Good morning, my name is [ Megan ] and I will be your conference operator for today. At this time I would like to welcome everyone to the Pembina Pipeline Corporation 2017 Second Quarter Results Conference Call. [Operator Instructions] Scott Burrows, Pembina's Senior Vice President and Chief Financial Officer, you may begin your conference. .

Thank you, [ Megan ]. Good morning everyone and welcome to Pembina's conference call and webcast to review highlight from the second quarter and first 6 months of 2017. I'm Scott Burrows, Pembina's Senior Vice President and Chief Financial Officer.

On the call with me today are Mick Dilger, Pembina's President and Chief Executive Officer; Stu Taylor, Senior Vice President, NGL & Natural Gas Facilities; and Paul Murphy, Senior Vice President, Pipelines & Crude Oil Facilities.

Before passing the call over to Mick, I'd like to remind you that some of the comments made today may be forward-looking in nature and they 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. On a year-to-date basis, Pembina set new financial records for almost all metrics including adjusted EBITDA, adjusted cash flow from operations and adjusted cash flow from operations per share.

We've also set new volume records in our conventional pipelines and gas services businesses, all while continuing to operate safely and reliably. Furthermore, we placed $2.8 billion of projects into service at the end of the quarter, safely under budget and either on or ahead of schedule.

I'm sure you can appreciate the sense of accomplishment we feel having reached this major milestone and delivering on the promises we made several years ago.

Many of these projects were conceived during our 2013, 2014 time frame, so it took a lot of dedication and diligent work to get to this point where the assets are now in service and operating as expected. I'm extremely proud of the work our people have done to bring these projects to fruition and [ commence ] everyone at Pembina on a great job.

We're also very pleased that subsequent to quarter end we achieved 2 milestones related to the combination with Veresen. On July 11, Veresen's common and preferred shareholders overwhelmingly voted in favor of the transaction, and on July 12, the transaction was approved by the Court of Queen's Bench.

The transaction is transformational for both companies and we are excited about the progress we've made towards closing.

The combined company will feature an integrated asset base supported by long life economic hydrocarbon reserves, a high proportion of fee-for-service cash flow and an impressive fleet of both secured and unsecured growth opportunities.

Upon closing of the transaction, we continue to expect to correlate in the third quarter or early fourth quarter of this year, we try to increase our monthly dividend by 5.9% to $0.18 per common share, supporting our view of the strength of the combined company. I'll now pass it back to Scott. .

Thanks, Mick. As Mick mentioned, Pembina achieved operational and financial results -- strong financial results in the first 6 months of 2017. I will summarize the results briefly as the details are in the report. In our Conventional Pipelines and Gas Services businesses, we reached records for revenue volume.

Average revenue volume on our conventional pipelines were a record 692,000 barrels per day, 5% higher than in the first 6 months of last year. And our gas services business at average revenue volumes of over a bcf a day, 40% higher compared to the same period last year.

Higher volumes along with improved operational performance in new assets and services within certain business units resulted in strong operating margin in the second quarter and first half of the year compared to the same period last year.

Conventional Pipelines operating margin increased by 16% to $147 million in the second quarter and 10% or $281 million over the first 6 months. Gas Services operating margin increased 43% to $66 million in the second quarter and 64% or $136 million over the first 6 months.

Midstream operating margin increased 16%, $269 million over the first 6 months, however, Q2 was down 12% to $108 million on a quarter-over-quarter basis, with this second quarter operating margin being negatively impacted by market dynamics and restricted opportunities.

The crude oil midstream specifically, although crude oil prices have strengthened year-over-year and while marketed and stored volumes are relatively unchanged, the underlying margins were tighter which resulted in reduced operating margin. Further market prices were more volatile in 2016 and in 2017.

Within this business increased market volatility typically creates more opportunities for storage, which is what we saw happen in the 2016 period versus past quarter.

In addition due to increased domestic condensate production, the rail import of condensate was not economic during the first 6 months of 2017, where it was during the same period in 2016. In addition, our NGL business was impacted by third-party facility outages, both upstream and downstream of our facilities.

