Pembina Pipeline Corporation (PBA) Q4 2019 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by, and welcome to the Pembina Pipeline Corporation’s Fourth Quarter Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions] I would now like to hand the conference over to your speaker today, Scott Burrows, Senior Vice President and Chief Financial Officer. Please go ahead.

Thank you, Marcella. Good morning, everyone, and welcome to Pembina’s conference call and webcast to review highlights from the fourth quarter and full year 2019. I’m Scott Burrows, Senior Vice President and Chief Financial Officer. On the call with me today are Mick Dilger, President and Chief Executive Officer; Jason Wiun, Senior Vice President and Chief Operating Officer, Pipelines; Jaret Sprott, Senior Vice President and Chief Operating Officer, Facilities; and Stu Taylor, Senior Vice President, Marketing & New Ventures and Corporate Development Officer. Before we start, I’d like to remind you that some of the comments made today may be forward-looking in nature and are based on Pembina’s current expectations, estimates, judgments and projections. Forward-looking statements we may express or imply today are subject to risks and uncertainties, which could cause actual results to differ materially from expectations. Further, some of the information provided refers to non-GAAP measures. To learn more about these forward-looking statements and non-GAAP measures, please see the company’s various financial reports, which are available at pembina.com and on both SEDAR and EDGAR. Pembina once again delivered strong quarterly financial and operational performance as we continue to benefit from the ongoing growth in our business, both organically and through acquisitions. While earnings of $145 million during the quarter were a 61% decrease when compared to the same period last year, this was largely due to a onetime noncash after-tax impairment charge of $220 million on Pembina’s investment in Ruby Pipeline. We continue to benefit from the cumulative preferred interest in Ruby, which entitles Pembina to the first U.S $91 million per year of distributable cash flow from that asset. The impairment charge was a result of an assessment triggered by upcoming contract expirations in a business environment in the Rockies space and that remains challenged. Prior to the impairment, earnings would have been flat quarter-over-quarter. Adjusted EBITDA in the quarter was $787 million, a 10% increase compared to the same period last year. This increase was due to new assets placed into service and pipelines and facilities and the adoption of IFRS 16. While only contributing for half a month, the fourth quarter also was positively impacted by the contribution from new assets acquired in the Kinder acquisition. We also benefited from higher margins in our crude marketing business, although, this was offset somewhat by lower propane margins impacting Aux Sable and the narrower Chicago-AECO natural gas differential impacting both Alliance Pipeline Aux Sable. The strong fourth quarter contributed to record financial results for the full year. On an annual basis, 2019 earnings of $1.5 billion were 17% higher than 2018, adjusted EBITDA of $3.06 billion was 8% higher than 2018 and slightly exceeding the upper end of our guidance range, and adjusted cash flow from operations per share was 2% higher than 2018 at $4.36 per share. All three metrics set new records for Pembina. We have delivered these record results while remaining firmly within our financial guardrails. In 2019, fee-based cash flow comprised approximately 85% of adjusted EBITDA for the year. Our fee-based cash flow more than covered our annual dividend payment with a fee-for-service payout ratio of 73%. Our dividend continues to be fully funded without relying on our commodity exposed business. Roughly 79% of our credit exposure at year-end was with investment-grade and secured counterparties, and we remained – and we maintained our strong BBB credit rating with the year-end ratio of proportionally consolidated debt-to-adjusted-EBITDA of approximately four times. It’s worth noting that this ratio includes the incremental debt from Kinder transaction but only 16 days of EBITDA contribution. In 2019, we placed in excess of $600 million of projects safely and successfully into service, including Duvernay II, Burstall Ethane Storage as well as other infrastructure at our Redwater Complex. Furthermore, we are excited about the $1.2 billion of additional fee based projects which are expected to enter service in 2020, including the Phase VI expansion of the Peace pipeline system, the first phase of the Prince Rupert Terminal, the height development project as well as Duvernay 3. With these projects coming online in conjunction with the contributions from the Kinder Morgan assets we continue to estimate generating 2020 adjusted EBITDA of approximately $3.25 billion to $3.55 billion. The midpoint of this range would equate to an 11% increase over 2019. We continue to expect a 2020 capital program of $2.3 billion, including spending at our joint venture entities. Now I will turn things over to Mick for an update on some of our key growth projects and business development activities.

