Pembina Pipeline Corp (PBA) 2016 Q3 法說會逐字稿

Good morning. My name is Sharon, and I will be your conference operator today. At this time, I would like to welcome everyone to the Pembina Pipeline Corporation, 2016 third-quarter results conference call.

(Operator Instructions)

Mr. Scott Burrows, Vice President, Finance and Chief Financial Officer, you may begin your conference.

Thank you, Sharon. Good morning, everyone and welcome to the Pembina's conference call and webcast to review our third-quarter 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; Stub Taylor, Pembina's Senior Vice President NGL and Natural Gas Facilities; and Paul Murphy, Pembina's Senior Vice President Pipelines and Crude Oil Facilities.

Before passing the call over to Mick for review of quarterly highlights, I'd remind you that some of the comments made today may be forward-looking in nature and are based on Pembina's current expectations, estimates, projections, risks, and assumptions. 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.

I'd wanted to quickly note a few of the successes the third quarter brought for Pembina. Overall, the real highlight for me is the great progress our construction teams are making on growth projects, essentially, all of which are trending on time and on budget, or even better.

In 2016, we expect to bring approximately CAD1.2 billion worth of the projects into service. This leaves us with around CAD4 billion of projects remaining to be brought into service in 2017. The vast majority will be completed around the middle of the year.

Pembina's largest greenfield project, to date, the CAD2.4 billion Phase III expansion is over 50% complete. Mechanical construction of our third fractionator at Redwater is 75% complete. Construction on a variety of terminalling and storage infrastructure, in support of the North West's Redwaters planned refinery, is 50% complete. Civil work associated with the Canadian Diluent Hub is 70% complete.

Looking at our operations, our gas plant set a new revenue volume record of 894 million cubic feet per day, including physical volumes at the Musreau Deep Cut. Volumes reached over 1 billion cubic feet per day in gas services. With the record level of construction activity underway, Pembina's focus remains on executing safely, and delivering the remainder of our secured-growth projects on-time and on-budget.

Nearly all these projects are underpinned by long-term fee-for-service contracts, and as such, we have a visibility of -- significantly high-quality cash flow growth. Coupled with a strong balance sheet and continued access to capital, Pembina is well-positioned to continue driving long-term shareholder value.

Scott, back to you for our financial results.

Thanks, Mick. Pembina continues to deliver improved financial and operational performance, in nearly all business segments realizing higher revenue volumes and operating margins. Pembina generated adjusted EBITDA of CAD287 million in the third quarter, a 17% increase compared to CAD245 million in the same period last year. So far in 2016, Pembina generated adjusted EBITDA of CAD847 million, a 19% increase over the CAD714 million in the first nine months of 2015.

Increased quarterly and year-to-date results were driven by increased volume on Pembina conventional pipeline system, higher throughput within our gas services segment, as well as greater contribution from our NGL Midstream business. Higher gross profits were partially offset by higher taxes, net finance costs, and general and administration expenses resulting in earnings of CAD120 million or CAD0.25 per share in the third quarter of 2016. This compares to CAD113 million with CAD0.29 per share, for the same period last year.

Earnings for the first nine months of 2016 were CAD335 million, compared to CAD276 million, or a 21% higher-than-comparable period in 2015. This increase was as result of higher gross profits and lower taxes, which were somewhat offset by higher net finance costs, and general and administrative costs. Comparable periods in 2015 benefited from a gain on revaluation associated with Pembina's convertible [divestitures] of CAD30 million and CAD40 million, respectfully; whereas the 2016 periods, we recognized a loss of CAD3 million and CAD32 million.

Cash flow from operating activities increased to CAD247 million in the third quarter of 2016 compared to CAD187 million in the same period last year. This was largely driven by increased operating margin, and lower cash taxes paid. Year-to-date, cash flow from operations increased to CAD791 million compared to CAD516 in the same period of 2015, as result of increased operating margin and lower cash taxes paid, as well as reduction in non-cash working capital.

Adjusted cash flow from operating activity increased year-over-year, mainly as a result of increased cash flow from operating activities net of changes in non-cash working capital, and reduced taxes paid. This increase was partially offset by additional preferred share dividends.

