Pembina Pipeline Corp. (NYSE:PBA)
Q2 2016 Earnings Conference Call
August 05, 2016 10:00 AM ET
Scott Burrows - VP of Finance and CFO
Michael Dilger - President and CEO
Paul Murphy - SVP of Pipeline and Crude Oil Facilities
Stuart Taylor - SVP NGL and Natural Gas Facilities
Linda Ezergailis - TD Securities
David Galison - Canaccord Genuity
Robert Hope - Scotia Bank
Robert Catellier - CIBC World Markets
Andrew Kuske - Credit Suisse
Robert Kwan - RBC Capital markets
Steven Paget - FirstEnergy Capital
Patrick Kenny - National Bank Financial
Nigel Dyer - BMO Capital Markets
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’s 2016 Second Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be question-and-answer session [Operator Instructions] Thank you.
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 and 2016 results. I’m Scott Burrows, Pembina’s Vice President, 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 Facilites and Paul Murphy, Pembina’s Senior Vice President – Pembina’s Pipeline 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 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 would like to remind you that some of the comments made today maybe 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 success Pembina had in second quarter and in the first half of that matter. We generated the second highest quarterly operating income since 2014 and nearly broke our record for quarterly revenue volumes. We closed the $566 million acquisition of the Kakwa River facility, strengthening our strategic position in one of the core areas and we believe in some of the 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 $1 billion so far this year. These projects were collectively brought into service safely and under budget, which is 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 study for an integrated polypropylene facility, which Stu will discuss later in the call. And we enhanced our footprint in the Duvernay through an additional $130 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 two years. I’m excited that we are on track to deliver significant cash flow for share growth through 2018.
With that, I’ll pass call back over to Scott to review our financial results.
Thanks, Mick. I’m 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 macroeconomic environment in the earlier part of the year, our underlying business remains resilient. Our results also benefited from revenue associated with the growth project that we recently placed into service.
Pembina’s operating margin for the second quarter of 2016 was $327 million, a 26% increase over the $259 million we earned in the second quarter of 2015. Year-to-date, operating margin was up 18% at $642 million compared to $543 million for the same period in 2015. These improved results were modestly due to increased volumes on our conventional pipelines and in our gas processing segment, RFS II coming into service and increased NGL product margin.
Higher operating margin supported adjusted EBITDA of $291 million in the second quarter, a 28% increase compared to $228 million in the second quarter of 2015. So far in 2016, Pembina generated adjusted EBITDA of $560 million, a 19% increase over the $469 million in the first half of 2015.
Higher gross profit and lower taxes were partially offset by higher net finance cost and general and administrative expenses, resulting in earnings of $113 million or $0.25 per share for the second quarter of 2016. This compares to $43 million or $0.09 per share for the same period last year.
Earnings for the first half of 2016 were $215 million compared to $163 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 $273 million in the second quarter of 2016 compared to $209 million last year. This was largely driven by an increase in operating margin and lower taxes paid, partially offset by a decrease change in non-cash working capital.
Year-to-date, cash flow from operating activities was 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 $544 million compared to $329 million in the same period of 2015.
Adjusted cash flow from operating activities increase year-over-year, as a result of increased cash flows from operating activities, net of a decrease change in non-cash working capital, reduced taxes paid and lower share base payments, partially offset by additional preferred share dividends.
In the second quarter, Pembina generated adjusted cash flow from operating activities of $235 million or $0.60 per share. This compares to $176 million or $0.51 per share last year. The same factors contributed to adjusted cash flow from operating activities of $444 million or $1.16 per share for the first half of 2016, compared to $389 million or $1.14 per share for the same period.
The second quarter of 2016 conventional pipeline saw a robust quarterly revenue volumes of 648,000 barrels per day, a 7% increase compare 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 a 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 for the first quarter of this year -- from the first quarter of this year, due to outages at a third party refinery and flooding in DC, which impacted our Western system, as did scheduled in unplanned outages at some of gas service assets.
