Pembina Pipeline Corp (PBA) 2016 Q2 法說會逐字稿

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

(Operator Instructions)

Mr. Scott Burrows, you may begin your conference.

Thank you, Kirk. Good morning, everyone, and welcome to Pembina's conference call and webcast to review our second-quarter 2016 results. I'm Scott Burrows, Pembina's Vice President of Finance and Chief Financial Officer. With me today are: Mick Dilger, Pembina's President and Chief Executive Officer; Stu Taylor, Pembina's Senior Vice President, NGL and Natural Gas Facilities; and Paul Murphy, Pembina's Senior Vice President, Pembina Pipelines and Crude Oil Facilities.

Mick will start shortly with a few highlights from our second quarter. I'll provide an overview of our results, which we released yesterday after markets closed, and then Stu and Paul will give an update on Pembina's growth projects. I'll wrap things up, and then open the call for questions from the investment community.

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, 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.

Good morning, everyone. It's Mick Dilger. It's my pleasure this morning to highlight a few of the successes Pembina had in the second quarter and in the first half for that matter.

We generated the second highest quarterly operating income since 2014, and nearly broke our record for quarterly record volumes. We closed the CAD566 million acquisition of the Kakwa River facility, strengthening our strategic position in one of our core areas, and are, we believe, in some of North America's most prolific geology.

We placed several large-scale assets into service including RFS II, Musreau III and the Resthaven expansion, among others, totaling over CAD1 billion so far this year. These projects were collectively brought into service safely and under budget, which was a great accomplishment by our staff, and one that I'm very proud of. We received regulatory approval for the largest section of the phase III expansion, and are now in full construction mode.

We announced feasibility studies for an integrated polypropylene facility, which Stu will discuss later in the call. And we enhanced our footprint in the Duvernay through an additional CAD130 million of infrastructure to support our now fully-contracted Duvernay I facility.

As you can see, we had a very, very busy and productive first half of the year. Our businesses are performing well, and we are successfully executing the growth strategy we laid out over the past few years. I'm excited that we are on track to deliver significant cash flow per share growth through 2018.

With that, I'll pass the call back over to Scott to review our financial results.

Thanks, Mick. I am very pleased with Pembina's financial results during the second quarter and first half of 2016. Despite a few operational challenges during the second quarter, and a challenging macro economic environment in the earlier part of the year, our underlying business remains resilient. Our results also benefited from revenue associated with the growth projects that we have recently placed into service.

Pembina's operating margin for the second quarter of 2016 was CAD327 million, a 26% increase over the CAD259 million we earned in the second quarter of 2015. Year to date operating margin was up 18% at CAD642 million, compared to CAD543 million for the same period in 2015. These improved results were mostly due to increased volumes on our conventional pipelines, and in our gas processing segments, RFS II coming into service, and increased NGL product margin.

Higher operating margins supported adjusted EBITDA of CAD291 million in the second quarter, a 28% increase compared to CAD228 million in the second quarter of 2015. So far in 2016, Pembina generated adjusted EBITDA of CAD560 million, a 19% increase over the CAD469 million in the first half of 2015.

Higher gross profits and lower taxes were partially offset by higher net finance costs and general and administrative expenses, resulting in earnings of CAD113 million or CAD0.25 per share for the second quarter of 2016. This compares to CAD43 million or CAD0.09 per share for the same period last year.

Earnings for the first half of 2016 were CAD215 million compared to CAD163 million or 32% higher in the comparable period in 2015, as a result of the same factors impacting the quarter. Cash flow from operating activities increased to CAD273 million in the second quarter of 2016, compared to CAD209 million last year. This was largely driven by an increase in operating margin and lower taxes paid, partially offset by a decreased change in non-cash working capital.

Year to date, cash flow from operating activities is impacted by greater operating margin, a favorable change in non-cash working capital and lower cash taxes paid, resulting in cash flow from operating activities of CAD544 million compared to CAD329 million in the same period of 2015. Adjusted cash flow from operating activities increased year over year as a result of increased cash flow from operating activities, net of a decreased change in non-cash working capital, reduced taxes paid, and lower share-based payments, partially offset by additional preferred share dividends.

In the second quarter, Pembina generated adjusted cash flow from operating activities of CAD235 million or CAD0.60 per share. This compares to CAD176 million, or CAD0.51 per share last year. The same factors contributed to adjusted cash flow from operating activities of CAD444 million, or CAD1.16 per share for the first half of 2016, compared to CAD389 million or CAD1.14 per share for the same period.