Thanks, Scott. Good morning, everyone. In reviewing 2019, the most single – significant single event was clearly the $4.25 billion acquisition of Kinder Morgan. While early days, the integration is going well. As we said at the time of the announcement, we see meaningful financial upside available from a portfolio of small capital projects in addition to the integration of acquired assets. Over the next five years, we estimate realizing additional annual adjusted EBITDA of $100 million with only modest capital spending. I’m confident time will show, this was a solid use of Pembina’s capital. Early indications from customers for both ocean and the tanks are promising. Shifting to our secured portfolio of projects. We currently have $2.9 billion of projects under construction, which in aggregate are trending on budget. The staged development of Peace Pipeline systems remains a significant component of that program. In addition to Phase VI, VII and VIII expansions, the recently approved first stage of Phase IX expansion is also underway. Phase IX completes our multiyear effort to provide separate pipelines for each of our four products. Full product segregation is a significant accomplishment that will drive operational and capital efficiencies, strengthen our competitive advantage, and ultimately, benefit our customers. In addition, we continue to have the ability through a second stage of Phase IX expansion to add approximately 200,000 barrels per day of capacity through the addition of pump stations in the Fox Creek two, Namao corridor and we began to evaluate what we call Phase X, an optimization project that could create up to an incremental 100,000 barrels per day. So in total with minimal capital outlay, Pembina could quickly and cost-effectively add 300,000 barrels per day of capacity to support additional customer growth. As we execute our strategy of accessing global markets, we continue to progress our PDH/PP facility. We are pleased to announce a lump sum EPC contract relating to the construction of the PDH plant on January 7 of this year. With this contract, we have locked in approximately 60% of the cost of the PDH/PP facility thus far reflecting our disciplined and prudent approach to capital spending. We expect this percentage to increase as the project evolves to meet our stated objective of two thirds locked down. In addition to advancing our petrochemical facility, we are also excited about our Prince Rupert propane export terminal. This project is important as it represents our first export facility. Demand for propane capacity has been significant and we have as a result recently decided to proceed with an expansion increasing capacity to approximately 40,000 barrels per day. Also, I believe Pembina’s existing assets footprint is poised to benefit from the development of LNG project to be located along the North American West Coast. We have the opportunity to benefit our customers, the province, and indeed the country while playing an important role in reducing GHG emissions by displacing coal demand abroad. We want to be in the LNG business and we are currently working on several opportunities including locations in Northeast BC as well as continuing to progress our proposed Jordan Cove project. In 2019, we are pleased to share our progress in developing two new stands. For Pembina, a stand is something you’re going to do even if you don’t know exactly how are you going to do it yet. In other words, we’re not there yet, but we are continuing to get to work towards a more definitive target. Carbon stands – the Pembina’s Carbon Stand states we are committed to reducing the GHG emission intensity in each of the businesses that we operate. While the diversity inclusion stand states we are committed to diversity, equal opportunity and ensuring that our employees have the ability to thrive in an inclusive environment. In closing this year, in fact, this decade, Pembina has delivered significant growth while enhancing our diversification and strengthening our overall business for the benefit of all stakeholders. We have thrived despite the financial crisis, despite low and volatile commodity prices, regulatory and political uncertainty, as well as uncertain capital markets. We have delivered a compound annual growth rate over the decade of approximately 12% EBITDA per share, 11% adjusted cash flow per share and 9% earnings per share. Over the 10 year period, shareholders received the total compound annual return of 17% per year. As always, we strive to continue this trend. I’d once again like to thank all of our stakeholders for their support. We are entering a new decade with significant momentum, abundant growth opportunities and we look forward to the year ahead. With that, we’ll wrap things up. Operator, please go ahead and open the lines for questions.

Your first question comes from the line of Matt Taylor from Tudor, Pickering. Your line is open.

Yes. Hey. Thanks for taking my questions here guys. Just wanted to start there on Ruby. It seems like the writing has been on the wall there for a while, so I just assume this is a formalization of that? But be helpful if you could just speak to the contracts that you do have after expiry? Do they generate enough cash flow there to satisfy your pref interest? And then what are you assuming, you’ll be able to recontract even before Jordan Cove may enter service?

