Good morning. My name is Jody, 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. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then 1 on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. Scott Burrows, Vice President of Finance and Chief Financial Officer, you may begin your conference.
Thank you, Jody. 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, Stuart 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 year in a row we've had no lost time employee incident. We completed approximately CAD 1.2 billion in major projects, representing a meaningful portion of our secured growth projects, including our second Redwater fractionator, expansions of two 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 CAD 3 billion and are scheduled to be completed by the middle of this year. In 2016, we secured over CAD 750 million in new growth, which helped to augment our competitive positioning in two of the basin's premier resource plays, the Alberta Montney and the Duvernay. We have begun work on the next wave of growth opportunities. We completed our feasibility study for our PDHPP project, which Stu will discuss later on in the call. We purchased approximately 22 acres of highly strategic lands in the Alberta Industrial Heartland, directly adjacent to our Redwater site. 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 CAD 4 billion in projects, three-quarters 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 and 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 CAD 342 million, an all-time quarterly high, and CAD 1.189 billion for the year, as a result of stronger performances across all businesses, including new assets placed into service and the Kakwa acquisition. Respectively, adjusted EBITDA was 27% and 21% higher than the comparable periods last year. The strong business performance, partially offset by additional preferred share dividends, resulted in adjusted cash flow of CAD 292 million for the quarter and CAD 986 million for the year. Per share metrics were largely in line with last year as a result of share issuances to partially fund our organic program, part of which won't contribute to results until later this year, and partially to fund the Kakwa 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, to the comparable periods in 2015. Increased revenue volumes from new assets in the Kakwa acquisition translated to operating margin of CAD 60 million for the fourth quarter, 82% higher than the comparable quarter last year. For the year, gas services recorded operating margin of CAD 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 CAD 112 million and CAD 334 million, respectively. Operating margin for crude oil midstream activities increased to CAD 46 million compared to CAD 37 million for the comparable quarter as a result of increased storage revenue. For the full year, operating margin was 5% lower at CAD 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 CAD 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 CAD 494 million, 23% higher than last year as a 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 previous periods as expected. Pembina continues to maintain one of the strongest balance sheets in our sector, further supported by a very strong liquidity position. For the last 12 months, Pembina's debt-to-EBITDA ratio was 3.5 times.
After year-end, we completed a very successful CAD 600 million medium-term note offering, and as of February 22nd, our CAD 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 III 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 of 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 continue 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 NEBC Expansion. This CAD 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 Alterra's lateral is also underway, which will connect into the NEBC Expansion. Both of these projects are expected to be completed by the end of the year. In 2016, we completed two projects within our oil sands and 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 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 at our 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%-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 of 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 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 cubic feet per day Duvernay I facility. At the field hub, all required regulatory approvals have been received. Engineering is 55% complete, and 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 CAD 240 million. We are very pleased 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 development remains contingent upon Chevron sanctions 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 were also encouraged by the conditional award of 300 million in royalty credits from the Alberta government's Petrochemicals 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 applications, a Class 3 cost estimate, 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's Sturgeon 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 CAD 600 million-CAD 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 CAD 1.2 billion of major projects we completed in 2016. Further, with approximately CAD 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.
Thank you very much. If you would like to ask a question at this time, please press star then the number one on your telephone handset. We'll pause briefly to compile the Q&A roster. Our first question comes from David Galison, Canaccord Genuity. Your line is open.
Hi, good morning, everyone. 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 they be a focus on maybe a staged increase in the dividend? Or just your thoughts on how to use the cash.
I think the answer is yes. We've been growing our dividends 4%-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. Yeah, we're going to continue growing the dividend, and I think 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 least CAD 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 CAD 3 billion, and some years it might be CAD 1 billion, but we've been generating that kind of growth even through these last two recessionary years.
We're pretty confident we can have a use of proceeds towards growing our asset base.
Okay, 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 the agreements are cost of service, 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. Will the FFL be dedicated to just servicing Chevron, or will they be open to other volumes as well if it should warrant?
One of the big important points for Pembina was to ensure that we had 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.
Okay. All right. Thank you very much.
Your next question comes from the line of Rob Hope of Scotiabank. Your line is open.
Good morning and congratulations on a good year.
Thank you.
Just taking a look up into the Montney, into the Duvernay, we're seeing a number of third-party plans 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 threes?