In the third quarter Pembina generated adjusted cash flow from operating activities of CAD250 or CAD0.64 per share. This compares to CAD209 or CAD0.60 per share in the same period last year. Pembina generated adjusted cash flow from operating activities of CAD694 million or CAD1.80 per share for the first three quarters of 2016, compared to CAD598 or CAD1.75 per share in the first nine months of 2015. Increased cash flow from operations, net of change in non-cash working capitals decreased tax expense and share-based payments were offset by higher preferred share dividends.

I will now review our business unit performance. In the third quarter, Conventional Pipeline saw a slight increase in quarterly revenue volumes to 643,000 barrels per day, a 7% increase compared to 600,000 barrels per day in the third quarter of 2015. Year-to-date revenue volumes were 654,000 barrels per day, compared to 612,000 barrels per day during the first nine months of last year. Revenue volumes grew as result of the Phase II expansions completed in April and September of 2015, new connections that were placed into service, and increased volumes on the Vantage pipeline.

Volumes trended slightly lower than prior quarters as a result of a facility outages on both the Pembina pipeline as well as third-party facilities, and flooding in British Columbia. Operating margin within the conventional pipelines was CAD121 million for the third quarter, representing a 32% increase over the same period last year. So far in 2016, operating margin within this business was CAD376 million compared to CAD292 million recorded for the comparable period of 2015.

In Gas Services, revenue volumes for the third quarter were a record 894 million cubic feet per day, compared to 690 million cubic feet per day in Q3 2015. Revenue volumes increased as a result of the acquisition of the Kakwa River facility, as well as Saturn II and SEEP coming to service in August 2015.

Operationally, there were a few challenges within this business including both scheduled and unscheduled outages and Resthaven, and a fire incident at Saturn II, which somewhat offset increased volumes from new assets. Resthaven was restarted July 24, and Saturn II on August 8. Since returning to service, both facilities have been operating very well.

Operating margin within gas services increased by 33% to CAD52 million for the third quarter, compared to CAD39 million in the third quarter last year. On a year-to-date basis, operating margin increased 22% to CAD135 million, compared to CAD111 million during the nine months ended September 30, 2015.

So far in 2016 the estimated impact of the Resthaven and Saturn II outages is nearly CAD18 million. An insurance claim for the insurable portion of the Saturn outage is pending, and is expected to cover CAD6 million of lost revenue across Pembina's operations.

In our Oil Sands and Heavy Oil business, we saw a modest increase in operating margin as a result of the Horizon expansion, which was partially offset by lower interruptible volumes on the Nipisi system. Operating margin for the third quarter was CAD36, compared to CAD33 million in the third quarter of last year. For the first nine months of the year, operating margin was comparable to the CAD103 million earned in the same period last year.

In our Midstream business, operating margin in third quarter of 2016 was CAD106 million compared to CAD0105 million in the third quarter of 2015. Improvements in NGL Midstream results were driven by the in-service of RFS II, and more favorable NGL sales environment. On a quarterly basis, volumes increased by 25%, while on a year-to-date basis, they were up 19% compared to prior periods. These factors resulted in an operating margin of CAD77 million or 24% higher than the third quarter of 2016.

For the first nine months of 2016, operating margin was CAD222 million compared to CAD171 million in the comparable period of 2015. Operating margin in Crude Oil Midstream was lower, as a result of a more challenging price environment, timing of storage revenue, and tighter commodity margins. Third-quarter operating margin was CAD29 million compared to CAD43 million for the third quarter last year. For the first nine months of 2016, operating margin decreased to CAD116 million from CAD133 million for the comparable period. Year-to-date results were impacted by the same factors as Q3.

We continue to ensure our balance sheet remains strong during this period of elevated capital spending, and are encouraged with our continued access to capital at attractive terms. In August, Pembina completed a CAD500 million, 10 year medium-term note issuance, with a coupon of 3.71%, and as of November 3, our CAD2.5 billion credit facility was approximately CAD165 million drawn.

Additionally, as of September 30, our debt to trailing 12 month adjusted EBITDA was 3.4 times, making for one of the most conservative balance sheets in our peer group. Overall, I am pleased at the results Pembina has been able to generate, while executing on such a large-scale capital program. All of this hard work is setting up for an exciting 2017, as we commission numerous large-scale growth projects, and begin to realize incremental cash flows.

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. Starting off with our Phase III expansion, construction teams are hard at work on a number of key sections of the project. During the third quarter, the pipeline between Wapiti and Kakwa was completed, and we began construction on the Fox Creek to Namao portion.

