Good morning, ladies and gentlemen. Welcome to the TC Energy 2019 Third 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 morning, everyone. I'd like to welcome you to TC Energy's 2019 third quarter conference call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Chief Financial Officer; Tracy Robinson, President, Canadian Natural Gas Pipelines; Stan Chapman, U.S. Natural Gas Pipelines, President of that business unit; Paul Miller, President of Liquids Pipelines; Francois Poirier, Executive Vice President of Corporate Development and Strategy, and President, Power and Storage and Mexico; and Glenn Menuz, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website. It can be found in the Investors section under the heading Events and Presentations. Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Jaimie Harding following this call, and she would be happy to address your questions. In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please re-enter 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 related to some of our smaller operations, Duane and I'd 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 TC Energy with Canadian securities regulators and with the U.S. Securities Exchange Commission. Finally, during this presentation, we'll refer to measures such as comparable earnings; comparable earnings per share; comparable earnings before interest, taxes, depreciation and amortization, or comparable EBITDA; comparable funds generated from operations; and comparable distributable cash flow. These and certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TC Energy's operating performance, liquidity and its ability to generate funds to finance its operations. With that, I'll now turn the call over to Russ.

Thanks, David, and good morning everyone and thank you very much for joining us today. As highlighted in our quarterly report to shareholders, during the second quarter, our $100 billion portfolio of high quality, long-life energy infrastructure assets continued to profit from strong supply and demand fundamentals. Those market fundamentals have resulted in demand for our services with the majority of our infrastructure now running at full capacity under either rate regulated constructs or long-term firm contracts. The demand for access to the continental footprint that we have has led to our industry leading $30 billion capital expansion program, which is underpinned by contracts that are generally 20 years or longer or rate regulated constructs. We continue to realize the growth expected from this program as we placed approximately $8 billion of new long-term contracted and rate regulated assets into service during the first nine months of the year. As a result, despite the significant asset sales that have accelerated the strengthening of our balance sheet, comparable earnings of $1.04 per share for the three months ended September 30, 2019 increased 4% over the same period in 2018 while comparable funds generated from operations of approximately $1.8 billion, or 15% higher. Today, we are advancing $30 billion of secured projects with approximately 2.5 billion of those projects expected to be completed in the fourth quarter of this year. In addition, we're continues on more than $20 billion of projects under development, including Keystone XL and the refurbishment of another five reactors at Bruce Power as part of their long-term life extension program. We've also made significant progress in funding our capital program during the third quarter through various portfolio management activities. More specifically, we completed the partial monetization of our Northern Courier pipeline in Alberta as well as certain –…

Thanks, Russ, and good morning, everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares was $739 million or $0.79 per share in the third quarter of 2019 compared to $928 million or $1.02 per share for the same period in 2018. Third quarter 2019 results included an after-tax loss of $133 million at September 30, 2019 related to the Ontario natural gas-fired power plants held for sale and after-tax loss of $133 million related to the disposition of certain Columbia midstream assets in August, and an after-tax gain of $115 million related to the partial monetization of the Northern Courier pipeline in July. Third quarter 2018 results included after-tax income of $8 million related to our U.S. northeast power marketing contracts. These specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings. Excluding these specific items, comparable earnings of $970 million or $1.04 per share in third quarter of 2019 were $68 million or $0.04 per share higher year-over-year. This equates to a 4% increase on a per share basis despite significant assets sales as well as the dilutive impact of common shares issued under our dividend reinvestment plan in 2018 and 2019 and aftermarket program in 2018 all of which were in support of our growth and credit metrics. These positive results reflect continued progress placing new assets into service as well as operational strength and solid cash generation across all of our businesses. Turning to our business segment results on Slide 15. In the second quarter, comparable EBITDA from our five operating businesses was approximately $2.3 billion, representing a $288 million or 14% increase from 2018. Canadian Natural Gas Pipelines comparable EBITDA of $572 million was $50 million lower than for…

Thanks, Don. Just a reminder before I turn it 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'll turn it to the conference coordinator.