Our Oil Sands business continue to perform in line with previous periods as expected. Now to touch on some of our key financial metrics. Adjusted EBITDA was $303 million for the second quarter and $666 million for the first 6 months of the year, increases of 4% and 19%, versus the same period last year.

These increases were largely due to new assets being placed in the service and strong performance particularly in our Conventional Pipelines and Gas Services businesses.

Our strong business performance combined with higher payments received, non-cash working capital and lower net finance costs resulted in adjusted cash flow of $275 million for the quarter and $583 million year-to-date, which are increases of 17% and 31% compared to the same period last year.

On a per share basis, adjusted cash flow was $0.68 for the quarter and $1.46 for the first 6 months, [ 13% and 26% ] jump versus the prior periods. Our earnings came in at $124 million or $0.26 on a per share basis for the quarter representing a 10% and 4% increase relative to the second quarter of 2016.

On a year-to-date basis, earnings were 58% and 56% higher, $339 million or $0.75 per share compared to last year. Turning to our financial position, Pembina maintains one of the strongest balance sheet among our peers and is further supported by ample liquidity and financing flexibility.

At June 30, 2017, Pembina's debt-to-trailing 12-month adjusted EBITDA ratio was 3.7x, strong cash flow generation from our legacy assets enhanced by immediate contribution from our newly in-service assets along with nearly $2 billion of undrawn credit facility capacity positions us well to fund our remaining 2017 capital program and future growth opportunity.

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 Mick mentioned earlier the real highlights for the quarter was placing our Phase III expansion in the service on time and under budget. This marks the completion of the largest capital project in Pembina's history.

Initial work for the Phase III expansion including debottlenecking segments of the existing pipeline system from Taylor, British Columbia to Gordondale, Alberta, adding a new pipeline from [ Namao ] to Fox Creek and the construction of 11 new our expanded pump stations to accommodate increased volumes upstream of our Fox Creek terminal.

To support increased volumes we had an additional 420,000 barrels a day of capacity between Fox Creek and Namao through the construction of 2 pipelines. We now have 4 pipelines in the corridor and are able to ship ethane-plus , propane-plus, condensate and crude oil separately.

We also now have sufficient upstream capacity to handle forecast volumes driven by the development of Montney, Duvernay Deep Basin resource plays. The expansion is operating as expected and volumes continue to ramp up.

We're also excited to have announced in early April our Phase IV and Phase V pipeline expansions on the back of continued customer demand for transportation service. We expect to place both of these projects into service in late 2018.

More imminently our Northeast British Columbia expansion and Altares Lateral remain on schedule for targeted in-service date in the fourth quarter of this year.

We're also very pleased to have brought our Canadian Diluent Hub into service at the end of the quarter in alignment with the Phase III start-up, remaining work at the facility includes the completion of the storage tanks later this year and some additional connectivity. Over to you, Stu. .

Thanks, Paul, and good morning, everyone. To echo Paul, the highlight of the NGL business unit this quarter was placing our third fractionator at our Redwater site into service on time and under budget. Pembina now has 210,000 barrels per day of fractionation capacity making ours the largest fractionation facility in Western Canada.

We're also very happy to announce during the quarter that we have moved into the FEED phase for our proposed PDH and PP facility and we executed joint venture agreements that include buying the commercial terms in support of the project and the formation of the Canada Kuwait Petrochemical Corporation or CKPC.

Subsequent to the quarter end, CKPC entered into both the PDH and PP [ projects ] technology license agreement with commercially proven technologies that have a strong track record of efficient and safe operations.

We are very pleased to have executed these agreements, with these decisions in hand we are working on other key FEED deliverables including regulatory applications and updated cost estimate and project execution plan among other items.

In April we were pleased to announce that we signed a nonbinding letter of intent with the city of Prince Rupert for us to assess developing our West Coast liquefied propane export terminal on Watson Island, B.C. The terminal would have approximate capacity of 20,000 barrels per day of export capability and access premium markets for our customers.

