Pembina Pipeline Corporation (PBA) Q4 2016 Earnings Report, Transcript and Summary

Good morning. My name is Jodie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation 2016 Fourth Quarter Results Conference Call. [Operator Instructions] Thank you. Scott Burrows, Vice President of Finance and Chief Financial Officer, you may begin your conference.

Thank you, Jodie. Good morning, everyone, and welcome to Pembina's Conference Call and Webcast to review highlights from the Fourth Quarter and Full Year 2016 Results. I'm Scott Burrows, Pembina's Vice President of Finance and Chief Financial Officer. On the call with me today are Mick Dilger, Pembina's President and Chief Executive Officer; Stu Taylor, Senior Vice President, NGL and Natural Gas Facilities; and Paul Murphy, Senior Vice President, Pipelines and Crude Oil Facilities. Before passing the call over to Mick for a review of quarterly and full year highlights, 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, projections and risks. 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. Actual results could differ materially from the forward-looking statements we may express or imply today. Over to you, Mick.

Thanks, Scott. Good morning, everyone. Looking back, we felt 2016 was a great year for Pembina. We had record financial and operating performance and maintained an exemplary safety record. Our staff worked 2.9 million hours in 2016 without a single lost time incident. This is the third time -- third year in a row we've had no lost-time employee incident. We completed approximately $1.2 billion in major projects representing a meaningful portion of our secured growth projects, including our second Redwater fractionator; expansions of 2 gas processing facilities totaling 200 million cubic feet per day; the expansion of the horizon pipeline system, among other projects. The remainder of our growth projects are also progressing well. Overall, Phase III is now 60% complete, and we're actually commissioning the pump stations right now. RFS III is expected to come in on schedule -- actually, ahead of schedule in July. Initial connectivity at our Diluent Hub, Canadian -- CDH, is now operational. These projects alone total approximately $3 billion and are scheduled to be completed by the middle of this year. In 2016, we secured over $750 million in new growth, which helped to augment our competitive positioning in 2 of the basin's premier resource play, the Alberta Montney and the Duvernay. We have begun work on the next wave of growth opportunities. We completed our feasibility study for our PDH/PP project, which Stu will discuss later on in the call. We purchased approximately 22 acres of highly strategic lands in the Alberta Industrial Heartlands, directly adjacent to our Redwater site. And we just announced an exciting opportunity with Chevron in the Duvernay, which Stu will also discuss later on the call. 2017 is set to be a transformational year for Pembina as we complete approximately $4 billion in projects, 3/4 of which will be completed by the middle of this year. The incremental fee-for-service cash flows from these projects will strengthen Pembina's financial foundation, ideally position us to pursue growth opportunities which continue to drive shareholder value over the long term. I'm very proud of the year Pembina had and excited for what the future holds. I'd also like to thank our stakeholders, customers, communities, investors and employees for their integral support during such an exciting time for Pembina. Now Scott will provide a few financial highlights from our operational perspective.

As Mick mentioned, Pembina realized record operational and financial performance in 2016. Fourth quarter adjusted EBITDA was $342 million, an all-time quarterly high, and $1.189 billion for the year as a result of stronger performances across all businesses, including new assets placed into service and the Kakwa River acquisition. Respectfully, adjusted EBITDA was 27% and 21% higher than the comparable period last year. This strong business performance, partially offset by additional preferred share dividends, resulted in adjusted cash flow of $292 million for the quarter and $986 million for the year. Per-share metrics were largely in line with last year as a result of share reissuances to partially fund our organic program, part of which won't contribute to results until later this year, and partially to fund the Kakwa River acquisition. Our Gas services business processed a record 976 million cubic feet per day in the quarter and 836 million cubic feet per day for the year. Revenue volumes were 61% and 21% higher, respectively, in the comparable periods -- to the comparable periods in 2015. Increased revenue volumes from new assets and the Kakwa River acquisition translated to operating margin of $60 million for the fourth quarter, 82% higher than the comparable quarter last year. For the year, Gas Services recorded operating margin of $195 million, a 35% jump from 2015. NGL sales volumes were also at a record level at 164,000 barrels per day for the fourth quarter and 143,000 barrels per day for the year. A combination of increased NGL sales volume and a higher commodity margin helped support increased operating margin in our Midstream business. Operating margin for NGL midstream activities was 30% higher than for both the fourth quarter and full year of 2016 at $112 million and $334 million, respectively. Operating margin for crude oil Midstream activities increased to $46 million compared to $37 million for the comparable quarter as the result of increased storage revenue. For the full year, operating margin was 5% lower at $162 million as a result of lower commodity margins due to tighter differentials and the exit from the full service terminal business. Conventional Pipeline volumes were 639,000 barrels per day for the fourth quarter and 650,000 barrels per day for 2016, increases of 3% and 6%. During the fourth quarter, routine maintenance on the Peace Pipeline modestly impacted revenue volumes due to a turnaround for our expansion coming online. Without this outage, revenue volumes for the fourth quarter would have been approximately 675,000 barrels per day or 6% higher than reported figures. Operating margin in Conventional Pipelines increased by 8% to $118 million for the fourth quarter as a result of higher revenue, somewhat offset by increased operating costs. For the year, Conventional Pipelines realized operating margin of $494 million, 23% higher than last year as the result of higher revenue and lower operating costs, which were mainly due to ongoing refinements in our integrity management program. Our oil sands business continued to perform in line with the previous periods, as expected. Pembina continued to maintain one of the strongest balance sheets in our sector, further supported by a very strongly liquidity position. For the last 12 months, Pembina's debt-to-EBITDA ratio was 3.5x. After year-end, we completed a very successful $600 million medium-term note offering. And as of February 22, our $2.5 billion credit facility was completely undrawn, which allows Pembina to have ample liquidity to fund the remaining 2017 capital program. I will now pass the call over to Paul, who will provide an update on growth projects within our condensate and crude oil value chain.