Thank you. [Operator Instructions] And the first question is from Linda Ezergailis with TD Securities.

Thank you. I'm wondering if you could just, maybe in advance of your Investor Day, give us a bit of a sneak peak in terms of where you're spending your business development time and where your focus is on opportunities on clearly the West Path Delivery announcement today is a significant new project. But I'm wondering, how dispersed your opportunities are geographically across your various business platforms and how might we think of kind of the cadence of spend beyond this year evolving?

Linda, I’ll maybe take a first shot at that and supplemented by our business unit heads here. But I think what you're seeing in the West Path expansion is similar to what we're seeing across the system is your demand for our services continues to be strong. As you know, it's difficult to build things in the current market environment, but demand for energy continues to grow, both domestically and in things like LNG export, and getting that product to market continues to grow. So we see production increases and demand for our system. So just by way of example, I guess, what I would first say is that I would expect our footprint to continue to generate these kinds of $500 million to $1.5 billion expansions in lots of pockets across the system. And maybe I'll just give you a few examples. Obviously, the demand for receipt capacity on the NGTL System continues to grow, and so we expect to see more capital to be spent in that area. As demand for receipt capacity grows, so does the demand for delivery capacity on our system. As you know, our Mainline has approximately 2 billion to 3 billion cubic feet a day of brownfield capacity that could be used to deliver that gas to market. So we see a potential expansion of that as well in Alberta as the – as we migrate from coal-fired generation to gas-fired generation. And then to other industrial users that have been moving to the province, both things like petrochemicals, fertilizers, gas to oil kind of conversions, again, demand for our systems and delivery capacity continues to grow. As you move downstream, down from that across the country, obviously, our view is that Marcellus/Utica will continue to grow as well in the longer term.…

Thank you. And maybe just specifically on your Liquids Pipelines, are you seeing some opportunities maybe to extend and pivot to more focused on exports there? Or any other incremental expansions you see there? And maybe more broadly, as you look at Keystone XL, some good progress made on the regulatory and legal front, but maybe you can also give us an update on your thoughts to approaching the financing and mitigating any sort of last-mile risk and when might all those work streams come together to be able to make an FID on that potential project?

Linda, its Paul here. I'll – on the first question around opportunities on export, et cetera, our focus is growing and seeking opportunities around our existing footprint right from Alberta all the way down to the U.S. Gulf Coast. And part of that effort sees us enhancing our connectivity, both at the supply side and the market side. And as we make the pipeline that much more attractive from a market access and supply access perspective, it helps us greatly with our contracting efforts. It also makes our spot capacity that much more attractive to shippers and to producers and to refiners. Specifically around the export, there is a lot of opportunities for us to connect to various export terminals in the U.S. And those export facilities is just another example on what makes the Keystone and the other pipelines that much more attractive for shippers to access because they can realize a net – a higher netback on their volumes. In regard to Keystone XL, we continue to go through a number of processes here, most on the legal and the regulatory side. On the recent events, in the last quarter, the Nebraska Supreme Court affirmed the decision by the Public Service Commission to approve the route through the state, which means we now have a fully permitted route for Keystone XL. There remains a challenge to the 2019 Presidential Permit. A hearing occurred last month, and we would anticipate a decision on that hearing later this month. The State Department issued the draft supplemental environmental impact statement in October. There are various open houses occurring for that statement, and we expect the final environmental impact statement to be issued here before year-end. With the issuance of the final environmental impact statement, the Bureau of Land Management and the Army Corps of Engineers will finalize their decisions. And I would anticipate we would see their decisions being issued sometime in Q1. We continue to work the various legal and the regulatory aspects of Keystone XL. As far as FID, we have to get these matters behind us. In regard to the last mile risk, and I'll defer to Don in a moment on the financing side, but in regard to the last mile risk, Keystone XL remains a very important pipeline for Canadian and U.S. producers. It's a very important pipeline for U.S. refiners and a very important pipeline for Canada and the United States. U.S. Gulf Coast is the largest refining center in the world, and it's significantly configured to run heavy crudes, like those produced here in Canada. And those refiners are seeing declining supplies from traditional producers. And they are looking and needing diversity of supply and Keystone XL will provide those supplies for them. And that's evidenced by the contracting of Keystone XL, which is both producers and U.S. refiners.