In the second quarter of 2016, conventional pipeline saw robust quarterly revenue volumes of 648,000 barrels per day, a 7% increase compared to the 603,000 barrels per day in the second quarter of 2015. Year-to-date revenue volumes were 659,000 barrels per day, compared to 618,000 barrels per day during the first half of last year. Revenue volumes grew as a result of the Phase II expansion completed in April and September of 2015, new connections that were placed into service, and increased volumes on the Vantage pipeline.

We did see a slight dip in volumes from the first quarter of this year due to outages at a third-party refinery, and flooding in BC, which impacted our Western system, as did scheduled and planned outages at some of our gas service assets.

Operating margin within conventional pipelines was CAD127 million for the second quarter, representing a 25% increase over the same period last year. So far in 2016, operating margin within the business was CAD255 million compared to CAD200 million recorded in the comparable period in 2015.

In gas services, revenue volumes for the second quarter were a record 795 million cubic feet per day, compared to 647 cubic million feet for day in Q2 of 2015. Revenue volumes increases a result of the acquisition of the Kakwa River facility, as well as Saturn II and [C] coming into service in August 2015. Operationally, there were the challenges within this business, including both scheduled and unscheduled outages at Resthaven, and a fire incident at Saturn II, which somewhat offset increased volumes from assets recently placed into service. Resthaven is now back up and running, and we expect to bring Saturn II back up next week.

Operating margin within gas services increased by 31% to CAD46 million for the second quarter, compared to CAD35 million in the second quarter last year. On a year-to-date basis, operating margin increased 15% to CAD83 million, compared to CAD72 million in the six months ended June 30, 2015. So far in 2016, the estimated impact of the Resthaven and Saturn II outages is nearly CAD15 million, and we have insurance claims pending for the insurable portions of the lost revenue. We will be able to provide an update on the third quarter once we have made the claims.

In our oil sands and heavy oil business, we saw stable performance, as expected, with second-quarter operating margin of CAD34 million compared to CAD35 million in the second quarter last year. For the first half of the year, operating margin dipped slightly to CAD67 million from CAD70 million in the comparable period of 2015. The modest decline is related to lower interruptible volumes.

In our midstream business, operating margin for the second quarter of 2016 was CAD118 million compared to CAD86 million for the second quarter of 2015. The stable to improving NGL sales environment helped improve results within the NGL segment of our midstream business, further supported by RFS II being placed into service. On a quarterly basis, volumes increased by 27%, while on a year-to-date basis, they were up 16% compared to prior periods. These factors resulted in an operating margin of CAD72 million or 80% higher than the second quarter of 2016. For the first half of 2016, operating margin was CAD145 million, compared to CAD109 million in the first half of 2016.

Operating margin in crude oil midstream was in line with the results recorded in 2015. Year-to-date results were impacted modestly by lower volumes at our terminals, which was somewhat offset by increased condensate volumes. Operating margin for the second quarter of 2016 was consistent with the second quarter of 2015, at CAD46 million. For the first half of 2016, operating margin decreased slightly to CAD87 million from CAD90 million in the first half of 2015.

Before I wrap up my section, I want to touch briefly on Pembina's financial position, so you can see how we plan to fund the growth Paul and Stu will talk about next. As noted on the first-quarter conference call, Pembina continues to have exceptional access to the capital markets. So far in 2016, Pembina has raised CAD765 million through three offerings of preferred and common shares to finance their growth projects and the Kakwa River acquisition.

As of August 4, our CAD2.5 billion credit facility was approximately CAD345 million drawn. Pembina's financial position remains solid, supported by a strong balance sheet, ample liquidity, increasing internally generated fee-for-service cash flow, and a high dividend reinvestment program participation rate. With the majority of Pembina's CAD5 billion plus of secured growth projects coming into service by mid-next year, the need for external capital continues to diminish. Combined, these factors create resilient financial outlook and visibility to long-term dividend and cash flow per share growth.

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. As Mick mentioned, the big highlight for us this past quarter was the Alberta Energy Regulator's approval of the Fox Creek to Namao pipeline portion of our Phase III expansion project. Our teams are now out in the fields, and have kicked off construction on this 270 kilometer twin-pipeline project.

In addition to beginning construction on the Fox Creek and Namao pipeline, our construction teams have also begun fieldwork on nine separate new or upgraded Phase III pipeline pump stations. The estimated mechanical completion date for the pump station is the end of the year. The combined Phase III project is now over 40% complete, and the project continues to trend under budget and on time, for a mid-2017 in-service date.