Yeah. I mean, every time a new plant is built, sorry, it's Paul. At this point, they come to us for more service. We're in the middle of looking at the feasibility of our Phase IV, which would be, we've talked about it before, some small pipeline segments and powering up the pipeline that we're building right now.
Yeah. We're doing the engineering, and we're clearing land for Phase IV right now. Doesn't mean it's going to go ahead. We need a certain volume threshold, but it's certainly possible.
Can you share where you are on the volumes and where you need to be in the volumes for Phase IV? If you're clearing land already, I would imagine you're getting closer.
No. You know how the producing community is. They're very cautious when they sign up. Once they sign up, they want the pipeline right away. We are, on our account, we're spending a relatively modest amount of money, I think about CAD 20 million, to make the time between the date they sign and the on-stream date a one-year period versus a multi-year period. 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. One last question, and I'll jump back in the queue. Looking at it another way, the CAD 600 million and CAD 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 north towards CAD 700 million-CAD 800 million.
Well, Rob, if we just go through the math again, remember the CAD 600 million is really the contractual threshold that assumes no volume. The upside from CAD 600 million to CAD 900 million is a few things. It's volumes through CDH, which I think, as we mentioned in this call, we're already starting to see volumes go through CDH. There's marketing revenue from both RFS II and RFS III. 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. I think it's fair to say that, we will be above the bottom of that CAD 600 million range.
Yeah, there's significant apportionment right now behind our system. 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.
Excellent. Thank you.
Your next question comes from the line of David Noseworthy of Macquarie. Your line is open.
Great. Thank you very much. Let me add my congratulations on the great financial results and ongoing safety track record.
Thanks, David.
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?
Yeah, David, it's Stu again. 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 12-18 months that the first service call will be coming in. It is totally at Chevron's call and subject to all their internal sanctioning. 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.
I think we've started some engineering on
Yep
on the infrastructure already.
Yeah, we've spent some money in advance, recognizing, obviously our D1 facility in the NGL, the infrastructure we're building to date, plus looking at some enhancements to that spend. We're spending some preliminary engineering dollars. Again, it's mixed in on the pipeline so that we can move forward quickly with the designs and try and be shortening that in-service time.
All right. 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 of projects going forward?
At this point, the agreement that was covered included all of the infrastructure and the overriding structure of the arrangement. Upon their sanctioning, all the agreements are ready to be completed, and they're in execution phase as they ask for that infrastructure.
David, the land dedication is binding.
Yeah.
If they are 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.
Okay.
The land dedication is the done deal.
Got it. Okay. Maybe just trying to stay on the gas side of things, but just on another area. Your Kakwa plant acquisition came with the design for that 6-18 plant. Has there been any positive development on that front, or has the change in ownership really cooled the opportunity for further growth there?
Like most things, we've continued to work with Seven Generations, and I think like most things, as you have a new acquirer, it takes them a bit of time to sort out the acquisition moving forward. 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. We're excited about moving forward with Seventh Gen in a meaningful way here in the next few years.
David, I'd just add, that plant wasn't completely capable of being filled given its front-end liquids capability. We're spending significant money, I think CAD 50 million, to enhance the ability for that plant to take liquids. That's well underway. When we ran economics, we thought of a three-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.
That's great to hear. I'll get back in the queue, but congratulations.
Thanks.
Your next question comes from the line of Jeremy Tonet of J.P. Morgan. Your line is open.
Good morning.
Morning.
Morning.
Just wanted to follow up on the Chevron opportunity a little bit more. As far as the spending, as you guys envision it, is it fair to think a couple of years out, it could start to tick up and then be a multi-year 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 to emphasize, it's totally at Chevron's request as far as the timing. I do believe infrastructure gets added in lumps, and I think as we go to do the first expansion, the processing will require some substantial stabilization in the field, plus gas and liquid pipelines to be built. It'll be, I think, a significant capital expenditure initially, and then it'll be lumpy as we move through. We see continued development as Chevron ramps up and delineates their Duvernay play on their liquid-rich acreage. I think it's going to be in lumps, and it's going to be for a long period of time. We'll be working with them. We do the work at their request, then they come back, and then we build the infrastructure as we go forward with them.