Linda, its Don here. With respect to the funding side, the key thing here are the work streams that Paul referred to as getting permitting finalized here. And we'll continue to work the costing and scheduling under various scenarios and as we progress towards an FID decision point. From a funding perspective, it remains all of the above. We'll look at everything from additional portfolio management. This project would probably bring some hybrid capacity, equity in some form, whether it be DRIP, ATM. But potentially joint venture partners here would be an important component of that. And then as we assess the overall risk/ return parameters here, if that equation is positive, we will proceed, including all the risk elements we've talked about here. So looking at it holistically, we just continue to push on all these streams right now to get to a point. And if the risk/return for TC Energy is appropriate, we'll move forward.

Thank you. I’ll jump back in the queue.

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

Hey, good morning. Russ, you mentioned the ability to – if you were able to secure a few these $500 million to say $1.5 billion type organic opportunities, that could, a, help you achieve your growth, but, b, you could fund that within your free cash flow. So I'm just wondering with the drip-off now, is this really a signal that you see and have achieved a self-funding model say outside of something like Keystone XL?

Yes, I think that's where we are today, Robert. Based on what we see in our portfolio coming at us over the next few years, we’re comfortable that we're back to the place where we want to be, which was the self-funding model where we're not issuing common equity to fund our day-to-day business activities. Don, do you want to comment?

Yes, Robert. Again, we look at everything on a per share basis here. So, turning our share count growth right now is important and a signal to the market that we can get to that soft planning model of really balancing credit metrics, we expect to be in the high fours here and debt-to-EBITDA basis, and 15% FFO to debt kind of range, which equates to our current credit ratings, maintaining payout ratios as we've historically done for the past couple of decades and then investing in these low-risk projects. One thing I would note is as we do add new projects to the hopper, the permitting process is such where there is not any material spend generally for a couple of years on these things. So we do get visibility out a couple of years now as to when those dollars are going to be required, and we are comfortable here turning the drip off and managing to balance all these things going forward.

Got it. Just to be clear, turning the drip off isn't just the – I don't need the cash right here right now, so, I don't want to hit the share count, but say six months to nine months down the road, either it comes back on our ATM just if you all you're doing is this $500 million to $1.5 billion type stuff?

Yes. If it's something larger transformational, we obviously reassess that, but what we see right now with our runway of projects, we think we're in that spot where we can live with an internally generated cash flow debt capacity within those credit metrics, and we still do have asset sale proceeds coming into the Ontario thermal plants in the first quarter of next year as well. The other thing we're looking at on Coastal GasLink is bringing in joint venture partners and project financing there. So when we look at this big picture wise, yes, we are comfortable that we can balance all of these things and we can deliver on these various initiatives and we can avoid share count growth in the absence of something very large that comes along.

I think the key, Robert, is as Don pointed out, as you see in the West Path Delivery expansion into 2023 expansion, as we bring in new projects today, that's the kind of time frames we're looking forward to get through the regulatory process. You you'll get through permitting and then you will actually order equipment and getting to construction, you are out there 2023, 2024, 2025, and I think that's the positive of our system right now is it the existing corridors are the places where you can actually get these things done where you have your roads already built and the relationships with landowners in those kinds of things. So existing corridors, it seems to be where folks want to build these things. The unfortunate part about that is that from the time we get the request of service to the time we actually put it in this request for service till commencement of operations is now a three-year to four-year process which is longer than it's been historically. But that's just the fact of the length of the regulatory process as we now see in front of us. So, that's the sort of the turnaround time frame from conception to the cash flow.

Yes, I'll just add one more final comment here is in terms of share count growth, we'll always look at asset sales as well. You've seen us do $6.4 billion this year and sizable amounts in the past few years as well. So that's the other counterbalance here where we'll always look at portfolio management versus increasing share count, as we would have per share metrics.