Operating margin within conventional pipelines was $127 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 $255 million compared to $200 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 million cubic feet per day in Q2 of 2015. Revenue volumes increased as a result of the acquisition of the Kakwa River facility as well as Saturn II and SEEP coming into service in August 2015.
Operationally, there were a few 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 backup next week.
Operating margin within gas services increased by 31% to $46 million for the second quarter compared to the $35 million in the second quarter last year. On a year-to-date basis, operating margin increased 15% to $83 million compared to $72 million in the six months ended June 30, 2016. So far in 2016 the estimated impact of the Resthaven and Saturn II outages is nearly $50 million and we have insurance claims pending for the insurable portion of the lost revenue. We’ll be able to provide an update in the third quarter once we have made claims.
In our oil sands and heavy oil business we saw stable performance as expected with second quarter operating margin of $34 million compared to $35 million in the second quarter last year.
For the first half of the year operating margin dipped slightly to $67 million from $70 million in the comparable period of 2015. The modest decline is related to lower interruptible volumes. In our midstream business operating margins for the second quarter of 2016 was $118 million compared to $86 million for the second quarter of 2015. The stable to improving NGL sales environment helped to improve results within the NGL segment of our midstream business, further supported by our RFS II being placed into service.
On a quarterly basis, volumes increased by 27%. On a year-to-date basis, they were up 16% compared prior periods. These factors resulted in an operating margin of $72 million or 80% higher in the second quarter of 2016. For the first half of 2016, operating margin was $145 million compared to $109 million in the first half of 2016. Operating margins 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 margins for the second quarter of the 2016 was consistent with the second quarter of 2015 at $46 million. For the first half of 2016 operating margin decreased slightly to $87 million from $90 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 (Inaudible). We’ll 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 765 million through three offerings of preferred and common shares to finance our growth projects and the Kakwa River acquisition. As of August 4th, our $2.5 billion credit facility was approximately $345 million drawn. Pembina’s financial position remains solid supported by a strong balance sheet, ample liquidity, increasing internally generated fee for services cash flow and a high dividend reinvestment program participation rate.
With the majority of Pembina’s $5 billion plus of secured growth project coming to 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 Nick 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 kilometers twin pipeline project.
In addition to beginning construction on the Fox Creek to Namao pipeline, our construction teams have also began field work 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 $300 million, including projects that have recently been placed into service.
The Karr lateral with 30,000 barrels per day of capacity for new Alberta-Montney formation production was completed during the second quarter. The Altares Lateral in North East British Columbia 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 Colombia expansion. Initial capacity of the 147 kilometers pipeline is estimated to be 73,000 barrels per day at an expected cost of $235 million. The project remains on track for 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 receive the customary leaf to open approval from the National Energy Board. The project will add an 80 kilometer lateral one new receipt 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 underpinning. We have now secured over 775,000 barrels per day of term service contracts for the transportation of crude oil, condensate and NGL across conventional pipelines.
Construction has also begun on our crude oil businesses Canadian Diluent Hub and Fort Saskatchewan. The initial civil engineering groundwork is nearly complete and the crews will be mobilizing next week to begin interacting the 0.5 million barrels of storage tanks to be built onsite. In combination with the existing cavern storage at Pembina’s red water site CDH will have access to dealing with 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 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 close the acquisition of the Kakwa River facility during the quarter. The assets are ideally situated with one of our core areas and for me personally as a geologist I’m excited about the potential of the underlying resources. 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 an appraisal 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 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 strives to advance our strategic positioning in the Duvernay and are committing $255 million through our new 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 see significant future development opportunities for this play. Engineering is now over 80% complete for the Duvernay I facility, which is he first large scale gas processing plant designed specifically for the Duvernay production.