In addition to the primary Phase III expansion project, Pembina continues to develop new gathering laterals to extend the reach of our pipeline network. In aggregate, these investments are expected to require capital of approximately CAD300 million, including projects that have recently been placed into service. The Karr lateral, worth 30,000 barrels per day of capacity for new Alberta Montney formation production, was completed during the second quarter. The Altares lateral in Northeast British Colombia, announced earlier this year, is expected to be completed by late 2017.

Numerous other laterals are at various stages of development, and are expected to be placed into service during 2017. Pembina has completed engineering and submitted regulatory and environmental applications, in support of our major Northeast British Columbia expansion. Initial capacity of the 147 kilometer pipeline is estimated to be 73,000 barrels per day, at an expected cost of CAD235 million. The project remains on track for a late 2017 in-service date, subject to receiving regulatory approvals, which are expected this fall.

Vantage pipeline expansion is nearly complete, and we expect to place this project into service in September, once we have received the customary leave-to-open approval from the National Energy Board. The project will add an 80 kilometer lateral, one new receive point, and increase the mainline system capacity to approximately 70,000 barrels per day, from the initial capacity of 40,000 barrels per day.

Overall, Pembina's conventional pipeline business continues to have strong contractual underpinnings. We have now secured over 775,000 barrels per day of firm service contracts for the transportation of crude oil, condensate and NGL across conventional pipelines. Construction has also began on our crude oil business's Canadian diluent hub in Fort Saskatchewan. The initial civil engineering groundwork is nearly complete, and the crews will be mobilizing next week to begin erecting the 0.5 million barrels of storage tanks to be built on site.

In combination with the existing cavern storage at Pembina's Redwater site, CDH will have access to diluent storage capacity of 1 million barrels, and an aggregate takeaway capacity in excess of 400,000 barrels per day through multiple diluent delivery pipelines. The project has a targeted in-service date of mid-2017, to align with the in-service date of the overall Phase III expansion.

I will now hand the call over to Stu, to provide an update on growth projects within our NGL value chain.

Thanks, Paul. Pembina was very pleased to have closed the acquisition of the Kakwa River facility during the quarter. The assets are ideally situated, within one of our core areas, and for me personally as a geologist, I'm excited about the potential of the underlying resource.

By expanding our service offering to include sour gas processing, Pembina is well-positioned to capitalize on the future liquids-rich gas production growth within the Montney. The acquisition is underpinned by long-term take-or-pay commitment, and has a producer expansion option which creates a foundation for future growth. In early July, Paramount announced an agreement to sell their Kakwa acreage to Seven Generations Energy.

We see this transaction as a win-win for both parties. Paramount realized significant value for their shareholders and continued participation in the area through Seven Gen share ownership. While Seven Gen is able to consolidate their land base and substantially grow their production. We look forward to working with Seven Gen going forward, and building on what has been a very strong relationship.

Also during the second quarter, we brought in an additional 200 million cubic feet per day of gross processing capacity into service, through the completion of an expansion at Resthaven and the Musreau III facility. Both of these projects were finished under budget and on or ahead of schedule. We continue to make strides to advance our strategic positioning in the Duvernay, and are committing CAD255 million through our now fully contracted Duvernay I facility, and recently-announced supporting infrastructure.

With the Duvernay attracting some of the world's largest producers, meaningful improvements in well cost and resource potential measured in billions of barrels, Pembina sees significant future development opportunities for this play. Engineering is now over 80% complete for the Duvernay I facility, which is the first large-scale gas processing plant designed specifically for the Duvernay production.

Construction teams are working on site, grating and piling activities, subject to receiving regulatory approval for the supporting pipeline, Duvernay I is expected to be in service in the fourth quarter of 2017. The project continues to trend on time and on budget.

On May 31, 2016, Pembina announced it has entered into an agreement to construct infrastructure associated with the Duvernay I. The supporting infrastructure includes condensate, gas and water fuel handling, a gas gathering trunk line, and a fuel line for total expected capital cost of approximately CAD130 million. The field hub, as we're calling it, is committed under long-term fixed-return agreement and will connect the customer's development well pads, providing separation, stabilization, and other supporting services.

In addition, Pembina will also construct a 35 kilometer gas gathering trunk line between Tony Creek, Alberta and Fox Creek, Alberta, that will connect the field hub to the Duvernay I plant. The field hub will also connect Pembina's Peace Pipeline system. The in-service date of the project is expected to align with the Duvernay I plant, subject to regulatory and environmental approval.

Also during the quarter, one of Pembina's customers at Resthaven filed for receivership. An investment bank has engaged to sell the assets, and in the meantime, we are continuing to process those volumes. At this time, we do not expect any material impact at Pembina to result from the short-term setback, given the strength of the underlying Montney geology.