Got it. If I can just finish with the Mainline, I'm just wondering if you can outline the process as you see it unfolding for both the timeline as well as just anything you can talk about with the framework for post 2022?

Hey Robert, It's Tracy. We are continuing our dialog with customers, and I would say I'm optimistic that we will have an agreement of sorts and something to fall by late this year, early next year. We are completely aligned on – from a principal perspective of using our mainline assets to support the basin and to reduce kind of that distance between the basin and the Eastern markets. So the dialogs are going well. And as I said, I'd anticipate kind of later this year or earlier next year for us to come to a conclusion on that.

Okay. And do you see that as being a bit of a bridging agreement or something bigger or something that could be more transformational than what we've seen historically?

You know we've had through this process a lot of conversations on those more transformational items. I don't think we're going to get there on this one, but we need to get this agreement done to give us that path to understand really what this Mainline is capable of, and I do see those conversations coming back as we get through this particular process.

Great, thank you.

Thanks, Robert.

Thank you. The next question is from Jeremy Tonet from JPMorgan. Please go ahead.

Hi, good morning.

Good morning, Jeremy.

Just want to start off with a high level question as far as capital allocation process here. And in the press release, you talked about the potential for 8% to 10% distribution growth in 2021. And it seems like some in midstream overall kind of moderated that the growth that was going forward. And just wondering if you could refresh us as far as how you think about the rate of dividend growth versus other means of returning capital versus the right leverage level, how does that all come together, you know, decide that, what is the right level of dividend growth at this point?

I will take maybe a shot at the high level, Jeremy. I think our capital allocation philosophy has remained unchanged for 20-or-so years, and at its core, it's to pay, first of all, you focus on the balance sheet making sure that we maintain the strongest balance sheet in our sector and that's the first sort of priority with respect to capital allocation. Secondly, return of capital to shareholders via the dividend and historically that number has been about 40% of cash flow and approximately 80% of earnings plus or minus a bit, and taking 60% of it and reinvesting it in our core businesses to the extent that there are good opportunities on a risk-adjusted basis that we think will add shareholder value to the extent that those opportunities aren't available. Our philosophy that has been return of capital to our shareholders. And then within there, how do we allocate capital between businesses and geographies and how compete for capital is really again unchanged as we try to high grade the projects across our system and that to the extent that we have more projects than our free cash flow. And then we look next to asset sales and then portfolio management to augment those. Most of the assets we have in our portfolio are solid good cash flowing assets, but to the extent that we see better platforms for future growth. So a good example of that is when we move to acquire Columbia and we saw the opportunity to exit the northeast power business and redeploy that capital back into a, what we saw was a longer-term growth set of assets in the Appalachian region, the Columbia Gas System sat on top of the fastest and lowest cost basin in North America, and we saw that as…

Yes. Jeremy, its Don here. We'll give you more color and granularity at Investor Day, but the next decade, looking, shaping up a lot like the last couple of decades, and don't expect any real change in our risk preferences, our payouts, our philosophy, our keep-it-simple methodology here; I would just say that we're probably more utility-like than midstream-like in our thought process here. Earnings matter, we are not 95% payout on cash flow kind of guys here, so watch for more of the same.

That makes sense. And then maybe just building off on some of the comments there, with regards to transformational acquisition opportunities, seems like TRP has historically waited until there was stress in the market to be opportunistic there. Just wondering in the current marketplace as it is right now, do you see anything that fits your parameters as far as risk in return out there or any other comments you could share?

I would say that the current time and we, there is some significant assets that we have it, we continue to monitor them as we always do. Nothing in that sort of fits what I'll call the risk return, kind of parameters, but there are very, very solid assets out there in the marketplace right now that we would see is very complementary to our business. And as you pointed out, our approach has always been one of, being financially disciplined. When those opportunities present themselves in a way and in an economic form, that adds value to our shareholders, then we're willing to act. And by doing that, I guess our view is that capital market support is when we want to go through those kinds of things.