Construction teams are working on site grading 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 he has entered into agreement to construct instructor associated with the Duvernay I. The supporting infrastructure includes condensate, gas and water field handling, a gas gathering trunk line and a fuel line for total expected capital cost of approximately $130 million. The field hub we are calling it is committed under long-term fixed return agreement and will connect the customers’ development well pads providing separation, stabilization and other supporting services.
In additional Pembina will also construct a 35 kilometer gas gathering trunk line between 20 Creek Alberta and Fox Creek Alberta that will connect the field hub to the Duvernay plant. The field hub will also connect to 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 environment approval.
Also during the quarter one of Pembina’s customers at Resthaven filed for receivership. An investment bank is engaged into sell the assets and in the meantime we are continue 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 first quarter of 2017.
Now on to the growth process within the NGL segment for our midstream business. During the second quarter Pembina commissioned its second 73,000 barrel per day fractionator at the Redwater site, and completed an expansion on rail infrastructure at our Corunna, Ontario site, which is part of the broader expansion project including storage, truck rack and brine pond. 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 onsite piling and foundations are finished and the [indiscernible] and de-butanizer have been set in place, overall construction is now approximately 55% complete.
With regulatory approval in hand for our terminaling infrastructure associated with the plant 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 or 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 received for their propane production, as well as benefit to 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 having advanced our 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 the 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 $60 million land purchase in the Alberta industrial hard land 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 $5 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 $600 million to $950 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] And your first question comes from the line of Linda Ezergailis from TD Securities. Your line is open.
Thank you. 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 cogen at Redwater given where power prices are and appear to be for the next little while is it a reliability consideration or overall cost consideration or can you walk us through your logic?
Yeah certainly. It’s quite simple we just see the transmission cost 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 light mind and wish to capture those savings. And so 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 spread on the balance. Linda of note we already have a cogen in that area that services ROF and RFS I.
Okay, thank you. And as a follow up in terms of your NGL business, can you just give us an update on what you are seeing in terms of pricing and a supply demand looking? 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 for the year might look like?
I think I’ll answer that question into little bit more high level. We are not going to talk specifically about potentially 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 pull back in oil prices we have seen, we have seen the propane price drift back down in that kind of $0.41, $0.42 per gallon. So higher than Q1, but 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 barrel for the 2016 timeframe as we kind of move through the last year of the kind of at major build outs. 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 sort of price depreciation.
In terms of the outlook, I think as we talked about it few times there is pros and cons. The pro being Canadian inventories are very low right now and below historical levels. And so what we are seeing there is a tightening of the differential to some of the U.S. benchmarks. That being said with the inventory levels in the U.S. it’s obviously puts downward pressure on any sort of rising prices there. So while we don’t see necessarily huge upside at this stage in the U.S. pricing. We do see the differentials compressing with the Canadian inventory levels.
That’s very helpful context. And just one final follow-up question 2017 hedging propane, can you comment on where you are at this point now?
We don’t have a significant amount hedged. But we are looking at that as we kind of go through and are doing a more detailed review of our 2017 budget. So more to talk about probably on our Q3 conference call.
Great, thank you.
Your next question comes from the line of David Galison from Canaccord Genuity. Your line is open.
Good morning, everyone. So just first question on the Kakwa asset acquisition. So with the change in customer to Seven Gen, could you maybe talk a bit about any potential benefits that you might see from the acquisition outside of maybe having a bit of a stronger counter party?
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 plants a little 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 they can be accelerated.
I think you nailed it, Mick. We had a ramp up or build up of the volumes coming through the asset with Seven Gen’s level of drilling their existing path, the opportunity to ramp up sooner. We think we will give 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 have the expansion kicked off faster than we originally anticipated.
With the capital that Pembina received it also the focus we think we are going to see increased drilling behind our Resthaven asset. So with both companies now with a core areas and focusing and not competing we think we’re going to see both areas ramp up due to their access to capital and infrastructure.