With plays like this, it's about repeatability and taking cost out of the equation. Your question's obviously challenging because we don't know what commodity prices are going to do. 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 get that repeatability. If they're pursuing repeatability, then we get to pursue repeatability. It's entirely conceivable that Duvernay site has four or five D1 equivalents: MGS, condensate facilities, stabilization, gathering, processing, and then, of course, driving our Phase IV expansion and also filling our fractionator. 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. Thanks for that. Just wanted to build off a couple of the comments that you guys had said before, talking about apportionment behind your systems and capturing growth of 1-3 billion. How do you see basin takeaway right now as far as constraints overall, and how that trends, and when that could lead to the next wave of discrete project announcements from you guys?
Yeah. In terms of basin takeaway, there's obviously a ton of natural gas takeaway. We're encouraged with the TransCanada open season to make our Western Canadian gas more competitive. 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 Cardium area or the Duvernay is condensate. There's a lot of running room in terms of condensate demand right now. Of course, we still have a couple of hundred, maybe 250,000 barrels a day of condensate being imported. Our view is that condensate's got a lot of running room, and were the condensate demand built in Alberta, imports would be displaced first. We don't really see a big constraint on supplying condensate into the basin.
As we think about oil pipelines, we're rooting for Kinder Morgan and Enbridge and TransCanada to get their projects done. That hopefully will, between those three projects, create egress for another couple of decades, and then that'll create the next platform for us to continue to grow. 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. On top of everything I just said, there's also rail egress. It's not well-utilized right now, but that is a safety valve as well. 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. Even maybe just on a basin level as far as takeaway just outside of the basin from Namao to Edmonton, as far as what that could mean for opportunities for you guys in the next wave of discrete projects.
Well, as Paul said, in the not too distant future, we might need another pipeline between Kakwa or Kakwa area into Fox Creek. From Fox Creek in, we have the power-up ability. We can add another 300,000 barrels a day or so. That project's in our gunsights. We're not at the volume threshold we need to be yet. As Scott said earlier in the call, how the supply and 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's enough physical barrels to support an expansion.
Great. 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 continuing into 1Q17. Propane prices have given back a bit here. Is 4Q16 a good run rate, or should we expect a little bit of a down step in 1Q17?
Yeah. As you know, Q4 and Q1 are always our strongest quarters in that business unit, just due to the winter heating season. You're putting me on the spot a little by trying to predict prices for another two months. I think it's 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. To the extent there is upside, some of that will be offset by hedging.
That makes sense. That's it for me. Thank you.
Your next question comes from the line of Linda Ezergailis of TD Securities. Your line is open.
Thank you. Just have some more questions on the Chevron MOU. I can imagine a 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. 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 path actually translated into a typical or higher return than your smaller projects that you would do historically?
Well, 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. Having real assets, real fractionators, real pipelines to provide multi-product 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 ramp up with their call for facilities. What I would say, Linda, 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 pref, and how you think about kind of pre-funding projects as they get built, and de-risking 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 mid-year on or maybe even from start of 2018, we expect to generate around CAD 500 million of cash flow after dividends. If we just reinvest that and borrow against it, that's CAD 1 billion of cash that we can deploy into projects. At CAD 1 billion a year of growth, at least for the next few years, we really don't need to have the DRIP or do prefs or anything. It's just kind of like finishing our program this year. Then, we have a great ability to just grow with internally generated cash flow. That's our plan right now. If something comes up and we make an acquisition or we start to grow above CAD 1 billion a year, then we're going to finance things the way we always do with a combination of long-term debt, DRIP and pref.
Okay, thank you. 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?
Yeah. Once we get to the middle of the year, the hard stuff is, knock on wood, behind us. We've done the integrity work. We have been spending CAD 150 million a year on pipeline integrity for a bunch of years, all in service of being ready by the middle of this year. We're going to put a whole bunch of brand new facilities into service. Yes, there'll be some commissioning headaches, the way there are. 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's going up at the same time, and that's kind of what's exciting about 2018 for us.
Great. Thank you.
Your next question comes from the line of Robert Catellier of CIBC World Markets. Your line is open.
Hi. Good morning. I have a question I think you 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 it is a binding agreement, but you don't really have certainty in terms of the timing of the capital call. Do you see a need to maintain a lower payout ratio in order to be able to respond?
No. The Chevron deal is obviously a major deal, and we've said pretty much as 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 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. The Chevron deal won't change that. It's well within the guardrails of staying on track.