Great, thanks for taking my questions.

Thanks, Jeremy.

Thank you. The next question is from Ben Pham from BMO. Please go ahead.

Okay. Thanks, good morning. My first question maybe for Paul, I'm wondering just more of a near-term question, Q4 2019 just wondering what the direction of outlook is there on Keystone? How do you think this bill could impact the results and maybe just a comment on liquids marketing?

Okay, Ben. I'll start with the impact of the spill first, and then I'll speak to the liquids marketing. And I might even touch a little bit on Marketlink, the pipe on the southern end of our system. On the spill, our teams are on site, and we have secured the site and contained the spill. At this time, we don't yet know the cause of the incident, but we will conduct a third-party assessment and learn the cause and make any necessary improvements to our integrity and maintenance programs. For now, it's a little early to determine any financial impact. We will be providing updates on our website as we learn more and hope to give you a little more visibility when we get to Investor Day. On marketing, we had a good quarter on our marketing operations. We saw some good volume, good margins in Q3, probably up about a couple cents from Q2. And this higher result was a result of a number of factors. Marketing competes for capacity on various pipelines, those pipelines which are offering good value because of various market differentials. And they were able to secure capacity on some of these pipelines and realize on that differential. We also saw some Brent/TI volatility, both at the beginning of the quarter and towards the end of the quarter, and captured some of that value. And the performance, I think, is just a reflection of continued evolution of our people and our programs. I think Q4 will be softer. I think you'll see Q4 migrating back towards levels we saw in Q1 and Q2, but still $0.01 to $0.02 lower. And then going forward 2020, I think there's still – there's going to be some continued variability in the market differentials. I think you're going to see these differentials range trade around 2020 as we look through the new pipelines coming into the Permian, for example; and various line-fill activities which are occurring now, which is also having an impact on our Marketlink operations. We had a softer quarter but still strong volumes supported by our take-or-pay contracts. And as we've increased capacity over 2018 to 2019, we have been able to attract additional contracts to that system. And so these contracts have, and they will continue to, provide stable cash flow. Where we saw some softness in Q3 was in our spot volume. But when I take a look at, for example Q4, the net impact in this quarter of the higher contracts and the lower spot volume was under $0.02 versus Q2. And even though we will we'll see continued variability, I think, in the entire Pad 3 market, again as these new Permian pipelines come into service and, call it, the line fill continue, I think Q4 will see further softening but will be supported by this higher level of contracts we've been able to secure over the last – on our Marketlink system.

Okay, thanks for that. And then on – maybe a second one for Don on the DRIP. I guess I'm wondering just the timing of it. How important was – or is the Coastal sale is in that analysis? Because I guess you could have waited a month or so to get some visibility. I think that's 75% sale or 50% or a little bit less. I mean how – like how should we be thinking about that?

First, with respect to the JV process, we remain quite encouraged by the quality and the quantity of participation in that. So it's not a binary call on whether and where that's at. What we're looking at is more bigger-picture. It’s we’ve got $8 billion of assets that have come into service. We've got $6.4 billion of asset sales this year. We believe our credit metrics are in line here. So it's a data point, but I wouldn't say it's the main driver of the decision to turn the DRIP off right now.

Okay, thanks. Thanks everybody.

Thanks, Ben.

Thank you. Your next question is from Robert Catellier from CIBC Capital Markets. Please go ahead.

Hi, thank you. There was a lot of good commentary on your capital spending outlook. I just wanted to double check, confirm that I've heard the message. But it sounded like there's enough projects for you in the existing corridors to account for your free cash flow generation. Is that correct?

That's what we're seeing right now. I mean obviously, it all hasn't materialized yet. But based on conversations with customers and inbound demand, it appears that we have a significant pipeline of new organic growth opportunities that will extend this out the next number of years here.

Okay. And then to the extent that your capital spending includes projects that are outside the existing corridors or maybe the regulatory process is a little bit more challenging, is there an understanding in the industry that there needs to be a more balanced risk-sharing mechanism given how difficult it is to get these project approves, particularly on the regulatory side?