Work on the section is the largest portion of the Phase III expansion, and will continue into 2017. We have successfully completed numerous challenging river crossings, including Peace, North Saskatchewan, Athabasca, and Kiskatinaw rivers. The combined Phase III expansion project, is over 50% complete and continues to trend on-schedule and under-budget for a mid-2017 in-service date.

We are awaiting final regulatory approval for our major Northeast British Columbia expansion. Once received, we expect construction will begin in the fourth quarter of this year. The project remains on track for a late 2017 in-service, subject to receiving required regulatory approvals by year-end.

The Vantage pipeline expansion was placed into service late in the quarter, and we are pleased that it was completed under budget. The project added 80 kilometer lateral, new connectivity and increased the system capacity to 68,000 barrels per day from the initial 40,000 barrels per day.

At our Canadian Diluent Hub, in Fort Saskatchewan, engineering and procurement are over 80% complete, and civil work is 70% complete. Construction of the two, 250,000-barrel tanks is about 1/3 complete. The project has targeted in-service date of mid-2017 to align with the in-service date of the Phase III expansion, and is trending under budget.

I will now pass the call to Stu to provide an update on growth projects in our NGL value chain.

Thanks Paul, and good morning, everyone.

Pembina's CAD270 million Duvernay development program is advancing well, with Duvernay I having received all required regulatory approvals. Site grading is complete, filing will be done by the end of the year, and the project is on track to be in service by the fourth quarter of 2017. Development of the field hub, which was announced earlier this year is also progressing. Engineering is 35% complete, and most of the major equipment has been ordered.

Key regulatory applications have been submitted, and subject to receipt, the field hub is expected to be in service by the fourth quarter of 2017, as well. At Redwater, all detailed engineering associated with RFS III is complete, and major equipment has arrived on site. Overall mechanical construction is 75% complete, and electrical construction is 25% complete. The project continues to trend on-time and on-budget for a Q3 2017 startup.

Construction is underway in support of the [terminalling] infrastructure associated with the planned Northwest Redwater Sturgeon refinery with detailed engineering and procurement 85% complete. The project is tracking on-time and on-budget, and we expect to place the assets into service throughout 2017, beginning early in the year.

Further through the detailed feasibility study associated with Pembina proposed [PDH/PP] facility is complete, with all key deliverables received. Pembina and our partner, Kuwait's PIC, are reviewing the study findings and are expected to make a decision on proceeding to FEED by the end of the year, at which we will provide an update to all stakeholders.

Scott, back to you.

Thanks, Stu. We very pleased with the financial results and volumes in our businesses, and our outlook for the remainder of year is positive. Furthermore, 2017 is setting up to be an exciting year as we will enjoy a full-year contribution from large-scale assets such as RFS II, Kakwa River, Musreau III, the Horizon Expansion, amongst others.

We are enthusiastic about the growth we'll be bringing on stream over the next 12 months. Inclusive of the projects put into service this year, we have clear line of sight to adding CAD600 million to CAD950 million of EBITDA by 2018, providing visibility to near-term dividend and cash flow per share growth. As always, will continue to focus on operating and growing our business in a safe, reliable, and cost-effective manner. With that, we will wrap things up. Sharon, please go ahead and open the line for questions.

(Operator Instructions)

David Noseworthy, Macquarie.

Thank you very much, and congratulations on a good quarter.

Thanks, David.

Starting with the recently completed PDH and PP facility study, are you still anticipating a capital cost of CAD1.5 billion to CAD2.5 billion net to Pembina?

That is right in our expected range, nothing has changed to that feasibility assessment.

Perfect. In terms of commercial constructs like take-or-pay, fee-for-service, at what stage in this process do you think you'll set that for the project? Or perhaps said differently, how much do a anticipate spending before understanding whether or not this is a project you can invest in?

We're continuing to look at that and we've had preliminary conversations with a variety of companies and individuals. It is difficult to say how far we ramp that up until we proceed further along with the FEED assessments, given review of our feasibility study. We've got some capital to spend to progress something, but at the same time we have been in conversations. It's hard to predict how much money we'll spend until we complete some of those conversations.

David, I think the reason we put out the guardrails in our investment criteria, is to give you comfort that we're going to stay within the guardrails on this (inaudible), and we will take up as much fee-for-service customer base as we need to, to stay comfortably within the guardrails.