Thanks, Scott. Good morning, everyone. As I mentioned on our last quarterly call, we are now in full construction mode, with over 3,000 people in the field working on our various Phase 3 expansion projects, which is now 60% complete. Our teams are currently working on the largest section of the project between Fox Creek and Namao, Alberta. In spite a very unseasonable weather last fall, we feel confident about the project's scheduled completion by the middle of the year within its previously disclosed budget. I want to commend the great job our teams have done managing Pembina's largest greenfield project to date in spite of mother nature's challenges. We also continued to advance our portfolio of lateral pipelines. These projects represent strategic opportunities to increase the reach of our mainline system. After receiving approval from the British Columbia Oil and Gas Commission, we have begun construction activities with our Northeast B.C. expansion. This $235 million project is underpinned by cost-of-service agreement and will provide strategic egress capacity for the liquids-rich Montney production growth. Development of the Altares Lateral is also underway, which will connect into the Northeast B.C. expansion. Both of these projects are expected to be completed by the end of the year. In 2016, we completed 2 projects within our Oil Sands & Heavy Oil business. The Horizon Expansion was completed in July, which increased the system capacity to 250,000 barrels per day. Later in the year, a modest expansion of the Cheecham Lateral was also put into service. Moving over to our crude oil business, Midstream business. Initial connectivity at the Canadian Diluent Hub is complete. This phase of development provides connectivity between Pembina's conventional pipeline infrastructure into the diluent takeaway capacity out of Redwater sites. We are currently flowing condensate volumes into access Cold Lake and Fort Saskatchewan pipeline systems, and are pleased with the initial demand from customers as well as the operational performance of the facilities. Construction of the 500,000 barrels of storage at CDH is now 90% to 95% complete. We are expecting the overall CDH project to be finished by the middle of this year, and it continues to trend under budget. I will now pass the call to Stu to provide an update on growth projects within our NGL value chain.

Thanks, Paul. Good morning, everyone. 2016 was a successful year for Pembina Gas Services business as we added approximately 450 million cubic feet per day gross from new processing capacity. Expansions were completed at both our Resthaven and Musreau facilities early in the year. And in April, we closed the acquisition of the Kakwa River facility, which represents Pembina's first sour gas processing facility. Pembina continues to advance our infrastructure platform in the Duvernay. Engineering is 85% complete. All major equipment has been ordered, and site grading and piling activities are now finished for our 100 million day -- 100 million cubic feet per day Duvernay 1 facility. At the field hub, all required regulatory approvals have been received. Engineering is 55% complete, initial civil work is done. Both projects are expected to be brought into service in the fourth quarter of 2017, and the expected total investment is approximately $240 million. We are very pleased to be -- to have been selected by Chevron Canada Limited to be their midstream service provider of choice to support their Duvernay development. As we recently announced, Pembina and Chevron have entered into a 20-year infrastructure development and service agreement. The agreement includes an area of dedication by Chevron in excess of 10 gross operated townships, over 230,000 acres, concentrated in the prolific, liquids-rich Kaybob region of the Duvernay resource play near Fox Creek. Under the agreement, and subject to Chevron sanctioning regional development, Pembina will construct, own and operate gas-gathering pipelines and processing facilities, liquid stabilization facilities and other supporting infrastructure. Additionally, Pembina will provide long-term service for Chevron on its pipelines and its fractionation facilities. In aggregate, and subject to internal Chevron and regulatory approvals, the infrastructure developed over the term of this agreement has the potential to represent multibillion dollar investment for Pembina. While this agreement and respective obligations are binding, the infrastructure fulfillment [ph] remains contingent upon Chevron's sanction as well as necessary environmental and regulatory approvals. The development of our proposed PDH and PP facility is well underway. We've completed our detailed feasibility study, which yielded encouraging initial results. We are also encouraged by the conditional award of $300 million in royalty credits from the Alberta government's petrochemical diversification program late last year. We hope to make a decision about FEED by the end of the first quarter of 2017. Key deliverables of the FEED phase include regulatory application, a Class 3 cost assessment, a project execution plan, among other items. We are aiming to make a final investment decision of this project by the second quarter of 2018. Subject to regulatory, environmental and Pembina's board approval, the project could be in service by 2021. Overall construction of RFS III is at 90%, and the facility will be effectively complete by early in the second quarter of 2017, which will be followed by commissioning activities. We expect to be able to bring RFS III into service early in the third quarter of 2017, ahead of our original expectations. Pembina continues to progress construction on infrastructure in support of the North West Redwater Partnership planned refinery. Overall, the project is now 70% complete, engineering and procurement activities are over 90% finished, nearly all materials and equipment have arrived on site. Various phases of the project will be placed into service throughout 2017, and by year's end, the project will be complete.