Hi Matt, this is Jason. So the contracts roll off and some of them roll off in 2021 and then we have other contracts that carry on beyond that. So we believe that there is demand to supply the California power market in terms of having ongoing demand there. And there is also – there is an opportunity to continue to supply that Malin hub. So we believe there is going to be an opportunity to roll those contracts over. There is also short-term opportunities that have presented themselves. So if you think when the – this factored incident happened, the Ruby Pipeline was able to step into that void. And that’s why we had higher volumes in the fourth quarter of 2019. So we think that there is going to be beyond just specific long-term contracts, we also think there is going to be in term opportunities for that pipeline to supply some void, including as the California Energy market sort of turns to more green power, there will be opportunities to provide the sort of the power that backs up the green power for the spot generation when there is no power availability through sun or wind.

Great. Thanks, Jason. And is there enough base level contracting there to at least cover the press interest in the interim?

No.

Great. Thanks Scott. And then on; Jordan Cove…

Hey, Matt. Let me just clarify. For 2020 and 2021, yes. Post 2021 the short answer is no. But as Jason pointed out they are actively working on recontracting.

Thanks for that. Scott. And then just moving over to Jordan Cove. When do you expect for to review that decision? Obviously there is a few balls in the air. And can you give us an update on discussions there just more broadly with Oregon because, you walked away from a project there before to build the LPG in Canada and just sort of wondering, what it would take for you to focus? You had mentioned in your opening remarks there about BC LNG opportunity. So just wondering if we might see something similar here where you might focus your attention in BC?

Matt, it’s Stu Taylor. So we are continuing to await the FERC. We were expecting a decision to come out on February 13, now it’s delayed to the 20th. And then a decision was further delayed. We’ve not got an exact time when the FERC decision. The next FERC commission meeting is I believe March 20. We are expecting a decision at the latest by that point, we may get it earlier, but at this point, we’re continuing to wait. There has been nothing published by FERC. As far as the Oregon, we continue to work through the regulatory process with the regulators in Oregon. We continue to provide information and answer questions and work through all of the requirements of which will be required for the project. So we’re continuing to progress as best we can and continue to move things forward and are looking forward to making progress on receiving some of those permits. Our BC initiative is with the progress that’s been made in British Columbia, we see an opportunity to move additional projects additional opportunities for LNG to go off the West Coast to British Columbia. So we are progressing all of our LNG projects including Jordan Cove and looking to come forward with the project on the BC side as quickly as we can through a lot of hard work by a number of people.

Great. Thanks. That’s it from me. Thanks for taking my questions.

Your next question comes from the line of Jeremy Tonet from JPMorgan. Your line is open.

Hi, good morning. Just want to touch base on Alliance here. If you could expand a little bit more on what were some of the drivers for I guess the volumes coming in a bit there as far as the differentials there, and I guess what’s your outlook going forward here? Do you expect that to repeat anything as far as demand for Bakken takeaway there just everything on Alliance that you could share would be great?

Sure. Hey, Jeremy, it’s Jason. So on – in the near term obviously the spreads have come in a little bit between Chicago and Alberta. So we are seeing a little bit less demand for IT volume on that pipeline at the moment. Historically, Chicago market always been the premium market, and we think this is just a temporary situation in terms of the weather conditions and some of the things like that have happened in the fourth quarter and first quarter. So we expect, as we go into summer and next fall things will go back to the way they normally are. In terms of the Bakken, we kind of started looking at the Bakken a bit differently. We were trying to go with a large expansion and try to lock up volumes and we realized it’s better to take a sort of staged approach there. So we are progressing our discussions with a number of the producers in the area and looking at sort of unique offerings that we can provide on Alliance in the near term. One of the things that we’ve noticed is with the Cochin Pipeline and the Vantage Pipeline, we’re now starting to see that the suite of assets, including our Palermo Gas processing facility with Aux Sable there. We’re starting to be able to sort of package together a fairly good midstream opportunity set. So, we’re getting a bit more interest in terms of some of the value chain opportunities of the Pembina store that we typically talk about in Alberta. So, we do think that we’re gaining traction there. The other thing we’re looking at to is some of the flaring that’s going on within North Dakota and seeing what we can do to help out with some of the flaring there. So we think there’s an opportunity to capture a lot of gas that’s being flared at the moment.