Okay, thanks for that color. Maybe just one last question on timing, understanding that the FEED decision is by year-end, what is your expectation assuming things move along long as expected, for an FID decision?

Right now the target of FID is looking to be early 2018.

Perfect, and maybe just one last question for Scott. Just noticing the tax refund that you received in the quarter. Can you speak briefly about, what your available CCA pools are, and your expectation regarding cash taxes going forward?

Sure. Similar to our Q3 of last year, and Q4 of last year, where we file our true-ups after completing our year-end tax return, we did have a current tax -- so just to be clear, that's a current tax recover, not a cash tax recovery. But from that end, maybe what I will guide you towards is the fact that we expect to have a current tax expense somewhere in the neighborhood of CAD60 million to CAD65 million for this year, and we would expect next year to be consistent with that, just given the large-scale capital project that we are bringing on, as well as the CCA pools that are associated them. But David, I don't have the number of front of me but we have somewhere in the neighborhood of CAD2.5 billion taxable.

Perfect. Thank you very much. Appreciate the color, and I will get back in the queue.

Thanks, David.

Linda Ezergailis, TD Securities.

Just to further to some of your big capital allocation decisions that you're going to be making over the next couple of years. How does your dividend policy, and thoughts on that, fit into that retaining capital to finance some of these pending potential projects like the PDH or moving your pay-out ratio as you complete some of your big projects next year? Or should we look to the historical trend of dividend growth to look forward?

When it comes to the dividends, I think the first principal, it goes back again to what Mick said about the guardrails, is we'd like to get that dividend to be below 100% of our fee-for-service business, more comfortably in the 90% to 100% of fee-for-service. Then we will let the little commodity exposure that we have float, and it will be what it will be.

In terms of, in relation to the capital, remember most of this capital is all completed by the middle of next year. There is some, obviously, that goes through the end of next year, but the vast majority of it is through the first half of next year and then the capital spending on some of the large-scale facilities like the PDH, as Stu said, an FID decision is early 2018. We won't be spending heavy capital until 2019/2020 if we decide to go ahead. So in this five minutes, it is not really a driving factor.

I think it goes back to the fee-for-service business -- a starting point is likely the historical rate, and then we will assess that in terms of any new projects we win or the current environment at the time.

If everything unfolds as we've guided we should be 90% of 80% after these projects come into service and, that would assume historic dividend increase. That puts us into early 2018, when we may or may not change the historic dividend growth rate, depending on how many capital projects we have at that point. We are focused on -- that's the one guardrail that we're not within just yet, but as Scott said, with roughly CAD5 billion we bring in over the next year or so, we intend to get that guardrail onside, and then we will reassess the dividend growth rate after that period of time.

Thank you. Further to the front-end loaded timing of your CapEx spend next year, can you talk about the relative attractiveness of various financing options including, how much short-term lending you might do to finance that CapEx versus pre-funding some of that through longer-term capital?

Right now, I said as of November 3, we only have CAD130 million or something drawn on our credit facility. If you've watched our historical pattern, we've tended to carry no more than roughly a CAD1 billion on the facility to leave flexibility.

So we do have the capacity that to go up to CAD2.5 billion; we would never do that, Linda. We are probably targeting somewhere in the neighborhood of CAD500 million bond deal next year, which we've talked a lot about.

The key point on the capital program is, we will carry probably a little more on the credit facility than we have in the past as we go through the financing program, only because then it provides us flexibility. Because as we move to the back end of 2017 and into 2018, absent any new projects we'll be generating significant free cash flow and then we will have options and one of our options will obviously be to repay debt. We have a lot more flexibility if we are caring it on our credit facility and redeeming long-term notes.

That is helpful, thank you.

I would say from our perspective, other than our share price, all other options of financing are attractive. We've seen preferred share rates come down, bond rates are attractive, so both of those are very attractive in the current market.

Great, thank you.

Ben Pham, BMO.

Just going back to the petrochemical proposal, I'm just wondering, on the feasibility study that you've gone through -- I'm just wondering if there's any other incremental surprises? Or maybe come out of it more optimistic on -- when you think about, perhaps looking at the pricing, the forward curve and competitors, not just within North America, but also globally. Was to anything else incremental coming out of that?

Nothing -- this is Stu, Ben. Nothing tremendously surprising, obliviously it's some fine tuning of some details. Recognizing it is a dynamic market, we are projecting a long ways into the future at this point in time. The world is changing, but I would say we're fairly pleased and confirmed many of our initial expectations through the feasibility study.