Pembina is well on its way to becoming one of the largest third-party gas processors, inclusive of our Younger and Empress facilities within the NGL segment of our midstream business, Pembina expects to have approximately 4.2 billion cubic feet per day of gas processing capacity by the fourth quarter of 2017.

Now onto the growth project within the NGL segment for our midstream business. During the second quarter, Pembina commissioned its second 73,000 barrel per day fractionator out at the Redwater site, and completed an expansion on rail infrastructure at our Corunna, Ontario site, which was part of our broader expansion project, including storage, truck racks, and brine ponds. RFS III continues to trend on time and on budget, for a Q3 2017 startup. Regulatory and environmental approval has been received.

All long lead items have arrived on site. Piling and foundations are finished, and the depropanizer and debutanizer have been set in place. Overall construction is now approximately 55% complete.

With regulatory approval in hand for our terminalling infrastructure associated with the planned NWR Sturgeon refinery, construction has begun. Detailed engineering and procurement activities are 75% complete, and over 90% of the material and equipment has been ordered. 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.

In early April, Pembina announced a joint feasibility study for the evaluation of a world scale integrated polypropylene facility in Alberta, with Kuwait's petrochemical industries company, PIC, which may create an opportunity to develop crucial new market demand for propane in our province. Building local value-added infrastructure to help maximize the proceeds that our customers receive for their propane production, as well as benefit the province by increasing regional economic activity.

The facility could consume 35,000 barrels per day of propane, and produce up to 800,000 metric tons per year of polypropylene. The project leverages our position as the Western Canadian sedimentary basin's largest fractionator, and extends Pembina's integrated NGL service offering. Pembina and PIC have advanced their detailed technical, financial, and commercial study. The study is expected to be completed by the fourth quarter, and if favorable, the feed base will commence in early 2017. We're very excited about this opportunity, but still have a lot of work ahead of us to determine if the project is feasible from a technical, commercial, and financial perspective.

You'll also note that we made a CAD60 million land purchase in the Alberta industrial heartland, adjacent to our Redwater facilities. We expect to use 2,200 acres of land for future strategic fee-for-service infrastructure development, which could include additional fractionation facilities and associated services, or in association with our potential PDH and PP facility.

Scott, back to you.

Thanks, Stu. We're pleased with the strong financial results and growing volumes in our businesses. Our teams are doing a great job of advancing our over CAD5 billion of growth projects, all of which are expected to be in service by the end of next year. These projects are set to add CAD600 million to CAD950 million of incremental EBITDA by 2018 compared to 2015. As always, we will continue to keep our focus on operating and growing our business in a safe, reliable, and cost-effective manner.

With that, we'll wrap things up. Operator, please go ahead and open the line up for questions.

(Operator Instructions)

Linda Ezergailis, TD Securities.

Maybe I can just start off with a question that might not be the most important one, but certainly I'm a bit curious about. Can you help us understand the business case for building a co-gen at Redwater, given where power prices are, and appear to be for the next little while? Is it a reliability consideration, or a real cost consideration, or can you walk us through your logic?

Yes, certainly. It is quite simple. We just see the transmission costs increasing over the next number of years in the province, and with the discontinuance of coal, we believe prices are going to go up. Many of our customers are of like mind, and wish to capture those savings.

And when the dust settles, we think that this asset will be at least half if not more fee for service. And we think it's a good bet to take the spark spreads on the balance. Linda, of note, we already have a co-gen in that area that services ROF and RSI.

Okay, thank you. And as a follow up, in terms of your NGL business, can you just give us an update on what you're seeing in terms of pricing, and a supply-demand outlook, and specifically, I know it's still early in the quarter, but maybe you can talk about how things are looking right now, and some considerations in terms of what the balance of the year might like?

Yes, Linda I think I'll answer the question in little bit high level. We're not going to talk specifically about potential quarterly results. I mean, if you follow the trend certainly through Q2, we did see price recover pretty significantly over Q1.

That being said, with the latest pullback in oil prices we have seen, we have seen the propane price drip down in that CAD0.41, CAD0.42 per gallon. So higher than Q1, but lower, a little bit lower than where we were in Q2.

That being said, when we went into this year, obviously with the volatility and the challenges in the first quarter, we made an effort to hedge more of our propane barrels for the 2016 timeframe. As we moved through the last year of that major build out. So, despite some volatility in the pricing, we have significantly more of our NGL barrel hedged this year, especially through the end of the year, which will help protect us on any price depreciation.

In terms of the outlook, I think as we have talked about a few times, there's pros and cons. The pro being Canadian inventories are very low right now, and below historical levels. And so what we're seeing there is a tightening of the differential to some of the US benchmarks.