The terminals continued on completion of design and the engineering requirement, entering into the appropriate definitive agreements, and the receipt of necessary environmental and regulatory permits.

Through this project and our propylene/polypropylene production facility, we remain focused on working to buy market access solutions to our customers helping to add value to Western Canadian incremental barrels and increased producer netbacks.

At the company's Redwater site, the infrastructure in support of the North West Redwater partnerships refineries nearing completion and we are on schedule to have the project in service late 2017. Turning briefly to the Gas Services project. Duvernay I plant in the Field Hub are on target to be brought into service in the fourth quarter of 2017.

We continue advance preliminary engineering of a replica Duvernay II facility as well as the development of substantial liquids handling and stabilization equipment. Back to you Scott. .

Thanks, Stu. As we pass the midpoint of the year, we feel 2017 is truly shaping up to be a transformational as we expected it to be.

With [ $2.8 billion ] of projects recently placed into service along with our other growth projects slated to come into service this year combined with the associated incremental cash flows, we remain on track to delivering adjusted EBITDA between $1.8 billion and $1.9 billion in 2018 as a standalone company.

The Veresen transaction, these numbers increased to $2.55 billion to $2.75 billion. We believe the last half of the year will be as exciting as the first half given clear visibility to near-term, high-quality cash flow growth and the potential close of the transaction. With that, we'll wrap things up.

[ Megan ], please go ahead and open the line up for questions. .

[Operator Instructions] Our first question comes from David Galison with Canaccord. Your line is open. .

So I guess my first question is for Scott, just to touch on your guidance kind of considering the change in the U.S. dollar recently. Are you -- can you talk about maybe how comfortable you are with the guidance and maybe is there a level in the U.S.

dollar where you start to push up against the range?.

David, I'm still comfortable with the range.

When we set our budget in late 2016, the dollar was roughly at this time frame, so as we started to move through 2017, certainly our guidance was moving up with that, but now that the dollar's fallen back down to roughly $0.80 mark, we're kind of back to where we originally set our budget, so I'm comfortable with where we sit today. .

And then just on the polypropylene PDH facility, the contracts that you had mentioned, could you talk about the type and maybe how much of the capacity is contracted?.

Right now, the agreements that we've executed, the joint venture agreement in particular is not -- it is a joint venture agreement, it is the governance for the facility, how the two partners will work together, the roles that the two partners will play on a go forward basis for the next 50 years, as we get closer and work through the FEED, obviously you can appreciate there are additional agreements to be worked through.

We have an understanding from a market perspective, we have an understanding from a supply perspective as well and how those will go forward, but at this point those are still to be executed as we move into the -- through the FEED phase. .

Do you have a preferred contractor level that you're looking for the project, when you're -- conducting these negotiations?.

We continue to look to -- we've referred to [ harmonizing ] the project and we're looking to work with equities, with our partners and derisk the project as best as possible.

We'd like to with Pembina's model and through that some of our revenues are -- come from a fee-for-service type perspective and we're looking at what level that should be on a go forward basis. .

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

I have some questions with respect to your crude oil midstream business. Can you comment on the factors that contributed to some margin compression in your crude oil midstream operations, was it may be a producer outage namely Syncrude or some other factors.

And how might we think of them continuing in Q3 and beyond, is this just kind of a blip or is there may be some sort of a secular shift in the local industry et cetera?.

So Linda, I think there was a couple of different things that impacted it. #1, as we talked about it wasn't an overly volatile quarter in terms of commodity prices with more volatility leads to more trading opportunities as well as storage opportunities, so that was a major driver of the quarter.

We also saw compressed condensate pricing, which limited the ability to import condensate by rail and the products laid on the pipeline, we've seen domestic condensate increase while crude oil has been flat to down, which leads to less opportunities as well. So there was a multitude of factors that happened to the quarter.