That’s helpful. Thanks and want to just turn over to the BC frac something that you guys had talked about the possibility in the past, and I’m wondering if you could update us there as far as what your thoughts on the potential need for that service and ability to kind of do that at some point in the future?

Hi, Jeremy. Jaret here. So on the need side, we see that the proxy can continue to tighten up here in Western Canada as the condensate demand continues to back out some of the imports, NGLs obviously come with that. So we see that there is going to be requirement for incremental fracs. What we’re evaluating right now, we continue to evaluate is the location of that, obviously we have a significant infrastructure in and around Redwater area, unit train capabilities, underground storage, etc. And we’re weighing that against building up in Northeast BC, where we don’t have some of those things, but you are closer to some of the West Coast market. So evaluating customer feedback, evaluating what – how Pembina can maximize our infrastructure while providing our customers with the highest reliability and the lowest cost option. So no update on that right now, just we continue to do the due diligence on that.

That’s helpful. I’ll stop there. Thank you.

Your next question comes from the line of Linda Ezergailis from TD Securities. Your line is open.

A bit of a runway to go in terms of progressing on your PDH project. But I’m wondering if you could just give us a sense of how the commercial discussions are evolving. Have you made any specific progress recently? Are these quantity and type of counterparties shifting a little bit? Do you have any line of sight in terms of when you might get to your targets. And any other context that you’re able to share, realizing that there is some commercial sensitivities would be appreciated?

Linda, it’s Stu. We continue to work through the commercial side, we are in contact with a number of parties to continue to increase our fee-for-service component. We’re looking at the creditworthiness of those counterparties, making sure there is a right partner on a go-forward basis for us. We believe the PDH/PP market, the ability to access that market will be a valuable commodity, a valuable asset in the future. And we think it just adds to the Pembina value chain and we can take customers from wellhead through plant through pipe and put their product into a local market at very low cost. So we’re – we continue to have conversations, we believe, it’s something that will be valuable. We’ve not at this point added any new contracts to that file, but we remain in conversations with a number of parties.

That’s helpful context. And maybe shifting to your gathering and processing business. Can you give us any sense of recent discussions with your customers in terms of the outlook for their activity levels and what that might mean for your operations? Are there any requests for some rate release may be from them in terms of potentially trading lower near term rates for longer-term commitments or anything of that nature?

Hi, Linda. It’s Jaret. Yes. So on the processing side, our gas processing business, under the traditional business outside of Veresen Midstream is highly contracted to date with fairly lengthy contracts, and we have fairly high utilization in those areas. We do have some exposure, about 15% of our – approximately 15% of our total processing business is exposed to cretaceous reserves, which I would say are struggling with a little bit today and in today’s commodity prices. On November 27 of last year, we did see one of our customers who had some small volumes not through our gas processing business but through our pipeline and fractionation business go into CCAA. So that did impact a little bit immaterial, albeit in the fourth quarter of last year and we just continue to work with that customer on providing alternative arrangements. So Pembina can still provide them the service that they need.

I mean that – those are all considered in our guidance Linda. So nothing that would remotely take us out of guidance. We’re always across our businesses looking to, we call it blend and extend, how we think we’d rather take a little lower toll and get a little longer firm. So that’s, that’s what we do in all our businesses.

Thank you. And maybe you can just give some context around what’s going on in Veresen Midstream and I realize it’s embedded within your guidance, but maybe a bit more granularity around the outlook there? Are we looking at a temporary blip in Q4? Is this a new run rate or might there be some other tilt in the volumetric outlook this year and beyond?

So in the Veresen Midstream, Linda, 2020 we would expect to be very much in line with the 2019s EBITDA. We do – we’re obviously very excited with the amount of liquids that are coming out. The one customer there [indiscernible] has been very public with the amount of Montney liquids coming out of that place. So we really like the resource there and we’re extremely excited about the advancements with LNG Canada. Obviously CRP, the Cutbank Ridge partnership other partner is also a partner in LNG Canada. So we continue to see that bridge through the liquids in the low gas prices, and then continuing on into maximum utilization once LNG Canada comes on in service.

Thank you. Final logistical question. Rail disruptions, how might we think of any sort of impact on your business in Q1. Would it be viewed obviously embedded in your guidance, but might it be a modest headwind? Could it create some pricing dislocation opportunities if your flexibility in your system? And how might it affect, if at all any sort of major parts being shipped for any of your capital projects? Either whether it be rail or port or other shipping disruptions on that front.