That being said, with the inventory levels in the US, it's obviously put downward pressure on any rising prices there. So while we don't see necessarily huge upside at this stage in the US pricing, we do see the differentials compressing with the Canadian inventory levels.

That's very helpful context. On just one final follow-up question. 2017 hedging propane? Can you comment on where you at, at this point now?

We don't have a significant amount hedged, but we're looking at that as we go through and are doing a more detailed of our 2017 budget. So more to talk about probably on our Q3 conference call.

Great, thank you.

David Galison, Canaccord Genuity.

So just a first question on the Kakwa asset acquisition. So with the change in customer to Seven Gen, could you maybe talk little bit about any potential benefits that you might see from acquisition, outside of maybe having a bit of a stronger counterparty?

I'm going to start off, and Stu will no doubt add some color. Just with Seven Gen's activity, they released their quarter recently. We just think, and their access to capital, we can fill the plant faster than we first thought.

We were looking at a few years to fill, that may in fact happen a little sooner. So I think that's the primary benefit.

Also as you know, there is an expansion feature in that transaction. And again, perhaps it can be accelerated.

I think you've nailed it, Mick. We had a ramp up, a build up of the volumes coming through the assets. With Seven Gen's level of drilling, their existing pads, the opportunity to ramp up earlier. We think we have an opportunity to exceed that ramp up forecast and move forward.

Their access to capital, we can see that they can drill that and fill that infrastructure faster than we anticipated. And then at the same time, that allows them to, we think we'll have expansion kicked up faster than we originally anticipated.

With the capital that Paramount received, and also the focus, we think we're going to see increased drilling behind our Resthaven asset. So with both companies now with core areas and focusing on competing, we think we're going to see both areas ramp up due to that access to capital and the infrastructure.

And then maybe a question for Scott. With the hedging for your propane in 2016, do you have an idea of what the updated sensitivity might be for the rest of the year?

Not on a hedging basis. I mean, at the end of the day, when we set the hedging previously, and we talked about the CAD0.10 per gallon being CAD30 million, that contemplated the hedging we had at the time. And we've increased that hedging, so that sensitivity would be down, David, but I don't have a number for you off the top of my head.

Okay, all right. Thank you very much.

Rob Hope, Scotiabank.

Maybe looking a little bit more broadly, just wondering how you are approaching the M&A market right now, given that you have recently done a relatively large acquisition, and I guess also with the color that you have done a number of capital raises over the last 12 months?

Yes, I guess the same way we have always looked at it. Focusing on assets that we can -- are or can integrate into to the value chain, and the market still is competitive.

There's lots of very capable parties besides Pembina out there, but we do have advantages in our core area. I think the Kakwa River opportunity is evidence of that.

But we're looking at it opportunistically with the CAD5 billion of growth that we're about halfway done paying for, we don't really have to do anything to drive our cash flow per share accretion, so we can be selective. But also, we have a very good multiple on EBITDA, I think still the highest in our sector. Which gives us the ability to acquire the assets that really make sense for us.

All right, that's hopeful. And then one follow-up question. Adjusted term of your conventional pipeline business, could you add some color on I guess the outlook for integrity and maintenance spend for the back half of the year versus the front half of the year, and into 2017?

Yes, again, without getting specific on numbers for quarterly guidance, what I can say is that that the second half of the year should be above where we were in the first half of the year, and the first half of the year with the warm winter we had, there was a certain amount of the program that we just couldn't get to. So we would expect our integrity spend to increase in Q3 and Q4 this year, compared to where we were the first half of the year.

And then longer term I think it's hard to say, you never know with these kind of freak flood events that you have, but generally, we are at a peak and trending down over the next number of years. The next heavy lifting for geotechnical, craft tool runs, facility integrity, we have or are going through peak spend, and we expect that to trend down into 2018.

All right, that's helpful. Thank you.

Robert Catellier, CIBC World Markets.

I wonder if you could start, and might be a little bit early for this discussion, but maybe you could provide some color on what you have discovered so far in those technical and market feasibility studies for the PH. Specifically, what do you see at this point as the biggest challenge to getting to PDH?

Rob, it's Stu. So far to date, everything that our original thoughts, our regional evaluation, has been confirmed. It is still very early days I have got to qualify with, but we are still excited about the opportunity. There appears to be from a market side that there are markets and growing markets for polypropylene within North America and globally.

We're still very early days. Our licensure selection process is underway. That evaluation is ongoing.

We continue to hope to see the results coming in, as we expect. Again, that's where everything is standing. We pushing very hardest in a very aggressive schedule with a hard push in the last quarter.

