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Pembina Pipeline Corp
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Ladies and gentlemen, thank you for standing by, and welcome to the Pembina Pipeline Corporation Fourth Quarter Results Conference call. [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, 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; Stu Taylor, Senior Vice President, Marketing and 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 refer 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 entitled Pembina to the first $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 Basin 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 in 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 narrow Chicago-AECO natural gas differential impacting both Alliance Pipeline and Aux Sable. This 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 3 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 4x. 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 an 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 Hythe Developments project as well as Duvernay III. 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 5 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 Cochin 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 4 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 to Namao corridor. And we've begun 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 the 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 a 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 2/3 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 has -- 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 asset footprint is poised to benefit from the development of LNG projects to be located on -- 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 North East B.C. as well as continuing to progress our proposed Jordan Cove project. In 2019, we are pleased to share our progress in developing 2 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 more definitive targets. 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 will receive a 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 line for questions.
[Operator Instructions]Your first question comes from the line of Matt Taylor from Tudor, Pickering.
Just wanted to start there on Ruby. Seems like the writing has been on the wall there for a while. So I just assume this is a formalization of that, but it'd 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 press interest? And then what are you assuming you'll be able to recontract even before Jordan Cove may enter service?
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's also -- there's an opportunity to continue to supply that Malin Hub. So we believe there's going to be an opportunity to roll those contracts over. There's also short-term opportunities that presented themselves. So if you think when this factory 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's going to be beyond just specific long-term contracts. We also think there's going to be interim 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's no power availability through sun or wind.
Great. And is there enough base level contracting there to at least cover the press interest in the interim?
No.
Good. And then on Jordan Cove...
Matt, let me just clarify for 2020 and 2021, yes. Post-2021, the short answer is no. But as Jason pointed out, they're actively working on recontracting.
And then just moving over to Jordan Cove, when do you expect FERC to re-hear that decision? Obviously, there's 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 so I'm wondering what it would take for you to focus. You had mentioned in your opening remarks there about B.C. LNG opportunities. So just wondering if we might see something similar here where you might focus your attention in B.C.?
Matt, it's Stu Taylor. So we are continuing to await the FERC -- we were expecting decisions to come out on February 13, now it's delayed to the 20th. And then a decision was further delayed. We've not gotten the 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's 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 B.C. 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 of British Columbia. So we are progressing all of our LNG projects, including Jordan Cove, and looking to come forward with a project on the B.C. side as quickly as we can through a lot of hard work by a number of people.
Your next question comes from the line of Jeremy Tonet from JPMorgan.
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? And anything as far as demand for Bakken takeaway there? Just everything on Alliance that you could share would be great.
Sure. 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 IP volume on that pipeline at the moment. Historically, Chicago market has 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, that have had 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're -- 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're 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 at 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. And I want to just turn over to the B.C. frac, something that you guys had talked about the possibility in the past. I'm wondering if you could update us there as far as what your thoughts on the potential need for that service and the ability to kind of do that at some point in the future?
Jeremy, Jaret here. So on the need side, we see that the fracs should 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's going to be a requirement for incremental fracs. What we're evaluating right now or continue to evaluate is the location of that. Obviously, we have a significant infrastructure in and around Redwater area, unit train capabilities, underground storage, et cetera, and we're weighing that against building up in Northeast B.C., where we don't have some of those things, but you are closer to some of the West Coast markets. 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.
Your next question comes from the line of Linda Ezergailis from TD Securities.
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 the 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's 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 they're the 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're -- 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 continuing 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 conversation 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 relief maybe from them in terms of potentially trading lower near-term rates for longer-term commitments or anything of that nature?
Linda, 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 a little bit today -- 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.
Yes. 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. You know how we think, we'd rather take a little lower toll and get a little longer term. So that's what we do in all our businesses.
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 much in line with the 2019's EBITDA. We do -- we're obviously very excited with the amount of liquids that are coming out. The one customer there of [indiscernible] has been very public with the amount of Montney liquids coming out of that play. So we really like the resource there, and we're extremely excited about the advancements with LNG Canada, obviously, CRP, Cutbank Ridge Partnership's 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.
Final logistical question. Rail disruptions, how might we think of any sort of impact on your business in Q1? Would it be -- obviously, embedded in your guidance, but might it be a modest headwind? Could it create some pricing dislocation opportunities if you have 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'll 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 of products across Canada into other places, we are impacted with the rail challenges that we're facing today. I think Pembina -- the size of our rail fleet, our logistics expertise, we've probably done better than most and are continuing to move product, but there is a slight headroom. We are a few days behind where we'd hope to be for the month of February, obviously, 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're working, we're providing input and talking to the government with relation to 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 then 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's significant traffic and ships coming in. I'm not aware of any of our projects at this point being affected by the delivery of equipment.