As we look forward, we're bringing on our Canadian Diluent Hub in Q3, we have our ENT expansion, those opportunities should more than offset some of the structural changes like the rail imports of condensate into the basin. .

And with respect to your NGL midstream operations, there was some decline in volumes, but that was offset by margins, is there some sort of product mix shift happening or can you comment on some of the dynamics there and whether it might be viewed as temporary or some new trends emerging?.

No, we view it as temporary, I mean if you -- the McMahon Gas Plant without for a month or 6 weeks or something like that, which of course restricted volumes through our younger facility, so as I mentioned on the call we had the third-party constraints both upstream as well as downstream of our facilities third-party constraints, which limited our ability to receive product as well as market certain amounts of product.

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And the margins, can you comment on that, is that a product mix aspect or --?.

Well, like -- with the overall sales volumes being down slightly, you're also amortizing your fixed costs over a less amount of barrel, so there was no real margin compression, but what you did see was propane prices obviously rallied through the first quarter, they were down on the second quarter, so your inventory was a little higher compared to your sales price just because you had rising prices through the winter and then have falling price dynamic in the second quarter.

As we look forward today we've seen propane prices go from low '60s [ amount ] value to I think there's $0.70 to $0.71 today., so we've seen quite a rally in the last 3 to 3.5 weeks in the commodity price outlook. .

And just maybe a more detailed question, your cash flows from operations, you benefited from a prepayment of some sort of project.

Can you comment on the nature of that and how that might be amortized and whether we might expect additional payments like that going forward?.

Yes. This quarter there was a certain number of projects that we essentially built on behalf of the producer funded and then were repaid that capital. So again it goes into deferred revenue. We receive the payments on our cash flow and then we'll amortize that revenue over the life of the contract.

So you would expect that amortization of deferred revenue in a couple of million dollars a quarter for the foreseeable future. .

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

Just want to go back to the crude oil midstream there for a bit and I think during the Analyst Day you'd referenced kind of a run rate -- for that business could be something in the 160 to 180 profit range.

Is that something that you still expect just kind of normalized before projects under service or do you think anything has kind of structurally changed the market where you wouldn't expect that and kind of how do you think it follows on in '17?.

Longer-term, we're comfortable with that run rate. As Scott said, the Contango came out of the market in the second quarter and some other little things going on there, but we're not ready for this year to say we're not going to hit that run rate, but certainly over a multiyear time frame we think that's still a good number. .

And then just from a high level point of view, you have a lot of projects entering service in the back half of the year.

And just wondering if there's any guidance you can provide us on a modeling level as far as what type of ramp to expect, is the kind of some of these contracts like day one flip the switch in their cash flowing or is there a ramp there, do you expect more of an increase going into 3Q or going into 4Q, is there any kind of goal post that you can provide there?.

Sure. And I think if you dig through the details, we tried to be explicit.

So for example, our North East BC and our North West Upgrader projects, those are two of our larger projects entering service in the back half of this year roughly $400 million combined, those are fixed return or cost of service deals, those are the type of deals that on day one you flip the switch and you start getting paid full run rate.

When it comes to more of our fee-for-service/take-or-pay, those projects do have ramp. So for example, in our Phase III pipeline, there is a ramp in 17, 18 and 19 and then of course our Canadian Diluent Hub is a fee-for-service asset, so that business is going to depend on volume build on our conventional pipeline.

So there are some assets that will have a build profile through the next couple of years, and then there is another mix of assets that day one start up right away. .

And then just one last one on the Veresen side, if there's any incremental color you could provide at this point with regards to how the process is progressing, have you gotten a second request from the Competition Bureau or anything else that you're able to share with us at this point?.

We're spending a lot of time on integration, we've set up integration teams, real credit to the Veresen staff, they really and our staff are really digging into that, there is a lot of detail, we talk about the assets in their current state, in the future state combined to -- in light of our economic projections, and so far we're not finding anything surprising and we think we can deliver the promises we've given to our Board and the guidance range that [ $2.55 billion to $2.75 billion ] that we've provided you, so far so good.

