Jess Nieukerk - Director of Finance and Communications David Cornhill - CEO David Harris - COO Debbie Stein - CFO

Linda Ezergailis - TD Securities Rob Hope - Macquarie David Noseworthy - CIBC World Markets Matthew Akman - Scotiabank Robert Catellier - GMP Securities David Galison - Canaccord Genuity Steven Paget - FirstEnergy Capital Robert Kwan - RBC Capital Markets Dirk Lever - AltaCorp Capital

Thank you, operator. Good morning, everyone.

Welcome to AltaGas' second quarter 2015 conference call. Speaking today are David Cornhill, Chairman and Chief Executive Officer; David Harris, President and Chief Operating Officer; and Debbie Stein, Senior Vice President, Finance and Chief Financial Officer.

After some formal comments this morning, we'll have a question-and-answer session. Before we begin, I'd like to remind you that certain information presented today may include forward-looking statements.

Such statements reflect the Corporation's current expectations, estimates, projections and assumptions. These forward-looking statements are not guarantees of future performance and they are subject to certain risks, which could cause actual performance and financial results to vary materially from those contemplated in the forward-looking statements.

For additional information on these risks, please take a look at our annual information form under the heading Risk Factors. I'll now turn the call over to David Cornhill.

Thank you, Jess. Good morning, everyone.

Before I get to my second quarter remarks, I'd like to acknowledge Debbie's planned retirement. Debbie has been with us for almost 11 years and has made a significant contribution to the company.

AltaGas has grown tremendously over the period and Debbie has played an important role. Well, she will be with us until the end of March next year, she'll be transitioning the CFO role over to Tim Watson in the end of October.

I'd like to thank Debbie for all her contributions and dedication. The Board of Directors has actively engaged in succession planning for the company.

As you can see in the announcement of Debbie's retirement, we have a strong management team in place. The first half of this year was very challenging, but we still delivered EBITDA in line with the first six months of 2014.

As we look to the rest of 2015, we expect a stronger second half of the year. Overall, we expect EBITDA to be 10% to 15% higher than 2014.

As I said in the Q1 call, Q2 would be the weakest quarter of the year and we expect that the power and utility businesses to deliver growth year-over-year. We still expect power and utility businesses to deliver higher earnings in 2015.

We have not seen and don't expect to see strengthening in liquids prices in the second half of 2015. As a result, we're now expecting the gas business to deliver lower earnings in 2015 and 2014 [ph].

Again, on a consolidated basis, we're expecting 10% to 15% growth in EBITDA. We are executing our strategy to add cash flow underpinned by low risk, long-life assets.

The strength of cash flow will provide us the ability to continue to grow our dividend. We did not declare a dividend from Petrogas in this quarter.

Petrogas is making significant investments in projects to enhance its liquid storage and liquids logistics capability across North America. This will support Petrogas' future growth and export capability.

While this resulted in lower reported funds from operations for AltaGas in Q2, we expect Petrogas to grow earnings and cash flow in the second half of the year. On the growth front, we’re well on our way to provide producers with the solution to reap liquids prices.

We are making significant progress on LPG export and our overall Northeast strategy. Our integrated solution is expected to drive over a billion dollars in energy infrastructure investment over the next two years.

This includes a site for export of Canada's west coast, a liquid fractionation facility at Fort St. John, gathering pipelines and sales volumes in our Townsend facilities.

We are in negotiations under exclusivity agreement for LPG export site of Canada's west coast. The site will initially be able to handle 25,000 barrels a day with significant expansion opportunities.

We expect to finalize agreements by the end of the year and we expect to be the first to export LPG of Canada's west coast. We are also proceeding liquid fractionation facility at Port St.

John. We have started consultation and we'll shortly be in the regulatory process.

By eliminating unnecessary transportation cost to Fort Saskatchewan, this facility will provide significant cost savings opportunities for producers looking to send liquids to the coast. We expect to reach FID on the Fort St.