But I think part of our confidence is demonstrated by the land purchase. We went out and secured a significant block of land in the Alberta industrial heartland, to grow, and to grow these assets or similar type assets and future growth opportunities that we haven't thought of yet.

Yes, it does seem to be an awful lot of land, even for the PDH.

I'll just take that one. That was the size of land that was for sale. So we've subsequently slipped off a few smaller partials. We have that flexibility. We got a good fair price for that.

We may not need it all, but they're not making any more adjacent land to Redwater, and so that, so I think it's wise to hold that, and it really doesn't pose a risk. Land always has value, so it's always an asset generally going up in value. So we looked at it the other way around. The risk was not buying that land.

Right. And just back to the PDH for a second. So with what you know at this point, are you still confident that the project can be done with a free structure that's similar to your current profile? In other words, predominately fee-for-service or class of service in a manageable amount of commodity price risk?

What we can say is that we've gone and taken all you folks through our guardrail. And those remain our guardrails. Whether this particular project is a little bit of fee-for-service or a lot, generally we want to be, have a good component of fee-for-service, and we think that is possible here. At the end of the day, we will stay within our guardrails.

Okay. And then just finally on the propane terminal, wasn't really all that much color in the press release. You're still looking at multiple West Coast sites, but how close do you think you are to being close to selecting a site?

Rob, it's Stu again. We continue to do work. We continue to progress conversations. It's difficult to say how close we are, and sometimes there's work and issues that still need to be addressed at every site that we continue to look at.

We have made some progress. It's hard to predict how close we are, until all those conversations are completed. We still believe there's opportunity. We believe we have a team that is looking at those opportunities.

Where perhaps a bit more cautious in going forward and how we announce that, making sure that as we go forward, we can complete the project as we announced it, and subject to acceptance and approvals of whatever is required in that particular site. So we're doing our due diligence on each of the sites, in detail, and trying to make sure that when we do make a declaration, that we can complete that.

Okay, fair enough. Thanks.

Andrew Kuske, Credit Suisse.

I guess the question is more on an M&A bent, and if we just think about asset packages that have either transacted or are in the market right now, you get a bit of a dichotomy of some assets that have relatively high valuations, and typically associated with highly contracted cash flows, versus the other end of the spectrum, that tend to have low valuations but are very activity or commodity sensitive. What do you think offers the best value proposition right now, just in a generic sense? I know it's a bit of a difficult question, but are you seeing any trends from a valuation perspective, has the valuation spread between those two broad classes gone just too wide?

That's an interesting question. If you think of one side of it, highly contracted, high EBITDA multiple required, so on and so forth. If we look at that and model the accretion against our currently-projected outcome, it isn't accretive to us often. It's a boat anchor in increasing our cash flow per share. So we're quite cautious on that side.

On the other side, we work very hard to get up to 80% fee-for-service. So we don't want to blow through that guardrail. So each has pros and cons. And we just have to assess each opportunity separately.

Okay, that's helpful. And then maybe an extension of that question, you have done a great job on certain assets, and not to be patronizing about it, but there's assets that bought in the past that maybe carried a bit more risk, and you de-risked them fairly quickly. Do you see that playing into some assets where you see a hidden value that maybe others don't see?

Again that's part of bringing the integrated value chain, and exploiting those assets. Clearly, when we acquired Providence a number of years ago, we were on the higher risk end of the spectrum, but we saw a great opportunity to grow on a fee-for-service basis, and re-contract on a fee-for-service basis.

So for sure, we look at every asset. I mean, even our petrochemical joint venture, that's not -- if we can do part of that on fee-for-service, that's not how those assets are done normally. But we think that with producer interest, some or, say, half of that, could still be done in a fee-for-service basis. So bringing the integrated value chain does give us opportunity to de-risk certain assets.

Okay, that's helpful, and then one final question if I may, and it just relates to competitive pressures. Are you seeing any increased competition or any significant signs of life from the MLP market competing in assets that you're interested in?

Not that I'm aware of. Scott, have you?

Not that we're aware of.

Okay, that's very helpful. Thank you.

Robert Kwan, RBC Capital Markets.

Maybe just kind of following on that topic here. How far outside of the guardrails would you be comfortable, out of the gate, on something that has commodity exposure, if you see a path to derisking, and how long would you be comfortable being outside of those guardrails? I don't know if that could measured in years.

Good question. If we were to go to the guardrails, and keep in mind, we've worked pretty hard to be in the guardrails. It's taken us a whole bunch of years, whether we're talking about just fee-for-service, but also on a payout ratio, recall, if you look four or five years back, we were at 100% payout ratio, and we are trying to work toward seeing 90% of our fee-for-service. So that's been a lot of heavy lifting.