Your next question comes from the line of Robert Kwan from RBC Capital.
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 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 tolls 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 can't remember, does PG&E have a most-favored-nation clause with respect to its contracted tolls?
We can't comment on the terms of people's contracts.
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 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 say 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 2 and a bit years to continue to work on that file.
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 the impression that there's a clip coming.
Okay. 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 have to think about it.
Okay. If I can just 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, 2 tailwinds to that guidance and 2 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 P10, P90, 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, the -- as I said in my piece, Cochin and the tanks have been really well received. So we're seeing some nice pickup on Cochin. 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 of. I'm just saying, day-to-day operations are -- we're getting -- we're exceeding our expectations on some of the day-to-day stuff outside the synergy bucket. The synergy bucket is on track.
Your next question comes from the line of Praneeth Satish from Wells Fargo.
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?
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 2 to as much as 3 years to get something like that in service because it is a federally regulated pipeline. So I would say that would be about the time line.
Got it. And then if you proceed with that, just to clarify, would Aux Sable 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 Aux Sable with some minor tweaks at the plants. But once we go towards the bigger expansion, 200,000 to 400,000 -- or 200 to 400 million cubic feet a day, that's when we have to start having a hard look at Aux Sable?
Yes, it's Jaret here. Yes, we just have to evaluate the richness of the gas that would be coming out of the Bakken and can we accept that, not on the processing side at Channahon 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 for 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 offtake.
Your next question comes from the line of Robert Catellier from CIBC Capital.
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 the challenges in developing those types of projects? And basically, what would it take for you to go FID on something in Canada? And 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 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, 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 B.C., 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 B.C. 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 Nations' support is something you have to look at. So all the locations, we're putting them through our stave 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 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 developing, it's hard, and that's a good segue to my next question. I'm curious as to how you're factoring in B.C. enshrining under up into law in terms of -- and also, I guess, separately, the recent rail blockades into how do you view the development in B.C., not specifically or limited to LNG, just in general, but also on the LNG file?
That'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, let's call it a 10-year total development cycle, you're going to have 2 or 3 federal governments, 2 or 3 state governments and so on and so forth. And so how do you weave the golden 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 the one thing it could lead you to is to have many, many opportunities because only one will be able to weave 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 the 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 taken the impairment on Ruby, but a number of your peers have also taken a gas asset in impairments during the quarter. So what's your appetite 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 Jaret 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.
Your next question comes from the line of Patrick Kenny from National Bank.
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 PP facility?
Patrick, it's Stu. We're fairly -- 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 are our PP experts and have built numerous facilities -- or engineered numerous facilities and 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. 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 4.25x 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?
Sure, Rob -- 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 4.5x 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.
[Operator Instructions]Your next question comes from the line of Ben Pham from BMO.
On Watson, can you remind us what your tolling or contracting strategy is on that project?
Ben, it's Stu. We're -- 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 -- or after we market and sell that price, they'll get a return on that. So it's -- we're taking our contracted volumes that we have with our customers and running them through that asset.
We -- I'd just add. We have some of our own product in there. You'll recall from the Provident acquisition, we have some frac spread barrels out of Taylor, for example, that we own the barrels. And we'll take that through on a proprietary basis alongside customers' barrels and our mantra there is customers get what we get. And -- but there's just 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 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 move 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 in NEBC or Redwater IV, I think, is a significant feature that customers are looking for to pave another 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 one of your guardrails being above 80%, and I think you're at 87% or 86% or so, it's helping out in this the commodity tape. Could you comment on where that trends over time, especially with PDH coming on? And maybe just kind of high-level 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 you annualize for a full year of Kinder, we should be in and around that 90% range on a fee basis. And 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 to PDH, we would expect that, all else being equal, to drop to maybe somewhere between -- around 85% then. 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 at about 90%.
Yes, that makes sense then. And maybe just lastly, the Peace expansions, and maybe more specifically, Phase X. Is that -- is Phase X 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, a 2-part to answer there, Ben. It's -- 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've 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 it's just -- 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 or so.
And then maybe just to close off, I know that Phase X and then your product segregation in line, is there still a lot of runway beyond Phase X? Maybe just call it something else at that point where we can start expanding Peace even beyond that?
Well, I think Mick mentioned between powering up our main lines in Phase X. 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 year 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 X, absolutely. Those basins, if we had egress a number of LNG plants versus one, and as all these pipelines fight their way through I 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, and 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.
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.