John’s facility in 2016. We continue to work with our partners on Douglas Channel to progress the LNG export plans.

We are in discussion with producers and the technical and commercial plans are underway to support our FID decision in the fourth quarter, but there is still a lot of work to do. We’re excited about the second half of 2015.

I will now pass the call over to David Harris.

Thank you, David, and good morning everyone. Our business operating income in the second quarter 2015 was $61.2 million compared to $73.1 million in the same quarter of 2014.

Lower results in gas from the impact of turnarounds, weak commodity prices and downstream contaminants were partially offset by stronger results from power and the utilities. Our operations continue to perform well throughout the second quarter.

Generation of Forrest Kerr and Volcano was better than expected. Gordondale volumes were up 7%.

The major planned turnarounds at Younger and Harmattan were completed on schedule. Utilities reported normalized operating income of $22 million in the second quarter of 2015 compared to $20 million in second quarter of 2014.

This was driven primarily by favorable foreign exchange, but slightly offset by warmer weather. We received approval of the main replacement program at SEMCO, which allows us to continue our capital program and include the recovery program cost and rates over the next five years.

In Power, normalized operating income from second quarter 2015 was $18 million, up $5 million despite lower realized Alberta power prices. This is a result of strong performance from Forrest Kerr and Volcano Creek.

The capacity factors at Forrest Kerr and Volcano Creek were 52% and 61% respectively. We continue to see a challenging Alberta power market.

The average realized power price in Alberta for the quarter was approximately $48 per megawatt hour, which compared to $57 per megawatt hour for the same period last year. We hedged 47% of Alberta generation in the quarter at an average price of $43 per megawatt hour.

This compares to approximately 50% hedged at $60 per megawatt hour in the same quarter last year. We expect Alberta power price to remain soft at 2015 with the additional 800 megawatt supply from the Shepard power plant.

For the remainder of 2015, Alberta power is 30% hedged at approximately $54. For 2016, we are 23% hedged at approximately $49 per megawatt hour.

Just to touch briefly on the new Specified Gas Emitters Regulations, we don't see this as a material issue for AltaGas. Normalized operating income from our gas business was $21 million in the second quarter 2015 compared to $40 million in the same quarter last year.

While lower frac spreads and lower frac exposed volumes were a headwind in the quarter, we saw strong performance at several of our facilities. Gordondale and Blair Creek are operating at close to full capacity and we're seeing opportunities to increase throughput at those facilities.

We recently completed a gathering line which extends to catchment area for Gordondale. Production of frac exposed volume was slightly lower in the second quarter 2015 compared to same quarter last year as a result of the turnarounds at Harmattan and Younger as well as reinjection of propane as a result of weak prices.

For the second quarter of 2015, AltaGas hedged approximately 3,300 barrels per day at an average price of $26 per barrel. This compares to approximately 5,000 barrels per day hedged at $25 per barrel in the same quarter last year.

The spot NGL frac spread for Q2, 2015 was $2.51 per barrel compared to approximately $18 per barrel a year ago. For the balance of 2015, we now expect to produce approximately 3,100 barrels per day of C3 plus that is directly exposed to frac spread, of which 3,000 barrels per day are hedged at an average price of $27 per barrel.

Let me now turn to give an update on some of our projects. At Townsend, we moved into the construction phase and to-date, we have committed over $100 million on long lead equipment including compressors, generation equipment, LPG boards and waste heat recovery unit.

Site earthworks are nearing completion with pilings going in, in early August. Townsend is firmly on track to be online in mid-2016.

Moving onto our to Blythe II expansion, on July 15, AltaGas submitted a petition to the California Energy Commission to amend its current permit to allow an upgrade of the proposed plant's permitted technology to a cleaner, more flexible and efficient technology. This facility when placed into operation will be one of the cleanest, most efficient and flexible plants in North America.

This gives the Blythe II facility a significant competitive advantage in future RFP processes. We are in discussions with off-takers for the expansion and also weighed our fees from the larger utilities.