Okay. And then maybe a question for Scott. With the hedging for your propane in 2016 do you have an idea 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 $0.10 per gallon being $30 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.
Your next question comes from the line of Robert Hope from Scotia Bank. Your line is open.
Yes. Thank you and good morning, everyone. Maybe looking a little bit more broadly, just wondering, how you’re approaching the M&A market right now, given that you have recently done a relatively large acquisition. And I guess also what the color that you have done a number of capital raises over the last 12 months?
Yeah, I guess, the same way we’ve always looked at it focusing on assets that we can or can integrate into the value chain. And the market still is competitive. There is 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 a $5 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 highest in the sector, which gives us the ability to acquire the assets that really make sense for us.
Alright, that’s helpful. And then one follow-up question. Just in terms 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 the second half of the year should be above where we were in the first half of the year. In the first half of the year with a 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 of this year compare to where we were in the first half of the year.
And then longer term, I think we -- it’s hard to say, you never know with these kind of free flood events that you have, but generally, we are at a peak and trending down over the next number of years. The heavy lifting for Geotechnical crack tool runs facility integrity, we have or going through peak spend, and we expect that to trend down into 2018.
Alright, that’s helpful. Thank you.
Your next question comes from the line of Robert Catellier from CIBC World Markets. Your line is open.
Hey, good morning, guys. I wonder, if you could start -- it might be little bit early for this discussion. But maybe you can provide some color on what you’ve discovered so far in those technical and market feasibility studies for the PDH. Specifically, what do you see at this point as the biggest challenge to getting top speed?
Rob, it’s Stu. So far to-date everything that in our regional thoughts our regional evaluation has been confirmed, it’s still very early day, I got to qualify with. But we’re still excited about the opportunity that appears to be from market side that there are markets and growing markets for polypropylene within North America and globally. We’re still very early days, our licensor selection process is underway. And that evaluation is ongoing, we continue to hope to see the results coming as we expect. Again, that’s where everything is kind of standing.
We’re pushing very hard, it’s very aggressive schedule with a hard push of 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 are similar type assets and future growth opportunities that we haven’t thought of yet.
Yeah, it does seem to be an awful lot of land, even for the PDH?
Yeah I’ll just take that one. That was the size of the land that was for sale. So we subsequently left off a few smaller parcels, we have that flexibility; we got a good fair price for that. We may not need it all, but they are not making any more adjacent land to Redwater. And so that’s -- I think it’s wise to hold that and really doesn’t really pose a risk. Land always has value, so it’s always an asset generally going up in Valley. So we look at the other way around, the risk was not buying that land.
Right and just back to the PDH then for a second. So what you know at this point are you still confident that the project can be done with a fee structure that’s similar to your current profile? So in other words predominantly fee for service or cost to service and manageable amount of commodity price risk?
What we can say is that we’ve gone and taken all of you folks through our guard rails and those remain our guard rails, whether this particular project is a little bit of deeper service or a lot. Generally we want to 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 guard rails.
Okay. And then just finally on the propane terminal, wasn’t really not a much color in the press release is talking multiple West Coast sites. But how close do you think you are to being close to selecting a site?
Robert it’s Stu again. We continue to do work, we continue to progress conversations. It’s difficult to say how close we are at some times. There is work and issues that’s still need to be address that 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 is an opportunity.
We believe we have a team that is looking at those opportunities, we’re 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 announce 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.
Your next question comes from the line of Andrew Kuske from Credit Suisse. Your line is open.
Thank you, good morning. I guess the question is more on M&A band. And if we just think about asset packages that have either transacted or 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 and 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 as the valuation spread between those two broad classes gotten just too wide.
That’s 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 and 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 guard rail. So each has pros and cons and we're -- we just have to assess each opportunity separately.
Okay, that’s helpful. And then maybe an extension of that question, you’ve done a great job on certain assets and not to be patronizing about it, but there is assets that you brought in the past that maybe carried a bit more risk and you derisk them fairly quickly. Do you see that playing in into some assets where you see hidden values maybe other don’t see?