Linda I will talk about the – from the marketing side. So yes, we’ve got a slight headwind like everyone else, the moving of our products, the marketing products across Canada into other places. We are impacted with the rail challenge that we’re facing today. I think Pembina the seismic rail fleet, our logistics expertise we’ve probably done better than most and are continuing to move product, but there is a slight headwind, we are a few days behind where we’d hope to be for the month of February as we’re closing out with the reduction of speeds on the rail system that will affect everyone as the rails become more congested. We are working, we’re providing inputs and talking to the government with relation of the rail side and the rail speeds. But it is an impact that we’re going to face, but we also feel we’re probably one of the best to serve and survive in this environment with our fleet and with our logistics capability. I can’t speak to any equipment coming in at this point. I heard there is significant traffic in ships coming in. I’m not aware of any of our projects at this point being affected by the delivery of equipment.

Thank you.

Your next question comes from the line of Robert Kwan from RBC Capital. Your line is open.

Hey, good morning. If I can come back to Ruby. I’m just wondering can you share at least even directionally what some of the assumptions are behind the write-down. For example, if you assumed any amount of recontracting and what types of tolls, at least directionally do you except – expect lower tolls?

Rob it’s Scott here. We’re not going to get into the specifics of that just because of the fact that we are going to be entering commercial negotiations. So we don’t want to tip our hand. But we did assume some recontracting at tools that are lower than the existing rates right now, that’s about all, I think we’re prepared to say on that front.

Fair enough. And just on those tolls, I remember does PG&E have most favored nation clause with respect to its contract to tolls?

We can’t comment on the terms of people’s contract.

Okay. I guess the last just on Ruby. If things get worse, are you willing to allow Ruby to file for restructuring?

I think it’s a bit early for that. So I think if you think back to pre-2015 on Alliance, it was in a situation where a lot of people thought things would not go well. I think we’ve got a lot of a lot of running room in front of us before we get to those types of discussions. I think we talked about earlier in the call that there’s some spot opportunities that present themselves that can generate some pretty good revenue on that ruby pipeline. So I think it’s too early to today, anything like that.

Yes Rob, I would just jump in that if you go to the impairment note in our financials, we do talk a little bit about the Ruby impairment. I believe it’s note-10 and so one other data point is the discount rate of 8%. That’s public in the financials. The other thing I’d say is that based on the current contractual profile, we obviously see no impact to that preferred distribution for 2020 and 2021. The next note that comes due is in 2022. And so we do have two even a bit years to continue to work on that file.

Okay.

Yes, it’s Mick. We have significant cash flow. Don’t get the wrong idea. There’s significant cash flow projected on that asset well, well into the future. So we don’t want to leave you with the impression that there’s a clip coming.

Thank you. I guess the question was just a little bit more philosophical, given there is no requirement for you to step in. I’m just wondering whether it’s reputational or what have you that you would want to step down? Is there anything…

We’ve never had a write-down. So this is already new to us. That’s an interesting question. But we’d have to have to think about it.

Okay. If I can finish on guidance, I know you’ve reiterated the range, which is fine. I guess, if you just think about when you set the guidance, are you able to set out, say, two tailwinds to that guidance and two headwinds at this point?

Well, headwinds, obviously, the marketing margins continue to be a little bit of a headwind. And that’s really what forms the outliers in the guidance is for kind of P 10, P 90, however which way you want to come on the range of marketing. Volume growth has been modest. So obviously, with the commodity price deck out there. Tailwinds, as I said in my piece, the ocean and the tanks have been really well received. So we’re seeing some nice pickup on [indiscernible]. The ability, as you think about Pembina store to have storage along with your transportation. I think that’s really interesting as well. So there’s always a bit of both. And those are a couple that come to mind.

And just to clarify on the Cochin and the tanks as a tailwind to the 2020 guidance. I guess, it sounds like you’re on track to be realizing somewhat material part of that $100 million in 2020?

It’s not really what I’m speaking. I’m just saying, day-to-day operations are – we’re exceeding our expectations on some of the day-to-day stuff outside the synergy bucket. The synergy bucket is on track.

Okay, that’s great, thank you.