Okay. Just with respect to the PDH feed, I think the original plan was to go into a feed by the end of the year. I'm just curious why there was a little bit of a timing delay there.
Rob, it's Stu. 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 4-6-month process of them working through their engineering and their work. We probably underestimated initially that timeframe. Upon further work, we've added that and yeah, now the time. You're right. Initially, we thought we'd be going into the feed, declaring our FID process before that, but we've had to build in that extra schedule.
The other thing is Rob, we elected along with our partner to get much more detail into the agreement. 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. It's not going to be a mystery when we come out of FEED how things are going to work. It's a pretty significant amount of money. FEED could reach CAD 100 million. Both sides agreed that we better know what the deal is before we spend that money. It's been time well spent.
Okay. That's helpful. My final 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.
We haven't felt anything yet upstream, so.
Okay. Thank you.
Your next question comes from the line of Ben Pham of BMO. Your line is open.
Okay. Thanks. Good morning. 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. With the Chevron agreement, you've mentioned potential opportunities with cost of service on your pipelines. Are you guys looking and 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 talked to us over the last 3 years, you know our deals are very integrated, and where the profit lies within any business unit is almost a little arbitrary. If you go back 3 years, and we talked about our CAD 6 billion growth profile, and we said it would add 650-950 of EBITDA, there's your implied multiple of what a normal Pembina deal is. Whether that profit ends up in the pipeline or the gas plant or the frack 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. I think it's pretty well delineated what a normal Pembina deal is, and if you look back at the last CAD 6 billion we spent.
Okay. Thanks for that. Just thinking about with this new agreement and FID on the PDH in 12-18 months, it kind of squares up with first module potentially. Are you perhaps less enthusiastic about petrochemical than maybe before? Because it is
You know, potentially put more uncertainty in 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 being able to 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 it will be in the short term. We're getting confidence with our partner and their capabilities. We're getting interest from the producing community to turn their propane into polypropylene on a fee basis. All those things combined, our return expectations really haven't changed over the last year. 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.
In fact, if you kind of go back when Pembina entered the fractionation business, most of the agreements were frac spread business. Now, roll forward 5 years and probably 70% going on 80% of our frac capacity is on a fee basis. 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. Thanks, Ryan. Just a quick final question on the NGL midstream margins, the CAD 112 million. If you compare that to Q3 and you look at just the change in frac spreads over that quarter, it seems to be a little bit inconsistent with some of the sensitivity analysis that you've put out there. Is that mostly the hedges that you highlighted earlier describing the delta?
I think, yeah, that's hedges. 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 a frac spread.
Okay. All right. Okay, thanks for taking my questions.
Your next question comes from the line of Andrew Kuske, Credit Suisse. Your line is open.
Thank you. Good morning. Maybe just following up on the operating margins on the midstream business. To the degree that you see this as really being a structural expansion versus a cyclical one, is it fair to really characterize that business is now much more structurally strong from a margin standpoint quarter after quarter?
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. The original asset base we bought when we merged with Provident, that cash flow stream, the 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.
Yeah. Andrew, if I just look at Q4 of 2016 versus Q4 of 2015, 50% of the difference on Redwater was really fee-for-service uptick from RFS II and a few incremental projects. Of course, the uplift in the East is strictly marketing because that's our Empress East asset. Overall, about 25%-30% of the overall business was the increase with fee-for-service. The remainder was commodity exposed.
Okay. That's very helpful.
In terms of the difference.
Okay. Great. 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're positioning yourself for a lot of growth opportunities in the West, whether it's the PDH, the PP, and the activities you have going on with a number of the producers and your land position that you're building. How do you think about allocating capital in effectively your own backyard versus any opportunities you see just elsewhere 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, we would like to be more diversified. Someday we hope to do that. 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. We tend to do the things in that order. At some point we would like to be in more than one basin for sure. We'd actually like to have a different currency cash flow stream at some point as well. We look at everything, but just nothing so far, I mean, Vantage Pipeline came up a few years, so that met the criteria. Nothing right now is meeting our criteria.
Okay, great. Thank you.
Your next question comes from the line of Robert Kwan of RBC Capital Markets. Your line is open.
Just in terms of the Montney, previously you talked about producers coming to you, some wanted more capacity, some wanted less, and you were really just focusing mostly on trading amongst the customers. I'm just wondering, I guess, with the 2017 capital budgets out in general, yep, and 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, want to.