I would just add to that, the one thing that looks possible that we haven't seen in Alberta for a long time is, there is a possibility we can lump some turnkey with the project and that something we have not seen in major facilities before. I'm going to characterize it as, it is possible at this point. And that is something that was not apparent as a possibility to us when we started this thing out. As we look at the way we can mitigate commodity exposure, the way we can mitigate capital exposure, and just the overall feasibility -- what we have seen so far looks positive.

When you say lump, is that more management cost?

What that means is someone will construct that facility for us at a pre-agreed to price, so we don't -- if that were to come to pass, and I'm not saying it is, but it would mean that someone would build that at the pre-agreed cost then henceforth ourselves and PIC would no longer take the capital cost risk.

Okay. Have you thought about any change in sizing and partners?

We continue to evaluate, we have not considered any other partners at this point in time. And as part of the feasibility study, we did evaluate two sizes and those are still decisions to be finalized.

Okay and just one quick clarification. The Phase III -- the portion that came in Q3, are you going to book fees on that? Or is that more of mid-2017 with the Namao portion, too?

It will come into service in mid-2017, because right now that pipeline is full. So there's really -- can't put a whole lot more volume on there. So it's really just a pre-built. So it'll be mid-2017.

Okay, great. Thanks for taking my questions.

Jeremy Tonet, JPMorgan.

Good morning. Just want to touch on crude oil operating margin in the Midstream segment there. It, as you note, stepped down a little bit quarter over quarter and year over year. And just curious, as we look into 4Q here, if you see that bouncing back towards where it was or, is it more of a run rate for the near-term?

Jeremy, I think a little bit of a color there on this quarter versus last quarter. Last quarter with everything that was going on in Alberta, there was a lot of volatility. And there were some storage positions that were monetized, whereas in Q3, some of those positions spilled over to Q4, and quite frankly, some of those will spill over to Q1.

This was a weaker quarter than we were expecting. I don't we expect Q4 to be back to where we were last quarter, or the quarter before that, but we don't think CAD29 million is the new run rate. We're somewhere in between, we think.

That's helpful. Thanks. M&A seems like it has picked up a bit, here, both asset level and corporate. I was wondering if you could provide any updated thoughts on how you view the landscape, especially with regards to the guardrails that you've outlined?

Yes, we see continued activity for sure. But just to take you through the way we think about that; when we exploit our asset base, that's clearly where we have the highest returns, so that's always our first priority. And looking, for example, to see if there's an opportunity to add the pump stations to the Fox and Namao portion some time in 2018 or 2019, that would be very accretive project for us. So those are the kinds of things we are looking at first.

Second, greenfields, Duvernay I is a great example of our Tier 2 priorities in terms of growing the business. Generally, those returns are slightly less favorable than brownfield but still very attractive.

Then third would be loose-asset acquisitions like Kakwa River. Again solid returns, building new platforms, growing the breadth of our businesses.

And then lastly, would be corporate. Clearly our peers are trading well, so that would be the last place we're looking. But we are always looking in all of those areas. I do concur, it does seem like there is more M&A opportunity, and we are looking at all those opportunities.

Great, thanks. Then just one last one if I could, and maybe on the PDH and PP project, as you've been discussing on the call. If you could just refresh us, as far as your thoughts, on the competitive stack up there versus some of the other alternatives that might be looking to come to market as well?

You mean how does that opportunity compare to M&A, is that your question?

As far as your offering versus others that might have similar offerings, might be looking to build as well, just wondering if you could refresh us on how you think yours stacks up versus other offerings out there -- other potential competing projects?

Absolutely. Our preference obviously would be that only one project go ahead, but we've always modeled two going ahead. We came into this with knowing a competitive project was out there, and so our modeling in terms of market size, and things like that, that's always been our base assumption. But were only one project to go ahead that would clearly be better, but we've always assumed two go ahead in all of our analysis. Stu, do you have anything to add to that?

No, I agree with what Mick has stated. I'd point out that we have the ability -- we have the supply to fill our entire facility, where we have the connectivity to access all of the fractionators --eventually all of the fractionators in the Fort Saskatchewan area, to ensure that we have multiple sources of supply to feed the facility on a go-forward basis. We think we have a great site, and selected an opportunity with all the interconnectivity that we need to be successful in a large way.