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And I think, Jeremy, we're not going to give specific commentary, but our guidance from day one has always been consistent, which is we expect to close this in late Q3 to early Q4, nothing is changed. .

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

My question is on your commodity exposure and may looking at perhaps first half of this year, are you guys able to quantify or have you quantified the percent of you EBITDA exposed to commodity prices, was it in line with your long-term outlook above or below?.

Yes, I mean, when you look at both the combined product margin and the frac spread, we expect that to be somewhere in the neighborhood of 17% to 15% overall, and we're roughly in line with that, yes. .

And maybe moving to the Duvernay and then more specifically the -- your long-term agreement with Chevron and I wonder if there's been any change in your confidence or conviction in terms of perhaps seeing some -- the first [ wave ] there as you had through 2018?.

I think as we stated Ben that we continue to advance our engineering on the [ D2 ] facility where we remain very excited about the opportunity.

We remain, we have a lot of confidence about the growth and the potential growth that, that contract will deliver for ourselves and for our customers Chevron in that deal, so we -- our confidence remains very high. .

And if you look at what some of the key players in that area are saying in the press in terms of the amount of money they expect to invest that it's meeting or exceeding our expectations of their investment, so we are remaining confident in that area. .

Maybe just last, a touch up in the conventional and integrity spending and if you comment a bit on Q1 and Q2 and just want to know how the pace of that is looking and then we [indiscernible] it's more normalized in the second half and and how do you think about maintenance CapEx as you -- you had $5 billion of projects over the next 18 months?.

Yes, let's start with maintenance, maintenance CapEx for us is around the year really, so we generally -- we maintain all assets and has new condition and most of the checks we write go into operating costs and are fully recoverable.

In terms of overall corporate integrity spend, we -- I think are at -- in 2016 and 2017 at peak and then we expected to drop, any quarter I would encourage you guys to think of it annually, quarter-by-quarter, I mean if you get a wet spring then you don't do integrity, you roll it into the fall.

So it's weather dependent, it's dependent on getting the the permits things like that, so it will move around certainly from quarter-to-quarter and even roll over, I mean we've seen a lot of times a heavy plan spend in the fourth quarter that just can't get done for whatever mother nature reasons roll over into the next year, but at a macro level we are through -- well through peak spend on integrity and expected to drop quite a bit into '18 and '19 and then stabilize after that.

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

So perhaps I could just start follow-up question on the propane, in terms of what you're seeing right now in demand, how much of this is anticipation of kind of a large crop drying and how much of this -- what is driving the propane price in your mind and what you're seeing today?.

I think the overall North American inventory levels are pretty substantially below where they were last year, and at or slightly below the five year average. So we've seen a slowdown in the U.S. in production and exports continue to pull a lot of barrels out of the Gulf Coast, so I think it's really the inventory levels that are driving at this stage.

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Crop drying is like having a tailwind when you're bike riding, it's such a nice to have, it doesn't really make too much difference anymore.

It's about exports, I think that, that are going to be the difference maker and of course winter weather, those are the two things that are happening and we're super pleased, as you know David, we'd rather be exporting ourselves and we're working hard towards that, but when others do it, it's still creates demand and that's a fundamental difference from say 5 years ago.

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And you mentioned kind of the positive side of some [indiscernible] you've seen in news recently, perhaps if you could just highlight -- in the last 12 months we've seen a fairly large exodus from the WCSB and the oil sands in particular from the international oil companies, how do you think about that exodus, what does it mean for capital investment in WCSB and where does Pembina want to be investing its capital going forward?.

Like running any business, there is a combination of skill and luck and we feel lucky that most of our investment is in the areas where shale and conventional drilling are occurring and less of our investment is in oil sands. We view oil sands as very stable, but may be not rapidly growing business unit over the next number of years.

So we of course believe very strongly in the Montney and the Duvernay and in those assets. Some of that is luck for sure, I mean there is oil sands pipelines that we bid on and would have like to own a few years ago and the luck part is we didn't win all those in our opinion.