Your next question comes from the line of Praneeth Satish from Wells Fargo. Your line is open.

Thanks, good morning. Just going back to Alliance for a second. You mentioned in the past the possibility of doing a smaller 100 million cubic feet per day expansion. Is that still the size of offering that you’re looking at? And I guess, if you’re successful, when could that capacity be placed into service?

Hi, this is Jason. So I guess, it will take – it’s really just a compression project. So it takes probably with regulatory process and construction, it probably takes about two to as much as three years to get something like that in service because it is a federally regulated pipeline. So I would say that would say that would be about the time line.

Got it. And then if you proceed with that, just to clarify, with oxable have to be expanded?

Are you talking about in Chicago?

Yes.

So we think that we can handle the – a small expansion like that at oxable with some minor tweaks at the plants. But once we go towards the bigger expansion 200,000 to 400,000 or 200 million to 400 million cubic feet a day, that’s when we have to start having a hard look at oxable?

Yes it’s Jaret here. We just have to evaluate the richness of the gas that would be coming out of the Bakken. And can we accept that on the processing side at Shanahan. But on the frac side and then do we need to add any more rail capacity is what we’re looking at right now.

Got it. And then just one more question from me. In terms of Prince Rupert, are you seeing any demand from your customers to maybe start moving some butane, I think it’s mostly a propane export dock at this point, but could it be expanded to incorporate butane shipments?

Currently, we’re focused on expanding for the C3 in our recent announcement, just due to the overhang of C3 in the province. Butane, obviously, isn’t that long. But definitely, customers would like enjoy and benefit from having more butane and propane uptake.

Thank you.

Your next question comes from the line of Robert Catellier CIBC Capitals. Your line is open.

Hi good morning everyone. And thank you for your fourth right answers to the questions so far. I just wanted to just dive into your appetite for LNG in general and Jordan Cove in particular. So how do you go about balancing the need that you see in the marketplace versus in the marketplace versus the challenges in developing those types of projects? And basically, what would it take for you to go FID on something in Canada? Are you looking at a new project or buying an interest in an existing permitted project?

Well, that would really narrow it down. Wouldn’t it Robert? Listen, as we as we push to get our products to better markets, we’re looking at everything. The LNG project Jordan Cove, what time line that’s on exactly, I guess, we’ll get some insight from FERC on that. We think the FERC approvals will build momentum for the project with the state. And the scarcity of that project, probably will be the only West Coast North American LNG terminal. It still intrigues us. And we’re going to stick with it, because our cost to stick with it is nominal, and it has huge upside. And so the math is pretty easy. We’re going to methodically move that one forward. We’re looking at a bunch of locations in BC, and there’s attributes of lower risk with some existing projects that are appealing. But those are not free. So just weighing all that out, looking at really what the gating criteria is for BC LNG. If, for example, it was determined that access to green power was a gating issue, then that’s something you have to look at first nation support is something you have to look at. So all the locations, we’re putting them through our set of key attributes, and we’ll try to move something forward. This is going to be a long-term process. I’m not aware of any major infrastructure projects in Canada or for that matter, anywhere on the West Coast of the U.S. that that gets done quickly. You go through the regulators, then you go through the courts. And so these are kind of mid- to end decade projects that we’re looking at. And we’re just laying the groundwork now because it just takes that long.

Yes. I mean, there’s no question about them, it’s hard, and that’s a good segue to my next question. I’m curious as to how you’re factoring in BC and trying [indiscernible] into law in terms of? And also, I guess, separately, the recent rail blockades into how you how you view development in BC, not specifically or limited to LNG, just in general, but also on the LNG file?

It’s a great question. We actually added that uncertainty into our investment criteria. So we had, let’s say, 10 investment criteria, we’ve added an 11th, if I’ve got my numbers right, around what are the risks of changing regimes, right? I mean, you’ve got a federal regime, a provincial or state regime, you’ve got a local regime, you’ve got first nations and other local stakeholder regimes, and they’re always in a state of flux. So if you take a Jordan Cove that, let’s call it, a ten-year total development cycle, you’re going to have two or three federal governments, two or three state governments and so on and so forth. And so how do you lead the goal and thread through all those things and create some lasting alignment for all stakeholders? That is a new risk criteria that we consider on these long-term projects. And so one thing it could lead you to is to have many opportunities because only one will be able to leave the golden thread. So it changes your portfolio of thinking.