That's helpful. That's it for me, thank you very much.

Rob Hope, Scotiabank.

Just a question on the volume outlook for the Phase III expansion. Just want to get your thoughts on the balancing impacts of less drilling activity, offset by the fact that we're seeing increasingly high condensate yields on some of these new wells up in the Montney?

Yes, those things are clearly offsetting. Just a reminder that the Phase III expansion is fully contracted right now, where the physical volumes will come in is a topic of discussion around here all the time. Clearly some producers are moving forward less quickly but we see a producer like 7G, that are surprising us the other way.

So, as we look that project coming in mid-2017, I'm going to take a guess that we will be somewhere around take-or-pay levels as we start, and that's well within the range of the CAD600 million to CAD950 million, and then over the success of a number of quarters maybe four to eight quarters, that we will be in excess of that take-or-pay. That's our current crystal ball but as you can appreciate with 40 customers all doing different things it's pretty hard to gauge.

That is helpful. Maybe a follow-up on that same topic. If one producer is going to exceed their take-or-pay levels, would they be talking to you for incremental contracts? Or would they potentially be discussing an assignment of some volumes from a producer that would see less volumes?

Both options are available to the shippers. A lot would depend on where the volumes are and where the relative contract receive points are, but all options are open to the shippers.

As you think about modeling it, if is someone's in excess of their take-or-pay, they've got to pay us the greater of the take-or-pay or the physical. That doesn't get offset by another customer who is under their take-or-pay, but when you think about it, it's pretty hard to imagine us being lower than our take-or-pay, because some people are going to exceed. And for sure Pembina, over time, is trying to facilitate transactions between people who need more capacity above their firm, to people who don't envision needing all their capacity. Because we don't want to have people paying take-or-pay, while we're asking other people to contract more. That wouldn't be what we view as a high level of service. So we are try to match-make, and we have had some success in that area. But when you run your model, you've got to realize, some people are going to be over their take-or-pay, and we will get paid for those excess volumes.

All right, that's helpful, thank you.

Robert Catellier, CIBC World Markets.

Believe it or not, I still have questions on the PDH facility so I will start with the first one. What really has to happen at this point for that go to a pre-FEED study?

Rob, as you can appreciate, the key deliverables are pouring in this week. There they are being compiled, and the process is to go through the entire package, for review by both ourselves and PIC, and once compiled, then recommendations to take before for both boards.

Okay. Then just on Canada's carbon price plan. Was that part of your prior studies, and what impact do you think that has on the project?

It is been included in our economic evaluation. We have put in some levy for carbon. Obviously, it is a negative to the economics.

We're doing everything we can, as you can appreciate, from an environmental and emission perspective, to reduce that. The facility is largely self-contained and self-generating it's power. We do have one of the proposals to put a cogen on-site. That will have some emissions, but at the same time we see it as a benefit from a power perspective to proceed that way. We valued it; it's in the economics. It is a negative. At this point we're doing everything we can to minimize that impact.

But just to put in one sentence; what we have seen so far we are pleased with. We have a partner, and we can't front-run their thinking, and we still have some deliverables rolling in, and we have a Board Meeting set on December 16, and we are working towards that.

Understood. That the next question Mick, if you got a lump-sum turnkey contract, that you could live with, and you've effectively transferred some capital risk, does that change your appetite for assuming commodity price risk on the project? Given it that might imply that your total risk isn't all that much difference on the returns?

That was the first thing the BD guys asked me. (laughter)

Thanks, Rob.

It is a guardrail analysis. Our straw dog is that Pembina lays off half of its half, in terms of commodity risk. And we are in discussions with some producers that would seem to be excited about taking on half of that half, i.e, we would use their propane barrels, and they would pay us a fee, and we would give them back polypropylene barrels so that's straw dog.

It is out there, but it is a guardrail analysis and of course, you can appreciate, if we for example, were to build the smaller facility, and turnkey that, it would shave a number of billions of dollars off the price, and henceforth our risk would be lower, and it would give us more capacity to take on commodity price risk. That doesn't mean we'd want to do it because we are a company that does want to have a high degree of fee-for-service, and we're also a company that has proprietary propane barrels that we can use in other projects. So we don't necessarily want to use of our non-fee-for-service room all for one project. We would rather see it diversified across a number of projects, and a number of commodities, to even diversify the small exposure we will have to commodity risk.