If we were to get outside the guardrails, we're going to think long and hard about it. Were we though to do that, I think we wed lay out a plan to our investors on how and when we would get back in and maybe a couple of years, I'm just speculating. But either we would buy an asset, let's say, and if the asset itself would have fell outside the guardrails, we would add fees for service maybe through another acquisition, or a Greenfield to balance that out.

So there's two ways to do it. One is to modify the asset you bought. The other one is to grow your fee-for-service. So we always look at our 80/20 portfolio in terms of what room we have to maintain the guardrails.

Okay. And then just on the propane outlook we've seen a bit of a roller coaster this year, with all the exports at the beginning of the year, but now with cargos being rejected, does any of that change your thoughts on propane exposure as you go forward, whether that's how you shape any of your projects, the contract structure of this project and then just the general procurement strategy of barrels coming out of the field?

Not at this time. Things are moving around quite a bit, and we have to look at consensus oil prices as an indication of propane prices. Scott said, Canadian inventories are pretty low, and we're always one cold winter away from this being in the rearview mirror at least in Canada.

I would say though if -- as prices remain soft, I think it's all the more reason to look at projects that are value-added to propane. It just kind of gives us a tailwind to work extra hard on those kinds of project Stu has talked about.

Okay that's great. And if I could just finish on turning to Kakwa and the 6 to 18 expansion, you've ended up with a nice counterparty. I'm just wondering though, do you have a sense as your thoughts on 6 to 18 given Seven G's general bias to owning their own infrastructure?

Well there was, Pat Crawford, I saw an article in the Herald that he used the words that Pembina was I think a strategic partner. Is that the right wording?

Yes.

So I don't know exactly what that means, but I haven't met with him in the last few weeks, and he got a little busy trying to close this deal. So I think the possibilities are there. We've toured those guys through our sites.

I think they are favorably impressed, and they have a lot of locations to drill. And it could be a matter of capital allocation but I don't answer, but I was pleased with the way he described Pembina in that release.

That's great. Thanks very much.

Steven Paget, FirstEnergy Capital.

My question is for Stu Taylor. Stu, when we look at Pembina's gas plants from Cutbank to Resthaven, which of these plants are full, and which could use more volume?

They're spaced, Steven, from a physical capacity perspective, we can use more volumes, at every one of the plants. Contractually, we're sitting in good shape. The volumes are up there for most cases.

We're up in our Cutbank area in the Musreau area, we're running at higher utilization rates there. Resthaven, we've got our expansion, the Phase II expansion completed. We've had some issues with some of the equipment, which we've worked through. Were back up and running as Scott's already mentioned, and there's room for growth.

Obviously the situation with the receivership has delayed some volumes into Resthaven. That is contracted space, but there is physical capacity available. We're not looking at substantial underutilization, we're in that 80%-plus range and always looking to tie in more barrels and more gas.

Thank you, Stu. My second question, could someone please comment on the performance of RFS II in June compared to April and May?

RFS II is fully operational. When we first started out we had some issues with ethane seals, they weren't holding. And our current understanding and observation is that that problem is now repaired.

Excellent. Thank you, those are my questions.

Patrick Kenny, National Bank Financial.

Just wanted to go back to the 2,200 acres of land that you picked up north of Redwater. Maybe a bit more color on the optionality there, and I'm thinking more if the PDH facility does not go ahead, will this land be used for Redwater IV someday, more underground storage, rail loading? Just trying to get a sense for how you might best look to integrate the land with the existing Redwater site?

Yes, the footprint we had was the Redwater IV might have been, we could have got it done, but it would have been tight. This journey started with, there's three core sections due North that take us up to the highway. And securing those for Redwater four and five, certainly the province has the geology to support a bunch of new fracs, and of course, additional rail expansion. So that's where the journey started.

The land was bought from the Fort Hills joint venture, and they did not want to be cherry-picked on quarter by quarter. So as I said earlier, the land was for sale in that block size, but we have complete optionality to put whatever we need to do there. Had we been constrained, had someone else bought that land, we would have been blocked in, and what we've learned over the last bunch of years is large scale facility projects that don't have access from four sides get expensive.

You want lay down areas, and work areas on all four sides of a major facility, or it gets expensive. I mean we learned that on the Musreau D cut, where we had a gas plant on three sides of that plant, and on Resthaven, we had a ravine on one side and an existing plant on one side, and it just gets pricy. And so we've gone for it.

And we've got now a decade's worth of growth area for that industrial complex, whatever it ends up being. You know of some the projects we're working on. We are working and different projects that could be located on that site, and as I said, it is an asset, will be an asset, and if we get five years out and we don't need all of it, we'll start to dispose it.