Yeah. I guess the swap of capacities is starting to settle down. I'm not sure. It's probably in part that people could see it coming and what they needed, so they've basically completed their business. As we talked about earlier, we have had, I'll say, a material amount of interest in new capacity, which is why we're getting close to, I guess, a decision on our Phase IV. It'll be ever-evolving, I think, for probably the next year, once the 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.
Understood.
We-
Oh, sorry, go ahead, Paul.
No. Go ahead.
Just so I'm clear on Phase IV, because there were a few comments earlier about, sounded like there was new build and then powering up. Are you looking at that as essentially the pump station expansion of Phase III, or are we talking about substantially a new build of capacity?
You're bringing out a good point. We need to name things so that you guys can understand it.
Mm-hmm.
You're 100%. Phase IV used to be with just pumps, just powering up the pipe between Fox Creek and Namao. 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. I don't know, we should maybe call that Phase V, which is a separate pipeline project. Both are under investigation right now. You're absolutely right. There's the power-up, which was what we talked about being Phase IV, and now there's also, you are short of capacity from Kakwa in, because really, the likes of 7Gen are just really. That whole 7Gen phenomenon has happened since we announced Phase III, and we frankly built the pipes too small out there by a lot. That's under investigation as well.
Okay. 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 pre-build parts of the system to continue to maintain that advantage you have over competitors of some of that spare capacity?
Just back to Phase III, you might recall we built all those pipes upstream of Fox Creek, say between Kakwa and Fox Creek, a number of years ago. That part of Phase III has been in service for quite some time, and we do not have enough capacity there. Barrels are going around because they can't get onto those pipes. We're already short of capacity there. Our Phase III is done, and it's not adequate. It's not strategic at all. It's just what's the critical mass to justify Phase V? 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 PDHPP 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 fee-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. We could warehouse taking our half entirely as a commodity business if we wanted to. The guardrails would show we could do that. Using all of our 20% room for one project, it really does limit what we might be able to do next, right? 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 a little bit of a position to get them built. We've thought about it. We could do that, but we're still hoping to go half fee-based just to create room for future initiatives.
Got it. Thank you very much.
Your next question comes from the line of Patrick Kenny, National Bank Financial. Your line is open.
Thank you. Morning, guys. I think the Duvernay has been well covered, so I'll switch gears and wanted to get your thoughts on the Pipestone region. Looks like that'll be one of the hot pockets of the Montney going forward, and obviously it'll be quite competitive here. 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?
Yeah, it's a play that is of significant interest to Pembina. Obviously, speaking first on the pipe side, our Phase Three expansion has a lot of the Montney players as our Phase Three 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, the 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, getting them access to the infrastructure, getting that growth and the value chain that we can bring to the table.
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. Thanks, Stu. This might be a bit of a tough question to quantify, but I'll ask it anyway. Any risk or 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. 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. I think the one thing we can say is it does support having alternative markets 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. If you look at Alberta on the whole, I think we produce, what, 200,000 barrels a day, Stu? Something like that?
Yeah, probably on the high side there, but probably 150,000-200,000.
Yeah. By the time we're done all our expansions and we consume 30-
30,000
locally. There's your ratio for the basin, and we're the biggest player in that basin. I haven't science'd it, but it's probably a decent guess on what we're doing. Again, that's where the polypropylene plant makes a difference because 22% of the new stuff could be used locally and propane exports could reduce the U.S. exports as well. We're continuing to work on both of those.
We're not the only ones. Obviously, all of the frac operators are largely putting their barrels into rail cars at this point in time and moving them to available markets. We do move into Eastern Canada, obviously, through our Eastern assets. We continue to load rail cars and access markets.
Yeah. Pembina thinks it has a leading role to play in balancing an out-of-balance basin that produces seven times as much NGL as it consumes. We want to play a leading role in trying to balance that market out.
All right. That's great. Appreciate the color. That's all I had.
Well, I think we've got to wrap it up now, Hailey. Thanks, everybody. We do very much appreciate and value your support. Thanks for being part of this journey. Far so good. Another bunch of months and we will have the wall of cash hopefully starting to come at us, and it'll be a lot of fun. Anyways, have a great weekend, and thanks for your support.
This concludes today's conference call. You may now disconnect.