Okay, that's very helpful color, thank you. On the Phase III, I guess I shouldn't be surprised, given Pembina's history of putting projects into service on-time/on-budget, but with Phase III, you did some regulatory shenanigans at the front end, and the weather doesn't look like it is been all that conducive to building up a project. You're still on-track/ on-budget, so maybe a little bit of color there, and your comfort level within the in-service date?

The weather -- actually we looked, and I think the last five months have been somewhere between 120% and 200% of normal precipitation, and it is creating challenging circumstances, right now. But Pembina still believes we can bring that project in on-time and under-budget, but clearly the weather is a drag on cost. Maybe we won't be as under-budget as we had hoped, but we are still trending on-time and under-budget.

And you are right, some of the time compression is a result of some of the regulatory items we've had to go through. But I can also say we are having constructive discussions with one party that we had some issues with, and we think we can end up in very good place with all communities along the right-of-way.

Just for a little more color on the construction site. We are working with our contractors. I guess we are benefiting from the fact there's not a lot of other pipeline projects in the province that are this size and diameter. So there is equipment around, and we just have to double up on the equipment, so it is available, and we are in the midst of negotiating with our contractors. It is going well.

So good availability makes-up, or perhaps offsets the productivity?

Right.

Thanks for taking my questions.

Patrick Kenny, National Bank Financial.

Just coming back to Midstream, wondering if you can comment on how NGL marketing environment is shaking out heading into this winter, relative to last year? Maybe both in Western Canada and Ontario?

And then also, quick update on any changes to your frac-spread hedging position, relative to last year as well?

Sure. I think from an overall NGL perspective, if you look at inventory levels, certainly the Canadian inventory levels are in decent shape, at or around historical five-year averages. I think the west is slightly below, the east is slightly above. From inventory perspective in Canada, we are setting up nicely. From a North American perspective I think the US inventories have now, as of this week, moved slightly below last year, which was an all-time high.

So we are back within that five-year inventory range, albeit at the high-end of that. And you've seen that reflected in the propane price, which has continued to inch up over the last couple of months. We do think it's setting up to be a decent winter pattern. Now, how much of that comes to fruition will depend on the weather, which we will wait to see.

But certainly we feel like we are in better position going into this winter than we did last winter. That being said, we have put on incremental propane hedges, compared to where we were last year. So we have about, I'm going to call it 75%, of our frac exposed barrels hedged going into the winter.

Looking forward, you can expect as we grow, and our frac-spread exposure, say as a percentage of EBITDA, drops from what was, 20% in 2014 or slightly higher. We expect to be -- with our commodity price crystal ball, somewhere in the 1% to 2% by 2018. The need for us to hedge through a peak debt-cycle and through a peak construction-cycle, the need for Pembina to hedge is diminishing.

So we are thinking about having no hedges in the 2018 timeframe, but that remains to be seen. I think you can expect the hedging activity to diminish as the company grows out of its commodity exposure over the next 12 to 18 months.

That is great, thanks for that. I guess I've got to get in on the PDH discussion here, so apologize if you already touched on this but if you could just confirm the guardrails, with respect to contract duration?

Now we are way, way out on the branch, here. First, we have to decide how much of that project will be fee-for-service, and how much will be non-fee-for-service. We haven't taken that decision. I've thrown out a straw dog, but if you observe Pembina over the last number of years -- 10 years is always a good number. A lot of our contracts are around 10 years, so that might be a good working assumption for you to model.

Long way to go before we decide that.

Okay. Thanks for that. Just lastly, I know it is a small part of the overall business, but just on the Western pipeline system. Does the outlook for this pipe change at all if the TMX expansion does in fact come online one day?

I don't think so. The southern portion, we are suspending at this time. The northern portion, we are talking to our single customer about what's happening next.

Overall, that pipe doesn't really impact Pembina very much, and we obviously need customers to run it. And there are no customers in the southern end, and if that were to change certainly we could restart it. It just takes a lot of effort and a lot of capital to keep it in as-new condition which is our standard. Paul, do you have anything to add?

No.

All right, great. Thank you very much, guys.

Robert Kwan, RBC Capital Markets.

Might as well pile onto the topic today. You commented that on the PDH/PP side that you have a preference, or wanted to go ahead. I guess I'm just wondering do you have any updated thoughts on the potential to combine the projects? It seemed a little insurmountable at the beginning, given you had a different set up; them only being PDH and then tracking to an FID by the end of this year. But now that they are looking at an integrated PDH/PP unit, and have pushed their commentary on FID up to mid-next year, you're at least little bit closer to what you're [thinking] on timing.