Finally, at McLymont, backfeed was achieved on June 30 and commissioning has commenced. We expect to start generating power in August at which point we will see cash flow generated from this asset under the terms of the EPA with BC Hydro.

That concludes my prepared remarks. I'll now pass the call over to Debbie.

Thank you, David, and good morning, everyone. Starting with the EBITDA, normalized EBITDA for the second quarter 2015 was $107 million, which was flat to the same quarter last year.

The contribution from our new assets and utilities offset the impact of the continued weak commodity price environment and the turnarounds in the quarter. Excluding the impact of the commodity-driven EBITDA in both quarters, AltaGas reported a 23% increase in EBITDA from its strong portfolio of energy infrastructure assets.

Normalized funds from operations was $68 million or $0.50 per share compared to $106 million or $0.86 per share. Normalized funds from operations were lower, primarily as a result of the Petrogas not declaring a dividend in the second quarter versus the dividend payment of $28 million in second quarter 2014.

As David mentioned, the cash was retained at Petrogas to fund its capital programs. On an annualized basis, we expect to receive dividends of $30 million to $40 million from our investment in Petrogas.

In the second quarter 2015, AltaGas reported normalized earnings of $9 million or $0.07 per share compared to $27 million or $0.22 per share in second quarter 2014. While we had a stronger quarter in power and utilities, the gas results included the impact of the turnarounds at Younger and Harmattan and lower earnings from the sale of NGLs.

The ramp up of generation at Forrest Kerr and Volcano more than offset the impact of weaker power prices in Alberta. Lower income taxes, higher interest expense and preferred share dividend also impacted the overall financial results in the quarter.

On a GAAP basis, we had a net loss applicable to common shares for second quarter 2014 of $22 million or $0.16 per share compared to a net income of $29 million or $0.23 per share for the second quarter of 2014. The two main drivers of the GAAP loss was the increase in income tax expense of $14 million resulting from the adjustment in our deferred tax liability due to the increase in corporate tax rates in Alberta, as well as the $17 million after-tax unrealized loss, which was primarily due to our power hedges as a result of the spike in the Alberta power forward curve late in the quarter.

The forward curve has since come down, thereby reducing that mark-to-market loss that we booked at the end of Q2. Interest expense for second quarter 2015 was $30 million compared to $23 million in the same quarter last year.

Interest expense was higher primarily as a result of lower capitalized interest. Depreciation in the second quarter was $50 million compared to $42 million in the same quarter last year as a result of increased assets in operations.

For the quarter ended June 30, 2015, net invested capital was $149 million. In the quarter, maintenance CapEx was approximately $11 million, including $7 million related to the turnarounds, which is amortized over three years until the next planned turnaround.

For the full year 2015, we expect our capital expenditure to be in the range of $600 million to $700 million. Our capital program this year is well funded with $290 million in cash on hand and $1.8 billion in availability on our credit facility and a debt to total capitalization of 45%.

And with that, I will turn the call over back to Jess.

Thank you, Debbie. Operator, we'll now take questions please.

Thank you. If I could just get some clarification on the Petrogas front.

When would you expect Petrogas to resume paying a dividend? What would the dividends have been this quarter if it was retained for growth?

And will there be some sort of a make-up payment?

Sorry, Linda. Can you --

So, on the Petrogas front, it's just not clear to me when your dividends from them will be resume? What it would have been in Q2, if it wouldn't have been retained at the Petrogas level for growth?

And, I guess the third prong to that question would be, will there be a make-up payment for no dividend?

I'll answer and then Debbie will correct me. I only have a few more months for her to do that for me.

Well, we're working with Petrogas, historically it's been in June and in December, we're looking to do more quarterly dividends on a more planned basis. I think Debbie's view is that between $30 million and $40 million is probably a good planning and we're just working with our partners at this point to put a little more orderly dividend process in place.