Thanks, Stu. Pembina made meaningful strides in 2016 towards achieving our goal of $600 million to $950 million of incremental EBITDA as compared to 2015. 2017 will be a very exciting year for Pembina, as we will realize a full year benefit from the approximately $1.2 billion of major projects we completed in 2016. Further, with approximately $4 billion of projects to be completed in 2017, substantial fee-for-service cash flow is imminent. Our balance sheet remains among the least levered in our sector, and we continue to maintain robust liquidity and are hard at work on our next wave of growth. This combination creates an unparalleled foundation for Pembina to continue to drive long-term shareholder value. As always, we will keep a sharp focus on operating and growing our business in a safe, reliable and cost-effective manner. We look forward to speaking to you again in May in conjunction with our Q1 results. With that, we'll wrap things up and open the line for questions.

[Operator Instructions] And our first question comes from David Galison, Canaccord Genuity.

So my first question is, with all these assets coming online, including the Phase III in 2017 and with the cash flows you'll be generating, how should we think about the potential uses for those cash flows? Will they be focused on additional growth? Or will there be a focus on maybe a staged increase in the dividend? Or just thoughts on how to use the cash.

I think the answer is yes. We've been growing our dividends 4% to 6% for a long period of time. We see room to be in the higher end of that. That'll be up to the board here in the next number of months to decide. But yes, we're going to continue growing the dividend, and I think that we've been saying for some time, we have confidence in the basin and continued opportunity in the basin. I think the Chevron transaction exemplifies that. And we expect to keep growing at, at least $1 billion a year, that's what's in my objectives for the year. And some years -- it's a lumpy business. Some years, it might be $3 billion, in some years, it might be $1 billion, but we've been generating that kind of growth even through these last 2 kind of recessionary years, so we're pretty confident we could have a use of proceeds towards growing our asset base.

Okay. And then just on the Chevron agreement, how do you envision the contracts? Will they be fee-for-service, or will they be more of a cost-of-service take-or-pay type of contracting system?

This is Stu. They're going to be a combination. Part of our -- the agreements are cost of service. But depending on the infrastructure, the remaining are fee-for-service type contracts with growing commitments as we continue to build and develop the infrastructure working with Chevron.

Okay. And will those -- would the assets all be dedicated to just servicing Chevron? Or will they be dedicated -- can you -- will they be open to other volumes as well if it should warrant?

One of the big and important points for Pembina was to ensure that we have the ability to overbuild any infrastructure we saw in the area such that we could have third parties come through that infrastructure and utilize that. We have rights, depending on what the infrastructure is, to bring third parties, and that revenue will be attributed to Pembina's account.

Your next question comes from the line of Rob Hope with Scotiabank.

Congratulations on a good year. Just taking a look up into the Montney and to the Duvernay. We're seeing a number of third-party plants being sanctioned and seeing pretty good activity levels. Just want to get a sense on, over the last 3 or 6 months, if you've been able to continue to translate that activity levels into increased contracted volumes on your infrastructure, being Phase IIIs.

Yes. I mean, every time a new plant is built -- sorry, it's Paul. At this point, they come to us for more service. So we're in the middle of looking at the feasibility of the -- our Phase IV, which should be -- we've talked about it before, some small pipeline segments and powering up the pipeline that we're building right now.

Yes. So we're doing the engineering, and we're clearing land for Phase IV right now. It doesn't mean it's going to go ahead, we need a certain volume threshold, but it's certainly possible.

And can you share what kind of -- where you are on the volumes and where you need to be on the volumes for Phase IV? If you're clearing land already, I would imagine you're getting closer.

No, the -- you know how the producing community is. They're very cautious when they sign up, but once they sign up, they want the pipeline right away. And so we are, on our account, spending a relatively modest amount of money, I think about $20 million, to make the time between the date they sign and the onstream date a 1-year period versus a multiyear period like we saw with -- it's tough to get approvals overnight, and so we're preemptively seeking all the approvals and having the rights away and doing our consultation in anticipation that those volumes will be signed up, because once they are signed up, our experience is that you just can't react quick enough.

Okay. And then one last question, I'll jump back in the queue. Looking at it another way, the $600 million to $950 million of EBITDA that you cite for your projects, I just want to get a sense of how quickly you're migrating from that $600 million north towards $700 million, $800 million.