I think you’ve seen those kind of constructs come forward on new projects. I mean the West Coast, Canadian LNG projects are a great example of the kind of constructs that are necessary to get through new corridors and to build capacity to new markets. It's – those are hard work and heavy lifting, and it requires capacity of many sort of creditworthy and technically capable parties to actually make them happen. But those are examples of things that you can see can come together and the kinds of constructs that are put together to make them happen. Similarly, on our pipeline through to Mexico, those are transformational for our company, but also for continental flow of commodities and natural gas in particular, and the kinds of constructs that you have to put together to make those work. So we think they're still out there. But obviously, the marketplace, to your question, is aware of the risks and how to mitigate and manage those risks as a partnership as opposed to the kind of approaches we might have had historically.

Okay. And then my – just my last question here. Are you in a position to quantify the potential financial impact from the Columbia rate settlement, if it's approved as envisioned?

Yes, this is Stan. The Columbia Gulf settlement is actually going to be filed today. Think of it as relatively straightforward. It’s a black box settlement. What you're going to see is a big nameplate increase in terms of max rates increasing by about 20%. But keep in mind, particularly on the Columbia Gulf System, virtually all of our revenues are covered by negotiated or fixed-rate contracts, so you're not necessarily going to see a big revenue bump. I would just say that the settlement was very much consistent with what we thought it was going to be: two-year moratorium, seven-year comeback, very straightforward.

Okay, thank you.

Thanks, Robert.

Thank you. Your next question is from Praneeth Satish from Wells Fargo. Please go ahead.

Hi, good afternoon. I am just wondering what kind of demand for gas you're seeing in the Pacific Northwest region. Is the West Path delivery project and GTN expansion, is that servicing new demand or just kind of displacing other pipelines in the region?

This is Stan. I could take a start at that. Think of our GTN XPress expansion as a 250,000 a day, going all the way down to Malin and is ultimately going to serve markets off of the PG&E system. So I think you'll see a fair amount of gas-on-gas competition, displacing gas that otherwise would come across from the Rockies, but great opportunity for us. It's an in-corridor expansion. It's a compression expansion. We're going to take out some old, inefficient depression, put in some new units that is going to increase reliability. It’s going to decrease our greenhouse gas footprint and provide the expansion capacity that the market needs.

Praneeth, I will just add a little bit to that. This is a combination of a pull from the market that Stan is talking about and a push from producers. And I think tellingly its three-year contract terms on average. So it's a pretty compelling statement about the attractiveness of that market.

Got it. And then on Coastal GasLink, can you just provide more details on what caused the cost increase? And then I guess what's your confidence level that cost won't continue to creep higher?

This $400 million is a combination of two things that you heard Russ mention. One is scope. So we've got incremental meter station and a few other things. And the other is raw quantities and water crossings. There was this section, if you will, recall of this pie path that we couldn't access to some restrictions until this year, until we had FID and dealt with some of those issues. And so as we've been into that terrain now, the first pass suggested that there is more rock issues than we had in our estimates. And so the – this adjustment reflects that as well as a greater number of water crossings across the full pipe path. So this is an estimate at this point in time and we're going to be working very hard to mitigate that, but we have now been on the pipe path in its entirety and this is our best estimate at this time.

Okay, got it. Thank you.

Thanks Praneeth.

The next question is from Rob Hope from Scotiabank. Please go ahead.

Good morning, everyone. Just hoping we could build on the comments on your crude export comments earlier on. If we pivot that over to gas, would you have any interest in potentially moving past just accessing the Gulf Coast with your gas network to potentially even holding some LNG capacity?

I think under the right construct and obviously that's a business that probably has a similar contracting profile, credit profile to our existing business and under those scenarios which certainly have that capacity, we've looked at those kinds of things in the past and we'll continue to look at them in the future. It's a matter of having the right construct and the fit with our existing systems. So certainly something we would look at.