And so, I guess our guidance as we think we should be looking at quarterly as we move forward and that it should be in the $30 million to $40 million range on an annual basis.

Okay, that's helpful. And maybe David, if you could just explain a little bit more about the exclusive agreement that you have on the LPG front in BC?

Is it related to site negotiation or is there some other element of talking to customers or suppliers? And I guess the second prong to that whole LPG question is, there is a mention about the potential to expand and can you talk about what sort of size expansion that would be on the LPG front and if that might include other products?

I will pass that over to the other David.

The exclusivity is a site-specific location that we've entered into. That's about, I think all we’re comfortable with talking at this point.

And as far as expansion capability, starting out with 25,000 has certainly has -- let's just say, significant expansion capability and be a little premature to talk about exactly how much, but it is significant. And as we get few quarters down, we will be able to probably provide greater clarity on that.

Great, thank you, and congratulations, Debbie on your retirement announcement.

Thank you, Linda.

Good morning, everyone, and congratulations, Debbie.

Thanks, Rob.

If we can move over to the BC Hydro projects, good to see that they are operating above your expectations. However, when we look to the back half of the year, and I guess may be even into 2016, how confident are you with the hydrology there given some of the drought conditions we are seeing on the west coast?

Very confident, if I could draw your attention to some of our best days, you may recall that hydraulic curve slide that we provided that has been averaged over 40 watt, which I guess now would be a 43-year, 44-year period. There were flows during the peak of when we make 97%, 98% of our earnings from mid-May to mid-October, has a flow rate above 780 Qmax and that’s [ph] drop because of environmental reasons, at least 250.

So we've got more than quarter in river, so the confidence factor as far as megawatt generation and earnings delivery is extremely high.

Good. And then just switching over to LPG, could you give an estimated CapEx and timing when your fractionator in NGL hub could enter service in Northeast BC?

Well, they started when we turned around and filed the applications and that might be noticed next year, we think that is somewhere in the 2017 time frame. And CapEx range on just the fractionator is probably somewhere in the order of $100 million.

All right, wonderful. And would that be contingent on your west coast BC project or are they separate?

No, it would be independent. We would still go forward with that project, but they certainly link very nicely.

Exactly, thank you.

Good morning. Let me add my congratulations to you Debbie.

Thanks, David.

Me just following from that fractionation question, what sort of storage would you need to complement that and is there anything -- is there any underground storage up in the Fort St. John area that would allow for cost effective storage?

There isn't and I can't give you that. What we are looking at is doing storage there as well as with respect to export at Ferndale is storage of 500,000 barrels for propane there.

So we're looking at moving it out of the fractionators on a regular basis and maybe David can add what the story -- I have not seen the design storage, but it's basically about a week production would be -- be the storage level that we'd hold there.

Yes. It's out of actual export facilities where you'd have the larger storage.

Yeah.

Okay, that's helpful, thank you. And then when we look at the year-over-year decrease in gas segment result, can you help us kind of quantify or any kind of color of the impact of lower commodity price environment from the pipeline curtailments versus the Petrogas specific results?

Give me a minute. So, I would say, on the curtailments, for the quarter it was about $2 million, on Petrogas, it was about $5 million and the rest would be commodities.

Got it. Perfect, thank you for that.

And then just on -- when you just working out or looking at Petrogas a little bit more, we saw how at least from the equity investment, and the gas segment is down about $3.8 [ph] million year-over-year. Now, presuming that's mainly Petrogas, I guess my question is, is this decrease in earnings also reflective of decrease in cash flow generated by Petrogas or are there meaningful non-cash items in here such that the cash flow actually wasn't nearly as impacted?

Year-over-year, I would say no material difference for the second quarter or the first half of the year. As we look at the second half of the year, there might be a little bit of a disconnect, but for the first half of the year, no, I would say it was pretty much cash and earnings.

Cash and earnings are -- what we see in earnings movement, we saw in cash movement?