Well, David, if we -- or sorry, Rob, if we just go through the math again, remember, the $600 million is really the contractual threshold that assumes no volume. So the upside from $600 million to $900 million is a few things. It's volume through CDH, which I think, as we mentioned in this call, we're already starting to see volumes go through CDH. There is marketing revenue from both RFS II and RFS II. Obviously, RFS II is up fully running, and we are marketing barrels off the back end of that. And then higher utilization above our take-or-pay, which I think we'll have a better view as we move throughout the year and get closer to the Phase III in-service date. But I think it's fair to say that we will be above the bottom of that $600 million range.

Yes. There's significant apportionment right now behind our systems, so that's an indication that people are trying to do what they need to do to at least hit their take-or-pay threshold with physical volumes.

Your next question comes from the line of David Noseworthy of Macquarie.

Great. I only add my congratulations on the great financial results and ongoing safety track record. So maybe just starting off on Chevron, do you have an idea in terms of timing of when you might see the sanctioning of the first project?

Yes. David, it's Stu again. Just -- so we're optimistic that Chevron is -- we've been working with them, the D1 plant will process some of their existing wells that have been drilled to date here as soon as that's in service. We expect, as they continue with their development, that sometime in the next 12 to 18 months, that the first service poll will be coming in. But it is totally at Chevron's call and subject to all their internal sanctioning, but we're excited about the Duvernay results. We're excited about the activity levels, and we think we'll be busy here working fairly quickly.

And we -- I think we've started some engineering on the infrastructure already.

Yes. We've -- we spent some money in advance, recognizing -- obviously, our D1 facility in the MGS, the infrastructure we're building to-date, plus looking at some enhancements to that. And we're spending some preliminary engineering dollars. So again, as Mick said, on the pipeline, so that we can move forward quickly with designs and trying to shorten that in-service time.

All right. And then just so I'm clear, with respect to Chevron and their internal approval. For this agreement to move forward, is there something that they have to do above and beyond the required sanctioning in terms of approvals at this juncture? Or is it just, at this point, everything's been signed and it's just sanctioning your projects going forward?

At this point, with -- the agreement was -- that was covered included all of the infrastructure and the overriding structure of the arrangement. And upon their sanctioning, we -- all the agreements are ready to be completed, and they're in execution phase as they ask for that infrastructure.

Even -- the land's dedication is binding, so if they're going to do anything, they have to do it with us. The timing of the different modules that they call for is still up to them, but the land dedication is -- it's the done deal.

Got it. Okay. And then maybe just turning -- staying on the gas side of things, which is another area. Your Kakwa plant acquisition came with a design for a -- that 6-18 plant. Has there been any positive development on that front? Or has there -- the change of ownership really cooled the opportunity for further growth there?

Like most things -- so we've continued to work with Seven Gen. And I think, like most things as you have, a new acquirer takes them a bit of time to sort out the acquisition report. I'm happy to say that I think we're making progress and ramping up here quite rapidly with Seven Generations. We've been working with them on the expansion opportunities, looking at our existing infrastructure, how to utilize that as well. And so we're excited about moving forward with Seven Gen in a meaningful way here in the next few years.

David, I'd just add that the plant -- that plant wasn't completely capable of being built, given its front-end liquids capabilities. So we're spending significant money, I think $50 million...

$50 million.

$50 million to enhance the ability of -- for that plant to take liquids. So that's well underway. And when we ran economics, we kind of thought of a 3-year build to build that plant. And with the enhanced liquids front end, we think we can accelerate that and improve essentially the NPV and IRR of that project.

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

Just wanted to follow up on the Chevron opportunity a little bit more. As far as the spending that you guys envision, is it kind of fair to think, kind of a couple of years out, it could start to tick up and then kind of be a multiyear window at that point? Or is it more ratable over a longer period of time? Or any color that you could provide there?

Again, just that said, it's totally at Chevron's request as far as the timing. I do believe that it's -- we're going to have a -- infrastructure gets added in lumps, and I think, as we go to do the first expansion, the processing will require us some substantial stabilization in the field, plus gas and liquid pipelines to be built. So it'll be, I think, a significant capital expenditure initially. And then it'll be lumpy us we move through, but I -- we see continued development as Chevron ramps up and delineates their Duvernay play on their liquid-rich acreage. So I think for now that it's going to be in lumps, and it's going to be for a long period of time. And we'll be working with them -- we do the work at their request, and they come back, and then we build the infrastructure if the -- as we go forward with them.

With plays like this, it's about repeatability and taking cost out of the equation, and so that your question's obviously challenging, because we don't know what commodity prices are going to do. But let's -- if we could assume commodity prices would stay relatively stable, it would make sense to put rigs to work and keep them at work and use -- get that repeatability. And if they're pursuing repeatability, then we get to pursue repeatability. It's entirely conceivable that Duvernay site has 4 or 5 D1 equivalents: MGSs; condensate facilities; stabilization; gathering; processing; and then, of course, driving our Phase IV expansion; and also filling our fractionator. So that's our hope. I'm sure it's Chevron's hope. And commodity prices willing, we think this could be a really exciting decade-long initiative.