It kind of speaks to the need of higher returns that you’re going to have to invest more development dollars spread against different options, it kind of speaks to a requirement for a higher return as well?

Yes. I mean, we used to say like, if you want to build a hydrocarbon project in Africa, then you need the political risk. Part of your return, and I think that exists now locally. So you’re quite right.

Okay. My final question then is just with what’s going on in the market. So I don’t want to get too carried away about the short-term markets here. I’m thinking just longer-term on the gas market, everything that’s happening there. What’s your appetite for new gas investment? You guys have taking the impairment on Ruby, but a number of your peers have also taken gas asset in impairments during the quarter. So what’s your update like for new gas infrastructure investment?

Well I mean, we’re primarily, as you know a hydrocarbon liquids company. And we got into the gas business originally to get more liquids out of the gas stream and to feed our core hydrocarbon liquids business. It comes down to geology. I was glad that you pointed out that we’re only 15% cretaceous, meaning that the other 85% is high liquids product. And so it’s a means to an end rather than a core strategy for us. Other than perhaps the things that we need to do to support LNG development because that hopefully takes you into a completely different market. And reminding everybody that we pursue a tolling model. And so the buyers of those services have very, very long-term demand, which makes you much more ambivalent to the price of gas.

Okay, that’s it from me. Thank you.

Your next question comes from the line of Patrick Kenny from National Bank. Your line is open.

Hi guys. Just on the polypropylene facility. I know you have the engineering and procurement contract locked down. But given you have a couple of other projects currently trending over budget. Maybe you can comment on your comfort level around the construction budget for the DP facility?

Patrick this is Stu. We’re just starting the detailed engineering. And so to be clear, what we have, we have the PDH component of the project. The most complex from an engineering and build perspective, walk down on a lump sum contract, that secured 60% of our costs. We have kicked off the EP contract on the PP facility. We’re continuing to evaluate that. It’s a less complex, simpler facility. We believe we’ve gone and partnered with TR, who our PP experts and have built numerous facilities or engineered numerous facilities in PP facilities in recent years. And when we get down to the construction contract, we’ll be evaluating that. But our team remains confident at the highest level of our capability to secure good contracts – good construction contracts when we need those. And again, it’s a simpler facility to build. So we, at this point, remain confident that we’ll come in on budget as we plan for that PP facility.

Okay, great. Thanks Stu. And then maybe for Scott. Just looking at consolidated leverage here. Based on guidance for 2020, it looks like debt-to-EBITDA will be temporarily above the 4.25 times threshold. I know you have various levers to pull, but just curious when you expect this ratio to come back in line with your longer-term cargo rails? And if maybe you can confirm your outlook for any near to medium-term equity needs to fund your capital program?

Hey Rob, I’m sorry, Pat. I think our math would show us not reaching that guardrail in 2020. As we look forward to 2021, 2022, I think we’ve been pretty open that leverage will peak slightly higher than that, maybe up to 4.5 times as we reach peak kind of construction on the PP plant. If you think about where we are in the asset cycle, we do have some assets coming on in 2020. But then a lot of the cash flow from the existing projects don’t come on until kind of later in 2022 and 2023. So we’ve always been pretty clear and shown our path for leverage to tick up in 2021, 2022. And then you start to see it come down in 2023 and then materially in 2024 when the PP/PDH come online. And then in terms of equity, I mean, I think as we’ve stated many times in our base case development plans, we are not forecasting or predicting any need for equity.

Okay, great. That’s it from me guys. Thanks.

[Operator Instructions] Your next question comes from the line of Ben Pham from BMO. Your line is open.

Okay, thanks. Good morning. On Watson, can you remind us what your tolling or contracting strategy is on that project?

Ben it’s Stu. Essentially, we’re moving product through – our customers’ product through that facility and recovering costs for the services offered. So it’s an all-in cost, essentially for moving product through the facility and market rate, we market and sell that price, they’ll get a return on that. We’re taking our contracted volumes that we have with our customers and running them through that asset.

I’d just add, we have some of our own product in there. You’ll recall from the Provident acquisition. So we have some frac spread barrels out of Taylor, for example, that we own the barrels. And– we take that through on a proprietary on a proprietary basis alongside customers’ barrels and our matter there is customers get what we get. But there’s a more of a tolling model.