So we like our commodity mix, you'll know from our Investor Day post Veresen we expect to be a third gas or third NGL and a third crude oil and condensate and in today's market that feels just really, really good. And again, some of that skill and some of that's luck. .

Also in the [ news ] we saw Braskem's announced an [ FID ] on a polypropylene facility in June, in terms of kind of the competitive dynamics that you have done for the polypropylene PDH facilities.

How does that play into -- that sort of part of what you expected as incremental demand to come into -- supply to come into the market or is that incremental to your expectation?.

Yes, David, it's Stu. We have that always modeled as a facility that would likely be moving forward, and so it was always in our plans, is always in our market analysis.

As we look at the growth and there is some closures, but with some of the growth -- there will be other plants that are added as we go forward, but at the same time the demand is growing and we see opportunity to be very competitive and to serve that growing demand on North America and as needed into other markets around the world. .

Yes, David. Braskem actually announced they are closing a facility at the same time and back to Stu's comment, we observe particularly in propylene [ honestly ] polypropylene that more projects are getting canceled or delayed, deferred, and definitely deferred than we had predicted a year ago.

So if anything -- the supply side of the curve looks in this 5 minutes tighter than what we had thought before. .

And one last question on your CapEx, the $2.4 billion budgeted for Phase III and [ RFS II ] both those projects coming under budget.

Can you provide any sort of color as to kind of the extent to which you're able to be budget?.

Yes, I think in our press release, we talked about the aggregate portfolio coming in roughly [ 8% ] under budget. .

Your next question comes from the line of Andrew Kuske from Credit Suisse. Your line is open. .

I think my first questions is for Scott, and it's just on the Midstream NGL sales volumes.

So if we look at year-over-year relatively positive story, but on the sequential basis it declines quite steeply, you mentioned some of the factors in the market that really affected that, but just from a Pembina standpoint to what degree were you effectively derisking activities, because you just viewed the market environment is being poor and you weren't willing to put on that risk in the market versus effectively losing market share?.

Yes, well I think there's a couple of dynamics going on like obviously Q2 is going to be lower than Q1 just because our winter sales, we sell about 66% to 70% of our volumes in Q4 and Q1 with the rest in Q2 and Q3, just to the nature of the propane business. So that's one impact sequentially, but that business over time we have sequentially derisk.

So despite the fact that sales volumes are going to move around that business is much more stable because of course RFS II is a fee-for-service business, almost 100% contracted, so while volumes may move around the margin in that business should remain relatively stable as we put on more fee-for-service business. .

And then just maybe a bigger broader question, when you look at the closing of the Veresen deal coming up later on in the year, how do you think about just the overall portfolio and what pieces are you effectively missing?.

We love the portfolio, honestly the ability to offer our customers gas service, I think it was a big missing piece we can do that indirectly through alliance, having the alternative NGL market [ hub ] down and our [indiscernible] is tremendous integrating Veresen midstream assets they are physically connected to our asset base and they've got just a ton of capacity turning on which is going to ramp up our NGL and condensate volumes on our system.

Thinking about Jordan Cove, Western Canadian producers can readily get their physical gas to where Jordan Cove is going to be and I think they want to look at export.

So it's fantastic, I mean in my dream of dreams, of course an [indiscernible] which connects all of our asset and my dream of dreams, we would be able to get physical gas on Pembina owned infrastructure down the Jordan Cove, but I don't think that dream is going to come true any time soon.

But we couldn't be more pleased the way this asset base as a potential to work together. .

So then maybe just a follow-up on that and putting aside the dream on dreams and then the physical connectivity issue there, but with the existing assets that you're about to paste together, do you anticipate having even a bigger multiplier in some of the businesses that effectively or the glue that binds a lot of things together and really moving a molecule from well head in the effectively terminals and marketing efforts.

Do you anticipate a better multiple then is already in the numbers now?.