Great. And then just want to build off a couple of the comments that you guys had said before, talking about apportionment behind your systems and growth -- capturing growth of $1 billion to $3 billion. When -- how do you see kind of basin takeaway right now as far as constraints overall? And how that trends and when that could lead to kind of more -- the next wave of discrete project announcements from you guys?

Yes. In terms of basin takeaway, I mean, there's obviously a ton of natural gas to take away. We are encouraged with the TransCanada open season to make our Western Canadian gas more competitive. So that's indirectly a good thing for Pembina, very good for producers, and also, I think, a sensible thing for TransCanada to do. A lot of the product that's coming out of the Kakwa area or the Duvernay is condensate. And so there's a lot of running room in terms of condensate demand right now, and of course, we still have a couple hundred, maybe 250,000 barrels a day of condensate being imported. So our view is that condensate's got a lot of running room. And where that condensate demand fills in Alberta, imports would be displaced first. So we don't really see a big constraint on supply in condensates into the basin. And then, as we think about oil pipelines, we're rooting for Kinder Morgan and Enbridge and TransCanada to get the projects done. And that hopefully will, between those 3 projects, create egress for another couple of decades. And then that will create the next platform for us to continue to grow. So we -- I guess, in short, we don't have a lot of concerns about egress right now. We were actually more worried about it some time ago. And on top of everything I just said, there's also rail egress, and it's not well utilized right now, but that is a safety valve as well. So I think we've got a lot of license to keep doing what we've been doing for a long period of time.

Got you. Or even maybe just on a basin level, as far as takeaway just outside of the basin that's from Montney to Edmonton, as far as what that could mean for opportunities for you guys in the next wave of discrete projects.

Well, I mean, as Paul said, in the not-too-distant future, we might need another pipeline between Kakwa -- or Kakwa area into Fox Creek; and then from Fox Creek, and we have the power of our ability, we can add another 300,000 barrels a day or so. So that project's in our gun sight. So we're not at the volume threshold we need to be yet. As Scott said earlier in the call, how the supply/demand of physical barrels, we know the contractual side. But the physical side will become more clear in the third quarter, and that would be a sensible time for us to assess whether there is enough physical barrels to support an expansion.

Great. And then just one last one, if I could. NGL midstream seemed quite strong in the quarter. And I imagine there was some benefit from propane uplift. Just wondering if you see that kind of continue into 1Q '17, propane prices have given back a bit here. Is 4Q '16 a good run rate? Or should we expect a little bit of a down-step in 1Q '17?

Yes. I mean, as you know, Q4 and Q1 are always our strongest quarters in that business unit, just due to the winter heating season. So you're putting me on the spot a little by trying to predict prices for another 2 months. I think it's generally in line with -- Q1's looking generally in line with Q4, but that's going to be dependent on pricing for the remainder of the quarter. Also, as you would have noticed, in our results, we have layered on some incremental hedging. And really, that was to protect the cash flow and the margin as we kind of exited this heavy capital build. So to the extent there is upside, some of that will be offset by hedging.

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

Just have some more questions on the Chevron MOU. I can imagine the number of reasons why an entity like Chevron would want to partner with Pembina, and one of them would also be to kind of minimize their costs. So can you comment on whether the scale of the opportunity for you and the certainty around the dedicated reserves or area allowed you to kind of accept a lower return? Or should we think of it more as kind of a full value chain pass actually translated into a typical or higher return than your smaller projects that you would do historically?

Well, I mean, our view on the reason we got picked was that we have a great safety record. Our reliability is high. And it's no secret that the integrated value chain is a differentiating factor. And having real assets with real fractionators, real pipelines to provide multiproduct service is a differentiating factor. Our ability to construct on time, on budget, all those things, I think, played into it. We can't get too much into the deal. I think Stu's highlighted that some of it's cost of service, some of it's fee-for-service, that the commitments that they have ramped up with, with their call for facilities. But what I would say, Linda, is it's a normal Pembina deal.

Okay, that's helpful. Maybe we can move on to something else then. In terms of your financing plans, in terms of putting in permanent financing beyond the credit facility, how might we think of your current sense of the relative attractiveness of various options, including press? And how you think about kind of prefunding projects as they get built and derisking the financing plan versus avoiding dilution by putting in permanent financing as projects are already built?

Linda, as we look forward to kind of from midyear on or maybe even from start of 2018, we expect to generate around $500 million of cash flow after dividends. And if we just reinvest that and borrow against it, that's $1 billion of cash that we can deploy into projects. So we -- at $1 billion a year of growth at least for the next few years, we really don't need to have the DRIP or do preps or anything. It's just kind of like finishing our program this year. And then we have a great ability to just grow with internally generated cash flow. So that's our plan right now. But if something comes up and we make an acquisition or we get -- we start to grow above that $1 billion a year, then we're going to finance things the way we always do with the combination of long-term debt, DRIP and preps.