Yeah again that’s part of bringing the integrated value chain and exploiting those assets. Clearly when we acquire Provident a number of years ago we were on the higher risk end of this spectrum but we saw a great opportunity to grow on a fee for service basis and recontract 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 all those assets are done normally. But we think that with producer interest some or say half of that could still be done on 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 a 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.
Your next question comes from the line of Robert Kwan from RBC Capital Markets. Your line is open.
Good morning. Maybe just kind of following on that topic here, how far outside of the guard rails would you be comfortable out of the gate on something that that has commodity exposure if you see a path to derisking and how long would you be comfortable being outside of those guard rails? I don’t know if that could be measured in years.
Yeah good question. If we were to go to the guard rails and keep in mind we’ve worked pretty hard to be in the guard rails. 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 go four or five years back we were at 100% payout ratio. And we are trying to work towards being 90% of our fee-per-service.
So that’s been a lot of heavy lifting. So if we were to get outside of the guard rails, we’re going to think long and hard about it. Where we go to do that I think we would 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 if -- if the assets itself put us outside the guard rails, we would add fee-for-service maybe through another acquisition or Greenfield to balance that out.
So there is two ways to do it. One is to modify the asset you brought and the other one is to grow your fee-for-service. So we always look at our kind of 80-20 portfolio in terms of what room we have to maintain the guard rails.
Okay. And then just on the propane outlook we’ve seen kind of a bit of a roller coaster this year with all of the exports at the beginning of the year. But now if cargos being rejected, does any of that change your thoughts on propane exposures as you go forward whether that’s how you shape any of your projects the contract structures of those projects and then just the general procurement strategy of barrels coming out of the field.
Not at this time, I mean, 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 rear view 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. Just kind of gives us a tailwind to work extra hard on the kinds of projects Stu just talked about.
Okay, that’s great. And if I can just finish on turning to Kakwa and the 6-18 expansion I know you’ve ended up with a nice counterpart and I’m just wondering though do you have a sense as to your thoughts on 6-18 given Seven G’s general bias to owning their own infrastructure?
Well, there was path [indiscernible] did. I saw an article in the Herald that he used the words that Pembina was I think strategic partner is that the right wording in yeah. So I don’t know exactly what that means because I haven’t met with him the last few weeks since he got a little busy trying to close this deal. So I think the possibilities are there. I mean we’ve toured those guys to our sites I think they’re favorably impressed and they have a lot of locations to drill. And it could be a matter of capital allocation, but I don't know the answer. But I was pleased with the way describe Pembina in that release.
That’s great. Thanks very much.
Your next question comes from the line of Steven Paget from FirstEnergy Capital. Your line is open.
Good morning. 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?
I mean, their space, 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 volume is up there for most case, we’re up in our Cutbank area. In the Musreau, we’re running at high utilization rate there. Resthaven, we’ve got our expansion complete, the Phase II expansion completed. We’ve had some issues with some of the equipment which we’ve worked through we’re back up and running as Scott already mentioned.
And there is room for growth obviously our -- the situation with the receiver ship has delayed some volumes in the 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 steels, they weren’t holding. And our current understanding and observation is that that problem is now repaired.
Excellent, thank you. Those are my questions.
Your next question comes from the line of Patrick Kenny from National Bank Financial. Your line is open.
Yes. Good morning, guys. Just wanted to go back to the 2,200 acres of land that you picked up at 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, would this land be used for Redwater IV someday, more underground storage, rail loading. Just trying to get sense for how you might best look to integrate the land with the existing Redwater site?
Yeah, the footprint we had was Redwater IV might have been -- like we could have got it done, but it would have been tight. So -- this journey started with their three quarter sections to North, that take us up to the highway and securing those for Redwater IV and V, I mean, certainly, the province has the geology to support a bunch of new fracs. And of course, rail -- additional rail expansion.