Okay, that's great Mick. Thanks for that. And then maybe just a quick update on the northeast BC expansion, and when you expect to see final regulatory and environmental approvals there? And when you think you might need those approvals to hit that late 2017 in service date?

The stage we're at right now with the regulatory approvals the process called it's gone to the ministers for referral. So we really expect to hear something within about 30 to 40 days, so sometime in September we expect to get the decision. Of course, we're confident it's going to be approved.

As far as getting the construction going, we'd like get started in the fall before freeze up, so it's not absolutely critical, but it's just easier for clearing topsoil and things if we can get started before December. So if we can get approval in September or October, we'll be fine for our late 2017 start up date.

Okay perfect. Thanks, Paul. And maybe less question just for Scott, I believe plan was to keep the DRIP on until at least Phase III comes on mid-next year. But I guess that happens to coincide with the FID for the PDH plant, so wondering if you would lean towards just keeping the DRIP on beyond mid-2017, if the PDH opportunity goes ahead? Or perhaps maybe look towards other financing alternatives at that point?

Yes, just to clarify Pat, originally we had planned on shutting the DRIP off at the end of this year, not middle of next year, to coincide with Phase III. So our original plan was to shut it off at the end of this year. We're looking at that right now as, since we have had that plan, we've announced that the Duvernay expansion, we've announced the co-gen, we announced kind of the going full bore on the PDH, so we kind of had three projects since we talked about shutting the DRIP off at the end of the year.

So we're assessing that right now, in terms of what that looks like. It may be on for another quarter or two in 2017, but I'm not going to commit to that at this stage. We're currently going through our 2017 budget process as we speak.

In terms of the PDH PP, I think that'll be a good discussion on our Q3 conference call. At that point in time we will have a lot more certainty on the feasibility study and go-forward plan.

And as part of that feasibility study, we're going to have a more detailed capital plan, and at that stage, once we know when the capital spend will be, we can have a discussion there. Because based on what I've seen to date, there will not be a heavy capital spend on PDH PP in 2017, and maybe not even in the first half of 2018.

So it would be illogical to leave the DRIP on at that stage, because the funding wouldn't really be needed until the back half of 2018 and really heavily into 2019 and 2020. So at that point in time, absent for the growth, we feel confident that could be funded with internally generated cash flow, so the DRIP wouldn't be required for that.

Okay great. Thanks Scott. Thanks guys.

Nigel Dyer, BMO Capital Markets.

Just following up on the Phase III expansion. I believe you have about 780,000 barrels per day contracted already. Just wanted to see what your confidence on getting additional contracts, given the current environment. And then what would mean for your EBITDA guidance of CAD600 million to CAD950 million?

Sorry we had trouble hearing you there. Was your question our confidence in getting more volumes for Phase III?

Yes, sorry.

We still, are receiving interest on producers on Phase III. So we have 30,000 to 40,000 barrels of capacity of Phase II and III and it we have an easy expansion, as we have discussed previously to put into place, by adding a couple of pump stations. So I mean, we're confident that we'll fill that pipeline.

Yes and just as it relates to our stand on EBITDA growth, we don't need additional volumes to make that happen.

Okay. Thanks. And then maybe just quickly on the CDH storage facility, could you clarify what the contract position of the facility, is if it's fixed fee per volume, and maybe what it would take for expansion potentially later on that down the road?

So that is a fee-for-service asset, but it does not have long-term contracts. But the reality of the situation is that as Phase III ramps up, the capacity into the CRW pool is physically limited, and so the volumes will go to CDH. And that's what's give us the confidence that facility will be well utilized.

We did recently announce downstream connections to most of the major diluent takeaway pipelines, and so the market is in the process of adjusting to really a new reality that you can get your condensate from both CDH and CRW pool rather than really just CRW pool. I would also just clarify that as Mick described the contractual structure there at CDH, none of that is in, when we talk about our CAD600 million to CAD950 million, none of that of the CAD600 million number, so every barrel that we get above zero starts to increase that CAD600 million to the CAD950 million.

Okay great. Thanks.

We have no further questions at this time. I'll turn the call back over to you, Mr. Dilger.

Well, thanks, everybody. We really are pleased with our progress and our first-half results, as well our outlook. I think we're well-positioned financially. We are looking at lots of different opportunities, both greenfields and on the M&A market, and I think we have the balance sheet to support that. So thanks for your support, and thanks to our staff for great work, and I wish everyone a happy and safe summer.

This does conclude today's conference call. You may now disconnect.