Yes, year-over-year.

Year-over-year, okay. And then just on your CapEx, 2015 CapEx guidance, I noticed that you've bumped up both the lower and higher end range, $50 million.

Can you give us any color on what that entails?

That's really related to, I would say, the initiatives that we've been working on for a few quarters making some more headway in this quarter and committing some incremental capital to moving those projects along.

Okay. And then in terms of -- does your updated guidance include any anticipated cost savings, really to just kind of the slowing energy business environment at West?

Well, I think we're always looking to tighten things up a bit and our availability is up. We're spending less on general expense, so it does.

Okay, I'll leave it at that and get back in the queue. Thank you very much.

Good morning. On the frac spread and the NGL exposed to frac spread in the commodity swap contracts, there is a comment that the amount of barrels exposed is, I guess about 3,100 for the remainder of the year.

And normally, I mean, that number is double or more, like if you look back at other years, is that because you guys have put in more long-term hedges or is that because you expect production of NGL to be down, not much due to, I guess just re-injection and other factors?

It's all re-injection. We are actually seeing the streams get richer.

But at this point, we're re-injecting because of better value in the gas price and propane price.

Okay, thank you. On the power business, I'm wondering if you could comment on the Alberta business.

It feels from the result like you might not have made money or much money and yet $48 price was realized. So maybe you could just comment on the discrepancy.

This was a soft quarter with pricing, but it also ties into dispatch. So dispatch was -- we were at this high availability for the asset, but lower dispatch because of pricing.

So that erodes away on the earnings equally as well as on spot market pricing.

Would you say or would you be able to comment on whether the Alberta power business contributed any operating income in the quarter?

It did.

Okay.

It did, but certainly not as much as it did Q2 of 2014.

Okay, thank you very much. Those are my questions.

Good morning. Rob Catellier here.

Just follow up on the power business here. Given the state of the current market, what's your strategy with respect to the PPAs given market conditions?

And then, wondering if you could address both the dispatch strategy and ultimately ownership.

When it comes to Sundance in the Alberta market, we certainly will take a look at what's the appropriate thing to do from both the hedging perspective when the market opportunities present itself. This hasn't exactly been robust periods of time where you got high Alberta power pricing which potentially can give you some opportunities to hedge out a little bit as buyers get a little uncertain on pricing.

So, I haven't seen as much of that as we have in the past. And then as it relates to dispatch, we're constantly looking at the dispatch strategy to turnaround and then improve that as opportunities present themselves up.

So without a change in the short-term power price environment, we should expect the margins might be compressed because the dispatch might be lower than the availability?

That would be a fair assessment.

Okay. And just moving to -- back to Petrogas, again, you know the retention of the cash flow for reinvestment makes sense, but can you address what they're doing to enhance serve capability, especially at Ferndale and maybe you can address both capital enhancements and operations.

I'll talk first -- with respect to their -- enhancing their storage capability in Canada and US, so both underground and tank storage to give more flexibility, which is significant. On Ferndale, they have enhanced the robustness of that facility to operate under different weather conditions, modernized a number of the equipment to make it more reliable and add capacity.

So those are the things that they do in storage across North America enhancing their logistics capability, both at the Fort and other places in mid-west and across North America.

Okay. And then, when you look at the model you are developing for LPG export in the liquids hub, you realize obviously it's early days, but how do you envision that cash flow and income stream being split between fee-based exposure and marginal frac spread?

It'll be substantially significant fee-based and then there will be some back-to-back -- it won't be a frac spread, but back-to-back sales arrangements would be in place or a cost plus arrangement. So those are what we're talking at this point in getting lots of traction with producers.

Okay. And how do you see Younger fitting into the strategy here?

Was there anything going to be built on the Younger side or are these assets going to be independent of Younger?

Independent of Younger.

Okay. Those are my questions.

Thank you.