Okay. And maybe just one final cleanup question. As we look out over 2017, should we be mindful of any major facility maintenance or expansion outages? And if so, kind of what quarter? And what might the financial impact be?

Yes. The hard stuff, once we get to the middle of the year, the hard stuff is, knock on wood, behind us. I mean, we've done the integrity work. We have been spending $150 million a year on pipeline integrity for a bunch of years. All-in service are being readied by the middle of this year, and we're going to put a whole bunch of brand-new facilities into service. And yes, there'll be some commissioning headaches the way there are, but everything we have done to get to the end of this year will put our facilities in as-new condition. And that's what's so exciting about it is, our expenses, we expect our integrity burn and expenses to start to drop while our revenue is going up at the same time, and that's kind of what's exciting about 2018 for us.

Your next question comes from the line of Robert Catellier of CIBC World Markets.

I have a question I think you've partially answered in responding to Linda, but I'm curious how the Duvernay agreement with Chevron might impact how you look at dividend policy, given that it is a binding agreement but you don't really have certainty in terms of the timing of the capital call. So do you see a need to maintain a lower payout ratio in order to be able to respond?

No. I mean we're -- the Chevron deal is obviously a major deal, and we've said pretty much as we can. But nevertheless, it's still a pretty small part of Pembina, and it's not going to influence our dividend policy. If we keep growing our dividends 6-ish percent a year with our guardrail of 80% fee-for-service, and we expect our payout ratio to keep dropping over the foreseeable future to the point where our dividend payments are -- entirely come out of fee-for-service, and the Chevron deal won't change that. It's well within the guardrails of staying on track.

Okay. And then just with respect to the PDH FEED. I think the original plan was to go to into a FEED by the end of the year, and I'm just curious why there was a little bit of a timing delay there.

Rob, it's Stu. So we probably underestimated the amount of time. As you go from the feasibility study into the FEED work, the first bit of engineering that needs to be completed is with your technology providers. That is about a 4- to 6-month process of them working through their engineering and their work. And we probably underestimated initially that time frame. And so upon further work, we've added that and you have now the time. You're right. Initially we thought we'd be going into the -- declaring our FID process before that, but we've had to build in that extra schedule.

The other thing is, Rob, we've elected, along with our partner, to get much more detail into the agreement. So at a time when we announce FEED, we have a lot of granularity on how the joint venture is going to work, whose jobs, different aspects of it are. And so it's not going to be a mystery when we come out of FEED how things are going to work. And it's a pretty significant amount of money. A FEED could reach $100 million, and so both sides agree that we better know what the deal is before we spend that money. So it's been time well spent.

Okay, that's helpful. And then my follow-up question here is on the impact of the Line 2A outage. What impact do you think that will have on industry activity, specifically on Pembina?

I can't comment on it. I don't know.

Yes. I mean, we haven't felt anything yet upstream, so...

Your next question comes from the line of Ben Pham of BMO.

I wanted to follow up on your comments about what you characterize as a normal Pembina return, because that's been changing a bit over the years. And with the Chevron agreement, you've mentioned potential opportunities with cost of service on your pipelines. And are you guys looking -- probably just going back to Linda's initial question, are you looking at returns more from an integrated consolidated perspective now, maybe a little bit more than you have in the past, when you're underwriting new projects?

I think if you've talked to us over the last 3 years, you know our deals are very integrated. And where the profit lies within any business units is almost a little arbitrary. And when we -- if you kind of go back 3 years, and we talked about our $6 billion growth profile and we said it would add $600 million to $950 million of EBITDA, there is your implied multiple of what a normal Pembina deal is. And whether that profit ends up in the pipeline or the gas plant or the frac facility or the marketing will be situation-specific. But it's the reason we have integrated value chains, because we can touch the molecules many times and hopefully make above-average returns. But I think it's pretty well delineated what a normal Pembina deal is if you look back at the last $6 billion we spent.

Okay. And just thinking about with this new agreement and FID on the PDH in 12, 18 months, you kind of square us up with first module, potentially. Are you perhaps less enthusiastic about petrochemical than maybe before, because it is potentially a little more [ph] concern than the returns in the construction?

No. Actually, the more we learn, the better we like it. It's kind of going the other way. We're getting a lot of confidence from the engineering firms we're talking to about the turnkey, a good portion of this project. We've got confidence that the market will be there, North American market eventually, but the international market perhaps in the short term. We're getting confidence with our partner and their capabilities. And we're getting interest from the producing community to turn their propane into polypropylene on a fee basis. So all those things combined, our return expectations really haven't changed over the last year, but I think what's making us feel better and better is we are perceiving that we can reduce the risk as we contemplate these types of facilities. And in fact, that's -- if you kind of go back when Pembina entered the fractionation business, most of the agreements were frac spread business. And now, roll forward 5 years, and probably 70% going on 80% of our frac capacity is on a fee basis. So we do have a track record of changing the way businesses operate. And we believe that, to a point, we can also do that in the petrochemical business.