So that’s where the journey started. The land was bought from the four 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 deep 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 pricey.
And so, we’ve gone for it. And we’ve got now decade worth of growth area for that industrial complex whatever it ends up being. If some of the projects we’re working on, we’re working on different projects that could be located on that side. 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 quick update on the Northeast BC expansion, and when do you expect to see final regulatory and environmental approvals there? And when you think you might need those approvals say at that late 2017 in service date.
The stage we’re at right now with the regulatory approvals, it’s gone to the -- the process call is gone to the Minister for referral. So we really expect to hear something within about 30 to 40 days or sometime in September we expect to get the decision. Of course we are confident it’s going to be approved, as far as getting the construction going we’d like to get started in the fall before freeze up. So it’s not absolutely critical, but it’s just easier for clearing tops surround 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 startup date.
Okay, perfect. Thanks, Paul. And then maybe last question just for Scott, I believe your plan was to keep 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 mid 2017 if the PDH opportunity goes ahead or perhaps maybe look towards other financing alternatives at that point?
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 shut it off at the end of this year. We are looking at that right now since we kind of had that plan. We’ve announced the Duvernay expansion, we’ve announced Cogen, we announced kind of the going full board on CDH. So we’ve kind of had three projects since we talked about shutting the drip off at the end of the year.
So we are accessing that right now in terms of what that looks like. It maybe on for another quarter during 2017, but I’m not going to commit to that at this stage. We’re currently going through our 2017 processes as we speak. In terms of the PDH PP I think that will be a good discussion on our Q3 conference call at that point in time we’ll have a lot more certainty on the feasibility study and the go forward plan. And as part of that feasibility study we are going to have a more detailed capital plan and at that stage once we kind of know when the capital spend will be, we can have a discussion there because based on what I’ve seen to-date there won't be a heavy capital spend on PDH PP in 2017. And maybe not even in the first half of 2018.
So it would be logical to leave the drip on at that stage because the funding wouldn’t really be needed till the back half of ‘18 and really heavily into ‘19 and ‘20. So at that point in time absent further growth we feel confident that that could be funded with internally generated cash flow so the drip wouldn’t be required for that.
Okay, great. Thanks Scott, thanks guys.
Your next question comes from the line of Nigel Dyer from BMO Capital Markets. Your line is open.
Thanks. Good morning, everyone. I guess just following up on the Phase III expansion, I believe have about 700 maybe 1000 barrels per day contracted already. Just want to see what your confidence on getting additional contracts given the current environment? And then what that mean for your EBITDA guidance of the $600 million to $950 million?
Sorry. We had trouble hearing you there, was your question our confidence in getting more volumes for Phase III?
We are still receiving interest from producers on Phase III. So I mean, we have 30,000 to 40,000 barrels of capacity on Phase III and we have an easy expansion as we’ve discussed previously to put into place by adding a couple of pump stations. So I mean, we are confident that we’ll fill that pipeline.
Yes and just as it relate to our stand on EBITDA growth, we don’t need additional volumes to make that happen.
Okay. Perfect, thanks. And then maybe just quickly on the CDH storage facility. Could you clarify what the contract positions of the facility is, is it fixed per volume? And then maybe what it would take for expansions potentially later on down the road?
That is a fee-for-service asset, but it does not have long-term contracts. But the reality of the situation is 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 gives us the confidence that that facility will be well utilized. We did recently announced downstream connections to most of the major diluent take away 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 pools out and really just CRW pool.
I would also just clarify that as Mick described the contractual structure there CDH none of that is in we talked about our $600 million to $950 million none of that is in the $600 million number. So every barrel that we get above zero starts to increase that $600 million to the $950 million.
Okay, great. Thanks.
We have no further questions at this time. I’ll turn the call back over to your Mr. Dilger.
Well thanks everybody. We’re really are pleased with our progress and our first half results and 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.
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