All right. And then just as a follow-up to that. Would you look to do it in a kind of a smaller byte size manner or something larger there?

Again, we look for the right opportunity. We have a large platform, we work with a number of folks as well that we are delivering natural gas to. And so we have conversations with folks at all sort of ends of the spectrum of a big and small. The key for us is fit, financial stability, growth potential and those kinds of things, and like the rest of our business, those are the kind of parameters it will have to compete for capital. Obviously, as we pointed out here earlier, there is a large demand for expansion along our systems. So there is a good call on capital today and new projects have to compete for capital within the company.

Thank you.

Thanks, Rob.

The next question is from Matt Taylor from Tudor Pickering Holt. Please go ahead.

Hey, thanks for taking my questions here. Just can you provide an update on conversations with customers in the Northeast as CapEx budgets are coming down, growth has been revised lower, just curious if there has been any rate concessions there and kind of what's your expected impact to non-contracted earnings and future growth plans there?

So I think what you're getting at is the health of producers overall, I would just say that the big picture-wise, we really don't have any significant concerns. When you look at our top 10 producer customers, for example, they are all flowing their contracts at very high load factors, which to me says that they're getting proper value out of their capacity and they all have a very strong acreage, which means that we believe that the molecules are in the ground are going to be produced for some time to come.

And have you made any rate concessions there in the Northeast?

No, we haven't.

And then just going back to AECO there, it looks like there's been some life breezed back into AECO, can you maybe talk through if you think this will last into the summer months and then maybe just how this impacts discussions if you're seeing any impact of discussions on adding more mainline capacity as producers are seeing better pricing?

AECO has jumped in the last months, and there's all kinds of things that impact AECO pricing. And you know the summer is normally a very difficult time for AECO because 1.5 Bcf or 2 Bcf of market disappear in the Alberta area, and there is no place for that production to go. We have had difficulty in getting into storage as our system has become completely contracted on a firm basis, has made storage access a little bit difficult. We did have, we did reach in general agreement with industry this summer that we should, that we would agree to kind of introduce a temporary variation in how we restrict, how we prioritize services on the NGTL system during the summer months. And while we are accessing the pipe for maintenance or capital expansion purposes and that just meaning that for a temporary period of time, we would prioritize interruptible service over our firm services to create that access to storage. So we think that that's probably had some of this impact, it's is very positive. We are now finished with that and we're going into November and into the winter season. I think we're well positioned for that. And we're hopeful that the demand this winter will support our continued strength in AECO pricing. Without a doubt, we are seeing increased demand for the mainline. In fact, there is some capacity on the Mainline right now because the bottleneck is the NGTL capacity to get on to the Mainline until 2021 when we're finished with that expansion, but post 2021, most of the available capacity on the mainline is now being contracted. And so we are working with our customers on an expansion potentially if the main line in the future to facilitate even a greater access for the basins volumes into the eastern markets. But that will be a dialog we will have over the course of the next year or so.

And Matt, just to add on to that is that we will work very hard in all of our basins to optimize our systems to be able to move as much gas as we can. And in doing that, hopefully improving the economics of our upstream producers. Our focus has been longer term, and if you can take a look of what we're doing longer term, we believe in the long-term economics of the basin. The gas in the Western Sedimentary Basin and Appalachia, we believe is the low-cost gas, which will compete extremely well in the marketplace over the long haul. With all the expansions we have under way on NGTL right now, we're increasing the delivery capacity by about 3.5 billion cubic feet a day over the time frame that Tracy mentioned. And that's going south and it's going East and it's going West and we'll continue to look at that on top of that with the coastal gasoline project, we're going to add another 2 billion cubic feet a day delivery capacity, so 5 billion cubic feet a day or so of delivery capacity coming out of the basin. And it's underpinned by more of the market fundamentals in the long term that liquids rich gas coming out of the major plays in Western Canada will compete well. And as we pointed out, as Stan pointed out, if you think about things like Pacific Northwest in California, there isn't that much new incremental demand, but obviously Canadian gas is competing for market share. And with 30-year contracts, it appears that there is great confidence that the basin will continue to grow into that 3.5 billion cubic feet a day of capacity that we made available. And if we can make available anymore, I think Canadian gas will compete very well into all of those marketplaces.