Okay. And just a quick final question. On the NGL Midstream margins, the $112 million, if you compare that to Q3 and you look at just a change in frac spreads over those -- over that quarter, it seems to be a little bit inconsistent with some of the sensitivity announcements that you've -- you put out there. So is that mostly the hedges that you've -- you highlighted earlier that's driving the delta?

I think -- yes, that hedge is also -- remember that RFS II is not really a frac spread business. It's a fee-for-service business with some marketing revenue that is essentially more like commission versus the frac spread.

Your next question comes from the line of Andrew Kuske of Crédit Suisse.

Maybe just following up on the operating margins in the Midstream business. So to the degree that you see this as really being a structural expansion versus a cyclical one, is it fair to really characterize as that business is now much more structurally strong from a margin standpoint quarter after quarter?

Are you referring -- I mean, the business as a whole is becoming ever more fee-for-service-oriented, absolutely. The way we're running it now with some pretty significant hedging, I think that is taking volatility out of the business. But the original asset base we bought when we merged with Provident, that cash flow stream, that character really hasn't changed too much. What's changed is everything else around that business is diluting that volatility in our overall cash flow stream.

Yes. I mean, Andrew, if I just look at Q4 of '16 versus Q4 of '15, 50% of the difference on Redwater was really fee-for-service uptick from RFS II and a few incremental projects. But of course, the uplift in the East is strictly marketing because that's our Empress East assets. So overall, about 25% to 30% of the overall business was -- the increase was fee-for-service, the remainder was commodity exposed. In terms of the different...

Okay, that's very helpful -- sorry. Okay, great. And then maybe a broader question, and it speaks to just the resiliency you're building up in the business and the fee-for-service model. Clearly, you are positioning yourself for a lot of growth opportunities in the west, whether it's the PDH, the PP and with the activities you have going on with a number of the producers and your land position that you're building. And how do you think about allocating capital in, effectively, your own backyard versus any opportunities you see just elsewhere or in any basin in North America at this point in time? Do you have a temptation to look elsewhere and really build up another business? Or enhance what you've got elsewhere, say, around Sarnia for example?

Well, I mean, we would like to be more diversified, and some day, we hope to do that. But where we are now, is brownfields are always the most accretive; then greenfields; then acquisitions; and then, usually, what's least accretive because we don't have the integrated value chain to squeeze extra dollars is acquisitions or greenfields in a different basin. So we tend to do things in that order, but at some point, we would like to be in more than one basin, for sure. And we'd actually like to have a different currency cash flow stream at some point as well. But we look at everything, but just nothing so far. I mean, Vantage Pipeline came up a few years, so that met the criteria, but nothing right now is meeting our criteria.

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

Just in terms of the Montney, previously, you'd talked about producers coming to you. Some wanted more capacity, some wanted less, and you were really just focused on, I guess, trading amongst the customers. I'm just wondering, I guess, with the 2017 capital budgets out and generally up in recent well results, are you seeing demand now really for just net increase and trying to eat away at the remaining capacity on the system?

Paul can...

Yes. I think it's starting to -- I guess the swap of capacity is just starting to settle down. I'm not sure -- that's probably in part that people could see it coming, what they needed, so they've basically completed their business. But as we talked about earlier, we have had, I'll say, a material amount of interest on the capacity, which is why we're getting close to, I guess, a decision on our Phase IV. So it'll be ever evolving, I think, for the next -- probably the next year as -- once a bunch of facilities come on and people see how much room there is. As Mick talked about earlier, we really want to see what the physical volumes are before we make any big moves. We'll...

Understand. And -- oh, sorry, go ahead, Paul.

No, go ahead.

So just so I'm clear on Phase IV, because there were a few comments earlier about, it sounded like there was newbuild and powering up. So Phase IV, though, are you looking at that as essentially the pump station expansion of Phase III? Or are we talking about substantially a newbuild of capacity?

You're bringing out a good point. We need to name things so that you guys can understand it. Your -- Phase IV used to be what the -- was just pumps, just powering up the pipe between Fox and Namao. And now we have a separate part of that project, which is essentially looping from Kakwa in, because that's really where we're short of capacity. So I don't know what -- we should maybe call that Phase V, which is a separate pipeline project. And both are under investigation right now, but you're absolutely right. There is the power-up, which was what we talked about being Phase IV; and now there's also your shorter capacity kind of from Kakwa in. Because really, the likes of Seven Gen are just really -- that whole Seven Gen phenomenon has happened since we announced Phase III, and we frankly built the pipes too small out there by a lot. So that's under investigation as well.

Okay. And so when you're thinking about kind of this Phase V concept, is that really, from your perspective, more bottleneck-driven and almost you need to do it? Or is it more of a strategic decision to kind of prebuild parts of the system to continue to maintain that advantage you have over competitors of some of that spare capacity?

