before 2020.

Q: And then pivoting over to the financing side and list of number of options that you guys have there as far as how you approach it, it seems like with this — this most recent asset sale, you’re able to kind of get quite a nice price tag there. So just wondering what are the — are there other opportunities like that, and if you could just help prioritized for us, how you think about the different mechanisms, because if I look at TCP, I don’t think they could afford that type of evaluation assets, maybe you could just help me think through how these things stack up?

Executive Vice President and CFO, Don Marchand: It’s pretty high quality portfolio that we have left year, but we’re open minded in terms of further portfolio management here. The way we look at this couple of criteria hold versus market value, strategic positioning, and tax consequence is a big thing as well. If we sell something and pay a big cash tax bill, it makes it certainly less compelling to us. As we look at the stack here, top to bottom senior debt within the A grade credit metrics that we’re targeting here, probably room for another hybrid issue in the next 12 to 18 months here of some size to bring us to 14%, 15% of capital structure on a sustained basis there. The DRP plan will continue running through this and then we’ll use the ATM as necessary to balance off the credit metric targets for at the same time being cognizant of growing share count here. Pipe LP is businesses as usual, there’s been no fundamental change in how we view that vehicle, it remains a key financing alternative for us going forward.

It does have to compete with our alternate capital sources including asset sales here. So it will be fluid depending how ebbs and flows of everything from LP market conditions to business results, capital plans and alike. But what you’ve seen this year is probably a preview of how we’re going to do things going forward, we’ve done year-to-date, about 1.5 billion of senior debt, 3.5 billion on hybrids, we did an LP drop, we have some recoveries on PRGT, we had 800 million from the DRIP and just north of $5 billion of asset sales. So long way to way of saying it’s in all of the above strategy here, but everything is in play.

Q: I wanted to go back to the Keystone XL and you mentioned open season taking a month to analyze the bid. And then Nebraska approval process around the same time frame. And there is some questions about timing post that in terms of what you need to do. And I just wanted to check in end of November, is there anything left there on the sell side of things for you to make an FID decision?

Paul Miller: So we still have a lot of work to do on both of those events. We are still working through the bid conditions and that will take some time. We anticipate the Nebraska PSC approval here by the end of the month and it will take us some time to review the decision by the PSC. So I think we let those two events play out and that will give us greater visibility into our investment, the final investment decision.

Q: You mentioned some of the conditions imposed by shippers, you think, could be manageable. Are you able to share those conditions, are they mainly driven by external events that shippers have to manage or is it more negotiation without the structure of the contracts or the toll is being discussed at the moment?

Paul Miller: Yeah, so the way open season works is we provide the contract in the terms and conditions of the contract to the marketplace and that’s what the ship is bid into. So there is no movement on negotiations around that. It’s just unique situation for different shippers that they have to navigate and work with us to help navigate that. So it really is lot of it mechanical, logistical, but although a unique deep shipper.

Q: Regarding the sale of your Canadian Solar asset, how do you think about sort of the positioning of the Canadian business, power business relative to other opportunities in your portfolio?

Karl Johannson: We still have actually a pretty high quality product power within TransCanada. So I see the sales of the solar as an opportunity to recycle some capital which doesn’t mean we’re not going to recycle capital elsewhere, we’ve done both with our natural gas pipelines through the LP and we’ve done it through selling parts of the power business. But certainly, we have a big long-term commitment to the Bruce Power to refurbish that with our partners and we have a very large plant $1 billion, $1 billion plus plant in construction right now at Napanee. I would say that we look at our Canadian Power business as a key and core aspect of our business going forward. Doesn’t mean to saywe won’t recycle some other assets in it so over time, but I do believe it’s a still pretty high quality, high-quality business that we intend to hold on to and to grow over time.

President and CEO, Russ Girling: The power business remains very important part of our portfolio. What we sold here in the last few months is 2% of our portfolio or 76megawatts, it wasn’t a large component of our portfolio, we retained 6,200 megawatts of operating assets with the addition of Napanee here coming into 2018. That business will still be generating a $1 billion of EBITDA for us. Looking forward, we believe that the billions of dollars of new investment is required in the energy business or they have the power business going forward to both convert the system from a higher carbon intensity to a lower carbon intensity, that means more natural gas, more renewables and in our case, potentially more nucular in places like Ontario, but as well with transmission, distribution and as the system needs

to be build out to accommodate those new resources and to replace an aging infrastructure system. So we literally see billions of dollars of opportunities ahead and those opportunities will compete for a capital and in the future from our growing cash flow from our asset base. So it remains important to us, remain in the business, but as Karl said, as we’ve done with all of our businesses, we will look to surface value where possible, recycle that capital to higher returns if possible. And the lens at which we look at all of things is through a per-share return basis for shareholders and that’s the way it will continue to move forward, and it’s always a component of our portfolio for 20 plus years and will continue to be for the future.

Q: I just want to figure out how you guys are thinking about your revenue requirement. I know your tariffs, how they might change in the US pipelines under a lower corporate tax rate. And if you could just remind us also, sort of what happened with the revenue requirement in Canada for semi-regulated pipes 10 years ago when the corporate tax rate came down just to help us understand how things could change or may not change at all?

Executive Vice President and President, U.S. Natural Gas Pipelines, Stan Chapman: I’ll start and others could jump in to the extent necessary. With respect to rate cases, we do not have any immediate rate case obligations. The first two would be Columbia and ANR in ’19 and ’20. So absent the FERC — absent one, the tax plan being finalized as currently is and then two, absent FERC requiring pipelines to come in in some sort of a special proceeding to address rate reduction, those tax changes will just be incorporated in the future rate cases.

Q: Looking at maintenance capital for the quarter, can you explain why it went up from the previous quarter and is this kind of a the run rate to look at going forward?

Don Marchand: I’ll start and my colleagues want to jump in as well. There is a seasonality aspect to maintenance capital, as I mentioned in my remarks. It is concentrated, particularly in the US in months when gas flows are lower. So that will be a recurring phenomena there. But effectively, there’s two major trends here. One maintenance capital is, has been trending upward as the gas system gets tighter and tighter and more money is required for reliability.

The second trend, this is actually positive for us, because maintenance capital is — there’s always been the case in Canada, but increasingly so in the United States is recoverable, it’s de fact a growth capital that we will earn a return on. And so, yeah, I’ll give a little more granularity in Investor Day in terms of that, but those are the two major trends right now.

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