It will be a percentage. It’s a small percentage of our entire portfolio as we move barrels all over North America. Our customers get every get a portion of that, they’ll get a portion of the PRT opportunity as well. And in the future as we go forward with the PDH, and we moved our propane in through the PDH facility, that too will become part of the basket of market that our customers will be able to access, giving them great diversification in pricing.

And it really just one last build on that. The expansion up to a new frac, whether it’s an NEBC or Redwater IV I think, is a significant feature that customers are looking for to pay and other exposure to those incremental propane barrels. So again, that’s more than one thing to buy in the Pembina store.

Okay. And maybe going back to what your guardrails being above 80%. And I think you’re at 87% or 86% or, so that’s helping out in this the commodity type. Could you comment on where that trends over time, especially with PDH coming on? And maybe just kind of high-level of thinking, like is it kind of like more you think about your leverage where you’ve always historically like to be below under leverage position? Is the same thing on the commodity side, it’s 80% plus, but you like to be well above that?

Yes, maybe I’ll take that. I think in 2019, we still overall, had a pretty good year for commodities around that 85%. If you take a normal what we’ll call a P 50 marketing case and then annualized for a full year of Kinder, we should be in and around that 90% range on a fee basis. In fact, our 2020 budget looks at about 90% fee-based contribution. On a pro forma basis, if we get to some of our expectations around contracting the PDH we would expect that all else being equal, to drop to maybe somewhere between – around 80%, Ben, that would be about the impact, somewhere plus or minus 1% or 2% off, of that.

Okay, that’s pretty…

It’s always been underground every year, depending on the commodity contribution. So I’m just trying to use a normalized commodity environment to kind of baseline, you had about 90%.

Yes and that makes sense. And maybe just lastly, the Peace expansions, and maybe more specifically, Phase 10, ,is that – is Phase 10 really just more getting better predecessor phases in and reevaluating that? Or do you actually see some more volume production ramping up in the Montney?

Well, I think, two-part to answer there, Ben. We’ve put on some of our other expansions. And as we’ve ramped up the volume to full utilization, we found that usually, we built in enough caution through our engineering process that we actually have been able to run those assets at a higher volume than we predicted. So there’s a lot of processes in place and some conservatism on a number of steps through the process that you take that sort of until you actually have the volume there, you can’t really test. So in terms of the long run, though, yes, we still see a long runway of volumes in terms of opportunities. And we’re somewhere in the neighborhood of 70% utilization right now, contracted at a much higher level. And we still have a lot of discussions ongoing to see more capacity signed up here and over the next year.

Okay. And then maybe just to close off, I know that’s there you’ve’ got Phase 10 and then your product segregation in line. Is there still a lot of runway beyond Phase 10? Maybe just call it up something at that point where we can start expanding piece even beyond that? J

Well, I think, Mick mentioned between powering up our main lines in Phase 10. We have about 300,000 barrels. So that’s a fair bit of runway right off the bat. But we also have a number of pipelines in the corridor between, say, Fox Creek and Edmonton that are underutilized or utilized in different services that we could look at for alternatives. So before we’d have to start building anything new.

In terms of – if you want to zoom way out, you look at the Montney and the Duvernay, high liquid basins, they’re very immature, really. 100-plus years of resource life, up to 150, depending. And every time we look over our shoulders, it’s more barrels per million that people are able to bring out. So if you’re asking, could there be life beyond Phase 10? Absolutely, those basins if we had egress, a number of LNG plants versus one, and as all these pipelines fight their way through used to say approval, but now becoming operationalized, there’s going to be a lot of egress. And we’re really well positioned between – if you look at the oil egress, 1.5 million barrels of oil egress that has to come from the field to the center in Pembina’s between the field and the center. So we’re pretty optimistic as these pipes, gas or oil get built that we’re extremely well positioned to benefit from that growth.

All right that’s great. Thanks everybody.

There are no further questions at this time. I turn the call back over to the presenters.

Well, thanks everybody. It’s been a great run for some of us who have been here 10 years. It’s been a lot of fun and look forward to the next 10, and thanks for your ongoing support and try not to look at your trading screens today. Cheers.

This concludes today’s conference call. You may now disconnect.