That -- just back to Phase III, you might recall, we built all those pipes upstream at Fox Creek, say, between Kakwa and Fox Creek a number of years ago. So they've been -- that part of Phase III has been in service for quite some time, and we do not have enough capacity there. Like barrels are going around because they can't get on to those pipes. So we're already short of capacity there. So our Phase III is done, and it's not adequate. So it's not strategic at all. It's just what's the critical mass to justify Phase V. I mean, you can't build a brand new pipeline for 10,000 barrels a day. You need critical mass, and we're not quite at the critical mass for what we've decided during this call to call Phase V.

Okay. Maybe I'll just finish with a question here on the PDH/PP project. I think, historically, you've talked about wanting to contract half of your half on a fee basis and being comfortable within the guardrails of having roughly the other half exposed. I guess, as you think about what's developed in your business, you're thinking about things like Phase IV and V, which, I assume, would be fee-based and the Duvernay agreement here with Chevron. Does that cause you to directionally be more comfortable being open then on that facility? Or coming back to maybe the capital allocation question, if you can get all the sea-based stuff in the rest of your business, you don't feel the need to take any commodity or material commodity exposure if you don't have to?

It's an interesting question. I mean, we could warehouse taking our half entirely as a commodity business if we wanted to. That -- the guardrails would show we could do that. But using all of our 20% room for one project, it really does limit what we might be able to do next, right? So we're still gunning for half of our half to be fee-based because there might be other projects that we want to do and take out -- take a little bit of a position to get them built. So we thought about it. We could do that, but we're still hoping to go half fee-based just to create room for future initiatives.

Your next question comes from the line of Patrick Kenny, National Bank Financial.

I think that Duvernay has been well covered, so I'll switch gears and wanted to get your thoughts on the Pipestone region. It looks like that will be one of the hot pockets of the Montney going forward, and obviously, it'll be quite competitive here. But just wanted to get a sense as to, a, is that a play that you're going after aggressively? And b, what your main competitive advantages might be.

Yes. It's a play that is of significant interest to Pembina. Obviously, from a -- speaking first on the pipe side, our Phase III expansion has -- a lot of the Montney players are Phase III customers already. We've been working with them for a number of years as they've grown their production, as the Montney's matured, from Alberta, all the way through into Northeast B.C. Paul mentioned earlier, our Northeast B.C. expansion, that's largely Montney-focused and driven. There's no question in my mind that Montney is a world-class play. There's going to be additional infrastructure requirements. We're excited about where we're sitting with our pipeline. With our gas processing expertise, with our value chain, we think we can work with Montney producers, both large and small, giving them access to the infrastructure, getting that growth and the value chain that we can bring to the table. So we're going to be aggressive, I think, looking at Montney opportunities. We love the resource itself. We love the liquid content in that gas and are excited about continuing to work with our existing customers and future customers.

All right, Stu. And then this might be a bit of a tough question to quantify, but I'll ask it anyway. Any risk or a material impact that you might see on your NGL marketing business from the border adjustment tax if it does get implemented?

Who knows? I think you're right. It's very hard to assess whether that would happen and in what form it would happen. And who would ultimately bear the cost for that is the second equally challenging question, whether it's Pembina or the customers or a combination, really difficult to answer. But I think the one thing we can say is it does support having alternative market for Alberta hydrocarbons. It's just a classic example that our basin has all its eggs in one basket, and we've got to change that.

I'm not sure if you've ever provided this or not, but just so we have a back pocket, what percentage of your NGL sales on a normalized basis might be in the U.S.?

It's high. I mean, if you look at Alberta on the whole, I think we have produced, what, 200,000 barrels a day, Stu, something like that?

Yes, probably on the high side there, but probably in the 150,000 to 200,000. Yes.

Yes. By the time we've done all our expansions and we consume 30,000...

30,000 local.

30,000 locally, so there's your ratio for the basin, and we're the biggest player in that basin. So that's -- haven't scienced it, but it's probably a decent guess on what we're doing. And again, that's where the polypropylene plant makes a difference, because 20, 22 of that -- of the new stuff could be used locally and propane exports could reduce the U.S. exports as well. So we're continuing to work on both of those.

I mean, we're not the only ones. I mean, obviously, all of the frac operators are largely putting their barrels into railcars at this point in time and moving them to available markets. We do move in the Eastern Canada, obviously, through our Eastern assets, but we continue to load railcars and access markets.

Yes. We -- Pembina thinks it has a leading role to play in balancing without a balance. A basin that produces 7x as much NGLs as it consumes. We want to play a leading role in trying to balance that market out. Well, I think we've got to wrap it up now, Haley. Thanks, everybody. We do very much appreciate and value your support. Thanks for being part of this journey. So far, so good. Another bunch of months and we will have the wall of cash flow play starting to come at us, and it'll be a lot of fun. So anyways, have a great weekend, and thanks for your support.

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