Just to clarify, Tracy, when you say Mainline contract, did you need to add more or invest more NGTL dollars to add more mainline capacity or do you already have enough NGTL egress to get them?

Once we finish, as you know, Matt, we have a considerable expansion program under way on the NGTL system and a big chunk of that comes into service in 2021, which should give us enough access of NGTL into the Mainline to think about how we get more volumes down that system.

Great, that's helpful. Thank you.

Thanks Matt.

Thank you. The next question is from Shneur Gershuni from UBS, please go ahead.

Good morning. This is [indiscernible] calling in for Shneur Gershuni. How confident is management with the progress on Keystone XL FID now versus the last earnings call and how goes with the recent development? And the US administration changes, do you feel there are protections in place?

Hi, it's Paul Miller here. We progressed Keystone XL over the last quarter. When you look back, going into Q3, there was uncertainty around the route in Nebraska, there was uncertainty around the issuance for example of the Draft Supplemental Environmental Impact Statement. Since then the Nebraska Supreme Court has affirmed the Public Service Commission's approval of the well. So we are fully approved in the state and all the jurisdictions in which the pipeline will be cited. We have received the draft environmental impact statement, the review of that environmental impact statement is under way and we anticipate getting it finalized here by year-end and then we would look to see the Bureau of Land Management and the Army Corps issue their decisions in Q1. Ultimately, our comfort level is going to revolve around getting these various legal and regulatory proceedings behind us before we commit to move forward on FID. I'm sorry. And then the second part of your – I think was in regard to last mile, we had some change in administration and our focus is managing the legal, the regulatory and project management activities. Keystone XL remains a very important pipeline for the industry and a very important pipeline for Canada and the United States. It is fully contracted by both Canadian and US interest, and as a result, I think that the merits of the pipeline are well established and well understood and we will continue to focus on the legal, the regulatory and the project management activities.

Thanks [indiscernible].

Thank you. The next question is from Patrick Kenny from National Bank Financial. Please go ahead.

Hey, good morning. Just with the NGTL expansion, was curious to get your thoughts on dealing with the new CER relative to the NEB, if we should be expecting any material change in the regulatory process?

The West Path expansion, Patrick, is one that will fall under the new CR process. Our current – all of the rest of the NGTL expansion that we have under way will follow as you know, under the old kind of NEB rules and processes. So we've been working around what you expect on this and we're optimistic in fact. So this falls underneath the level of an expansion that would trigger the Impact Assessment agency review and it is an expansion of two separate assets. So we believe that we are optimistic that this process should run generally in line with the timeline that we would have seen under the former NEB rules and procedures. Having said that, it's new to us. We are working through it, it's new to all of our stakeholders who are also working through it. So we will have to see how this goes.

Okay, great. Appreciate that. And then just on the Alberta power market here, was interested to see you guys sign an agreement for renewable power. I was just curious maybe a little bit of background on that and then also just your overall view with respect to your remaining Alberta power assets and the market in general?

Patrick, it's Francois. I'll be happy to take that question. That transaction obviously was very modest size, but complementary to our existing trading business. It was an opportunity to acquire attractively priced energy and remarket it. And really capital-light way for us to invest in the solar resource in Alberta. We like the Alberta market, we supported the reaffirmation of the energy-only market. We believe in the fundamental merits of all of our Cogencis facilities in Alberta and we would look at for opportunities to invest more capital along similar constructive, the opportunity presents itself.

Got it. Thanks everybody.

Thanks, Pat.

Thank you. Ladies and gentlemen, this concludes the question-and-answer session. If there are any further questions, please contact TC Energy Investor Relations. I will now turn the call back over to Mr. Moneta. Please go ahead.

Okay, thanks very much. We very much appreciate your interest in TC Energy, and we look forward to speaking to you again soon. Bye for now.

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