Even internally, we have not model that bigger multiplier, we've counted on certain G&A synergies, certain operating synergies, certain revenue synergies.

My instinct though as we build out gas marketing capability similar to that we have with NGL and crude oil marketing capability that there is significant -- that multiplier you talked about, there is multiplier possibilities on the gas side and on the Redwater NGL hub versus Aux Sable NGL hub.

So we're early days investigating those, but it's going to be really exciting to see what's possible there once we get all the combined organization in a room. .

Our final question comes from the line of Robert Kwan with RBC Capital Market. Your line is open. .

If I can go back to -- there was an answer earlier around, are you reviewing the contracting structure for the proposed PDH/PP facility, and if so, why the difference on the half of your half?.

No.

We're still working towards half of the half, the discussion we -- I thought was more around the contracts that we have signed and as Stu mentioned their joint venture contracts their -- what kind of technology we're going to use contracts and then coming out of FEED is there going to be whose building this for us contracts? We have not embarked on the entire commercial, because we don't have a rock solid capital cost estimates.

So Robert, you can imagine, if we go to a producer and say how would you like to turn your natural gas into gas plus NGLs transported frac, it turn it in your propane into propylene and then polypropylene, we need to know what the fee is for that service.

And without the capital cost estimate we can't quote that fee, but we are having hypothetical discussions with people strategic discussions around, hey, would you rather sell polypropylene or propane? And there is significant interest in that, but we can't quote fees until the cost estimate is done, but our target remains -- our straw dog remains half of our half, will be fee-for-service.

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And I guess, as part of those higher levels discussions that you're having.

I presume, is it mostly with producers versus interest on petchem's -- and from the producer perspective, is it largely customers that are already customers of yours, i.e, kind of accessing this is part of your Pembina value chain or do you -- are you seeing a lot of one-off interest as well?.

We're getting interest from those, we might expect to get interest from, but there is other people that we hadn't considered coming forward as well.

People who have our developing large asset basis in the basin that are also in polypropylene business, so it's interesting we've had calls actually in the last number of days from some companies we didn't expect that to show interest, but I think Stu and the team have made very solid progress and the world is watching us move towards a sensible measure development process and they are gaining confidence that this thing is unfolding in a sensible way.

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If I can just shift to crude oil midstream. Scott, when you answered the question earlier, I think you were really exciting kind of all the fact you had in the MD&A around the year-over-year commentary.

Just wondering, do you have any sequential commentary i.e., versus Q1 17 as to some of the dynamics that changed between Q1 and Q2 for the crude oil side?.

A lot of that again was the volatility, so in -- so we did see some incremental volatility in Q1, which we didn't see in the Q2 time frame.

There was also on the sequential basis quarter-over-quarter, there was some small 13-month adjustments that flow into Q2 that weren't in our Q1 result, so nothing materially different than the quarter-over-quarter results. .

If I can just maybe finish with the new infrastructure you've noted its operating well, I'm just wondering if it's possibly a little bit more granular in terms of where the volumes you're seeing flowing versus the minimum take or pay levels?.

Well, I mean I guess like [indiscernible]. Volumes are basically in line with what we're expected to happen and what really with the producers were telling us were going to happen. Obviously we have a lot more information at the end of Q2, it's only been on for a month here.

And the ramp up in volumes are sort of a combination of production, it was already flowing on IT, a lot of it was going to other pipeline systems on terminals and some that was shut in.

So we expected to keep ramping up, frankly, as Scott alluded to for the next of couple years as we get some winter drilling seasons, but they are basically in line with what we've got and what the producers were telling. .

I would now like to turn the call back to Mick Dilger, Pembina's President and Chief Executive Officer for closing remarks. .

Well, thanks everybody for the time on the call today and for your ongoing support. Again I just want to reiterate how proud I am of Pembina's team, imagine turning $3 billion worth of stuff on and having it work on the first day and the safety record people maintain. So hats-off to the staff. Thanks and have a safe and enjoyable summer. .

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