So how do you think about your willingness and the potential to try to combine the two?

If that made sense -- we'd consider everything that make sense, Robert. Right now, our project with our partner, and the economics we are seeing, and the risk profile we are seeing, make sense, whether or not another project were to proceed. But if it at some time that were to change, and it would make sense to combine projects, we will do what makes sense.

Okay, so there's nothing structural, even as you think about how much propane you're going to be getting, coming off of Redwater when RFS III rolls out?

The PDH, we like the project based on what we see so far. But it is not the only thing we are pursuing. I know it is been a long time, but we've never given up on exports. We haven't given up now, and so that could be a possible sink for propane and butane as well. Our job is to vertically integrate our business, and to create higher net-backs for producers for propane. And we're going to look at all opportunities to do that.

Okay. If I can just finish on the pipeline side of things. We have seen some good data points out of Montney producers, in particular. I was just wondering if you had a directional change? You talked a little bit about trying to swap people's barrels around. But any directional change and thoughts over the medium- to longer-term about the need for new capacity?

And I guess where I'm going is, you've got the low-cost solution for additional capacity for producers. But how do you think about balancing the high return from taking on new contracts, under the existing capacity versus trying to convey some of that cost to your advantage to your customers, so that you can build the next wave just to keep that advantage going?

Bluntly, we are looking at our toll structure, particularly at the very far end of our pipeline. If we can bring on a bunch of volumes, and do Phase IV, and power it up, I think we have the opportunity to look at tolls on the far end of our pipeline for our best customers. And we are going through that exercise right now, because as long as we make more money we are happy if the producers make more money. And we realize way up in the far reaches of our system, it is expensive.

And if we can bring volumes on there, and capture economies to scale, it is always been our way of doing business to share some of that with producers. So we've got the pipeline guys looking at what the possibilities are with this very accretive expansion.

Okay. That's great, thank you.

Andrew Kuske, Credit Suisse.

Good morning. I'm not going to ask a PDH question. (laughter)

Maybe this one is to Stu, and it's more about basin health, and how you guys think about health of the basin. And then obviously some volumes have been robust, but when you step back and think about the pipeline competition that's emerging -- and then obviously we've seen some producers like 7Gen be very proactive in securing capacity on an NGPL deal not that long ago. But, how do you think about how the pipeline dynamic on the nat gas side really impacts your business on a longer-term basis?

There's things that are transpiring. The gas price today, is I think, it is okay. I think the most cost-effective producers are covering cash costs and making a little bit of money; the margins are there.

Obviously, some of the regulatory and the pipeline discussions that are taking place, that would see a lower toll and access to some market -- potentially access to markets through those pipelines would be beneficial. We are a gas basin, we need to have a gas solution for continued development.

Having said that, the opportunity and some of the pricing and the advantage and a lot of the economics, is being driven by some of the liquid components of the gas stream. We are seeing people come in and basically drill for those liquids. The gases, they earn a small rate, and they are focused on a liquid recovery. So the gas is not the biggest driver.

But again, we are excited about the price today. We are excited about future access at economic rates to markets, and any gas benefit that the producers get does lead to more products being delivered into the pipelines, and more facilities need to be constructed to move those products.

That's helpful. Do you foresee a situation where tolls come down? Greater market access is secured on the gas side, and that spurs on even more development then, that you've anticipated?

That's our view, yes.

Okay, very helpful. Thank you.

Brent Watson, Cormark Securities.

I wonder if you could make it quick comment about cost environment, specifically as it pertains to labor. If you were to restart a Phase II or a Phase III project today, what would cost estimate look like?

It would not be vastly different. It wasn't very long ago actually that we -- in the last six months we really settled on pricing contract? From the time that we announced this project, we actually had at least one maybe two cost refreshes, so there would not be, in my opinion anyway, a real change if we did it today.

Thanks, great.

You have no further questions at this time.

Thanks, everybody for your continued interest and support. Capital programs going well. We do have -- we're really busy, actually. Most people might not expect it, but our teams are flat-out on all kinds of different projects. It is an exciting place to be, and we expect to deliver on the promises that we put out there. So thanks a lot and have a great weekend.

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