Good morning, everyone and congratulations Debbie as well. Just wanted to touch on the LPG, so just wondering what for the FID in 2016, what are you going to need to have in place in order to make that and maybe trying to understand what some of the risk could be for that?

And also just touch on whether you are expecting it in the second half or maybe in the first half.

I'll let David speak when he is expecting it. Well, we clearly have committed volumes already to the project.

We are in discussion with producers to get additional committed volumes. We've got the regulatory process to go through.

So those are the major hurdles that we see that we want to finish over the next few months. So that's that answer and then David for FID.

FID hinges on a couple of things. So, obviously getting the permit which we expect in the first half of 2016, making sure we have our consultations and we are collaborating with the First Nations which we always do.

We've got pretty good handle on pricing now, but we'll look to refine that. But those are probably the three major things that we would need to push us into the FID environment and expectations at this point would be so long as permitting in First Nations go reasonably well would be in the first half of 2016.

Okay. And then just on the EBITDA guidance for 10% to 15% growth over 2014, just kind of wondering if you could give some color on what you would need to sort of get to that 15% level?

I guess, we have to have a little better commodity tailwind, but we're not expecting any recovery in frac spread or change in Alberta power prices and we feel that has covered a little higher. It depends on when the claim on exactly comes on will make a little bit of difference as well.

So those are the ones and then I think just in terms of Petrogas performance.

Right. Those are all my questions.

Thank you.

Thank you, and good morning. Congratulations to you Debbie.

My first question is on the LPG export terminal. What might the ownership structure look like?

In other words, could Petrogas be a part owner and could First Nations have an equity interest?

We're still working through the process on all of those. The addition at this point is a joint venture with Idemitsu would be the owner of the facility and Petrogas would clearly have a significant role with their logistics capability.

So that's where we are at. We're in dialogs with First Nations now and working with them, so started to work with them on the site.

So, it's premature to say what the structure would be.

Thank you, David. You've noted that we are less than six months from FID on Douglas Channel, how much of its capacity is committed?

How much more commitments do you need from producers? And what are the key permits left to obtain?

I think it's premature from a market perspective, we're negotiating with customers to talk about that. We do are in active discussions on off-take and structure and with a number of producers that would more than fill the capacity.

So that's where we there, as everyone knows, it's a tough LNG market in pricing. Lots of interest from producers in diversifying their markets and so forth, but they are looking -- we are asking for long-term commitment.

So it does take time to make sure they're comfortable. So, with respect to permit, David?

So, on the permit side, we've actually filed the application and preliminary indication was received well, was very tight package and our anticipation is to be on the track with permitting by the end of the year.

Well, thank you gentlemen. Those are my questions and I'll get back in the queue.

Good morning. Just on the guidance for relatively flat FFO compared to 2014 for this year, is that the total FFO or is that on a per share basis?

It's on a per share basis, Rob.

Okay, great. I guess turning to Petrogas, it was my understanding that the idea was you're going to get a distribution based on operations and then you would kick capital back in for CapEx.

Was that the case or has that changed, and then I guess more importantly, how do you think about that dynamic going forward?

That was the case. We had some logistic issues with one of our partners to make that happen for the quarter to be totally blunt.

Okay. So is it fair to say to some degree then that not or I don't know if you can talk about what Petrogas' cash generation during the quarter was, like I know it's retained for growth, but did you also make a payment into Petrogas to fund growth as well?

No. It was all -- they funded everything internally.

That's why we're moving -- looking to move to a more predictable quarterly dividend process and my goal is to have effectively proportional accounting which is no longer allowed, but to more reflect the business for the external market to see what's going on.

Okay, perfect. Maybe just the last question to make sure it's clear to me.

That $30 million to $40 million annual run rate, that is what you would expect on a proportionate operational type basis and then you would kick capital in as needed for growth?

Correct.

Okay, perfect. And just last question on, you talked about for Sundance B on the dispatch strategy, just to be clear, are you controlling dispatch now or is this still something what TransCanada is controlling dispatch and you are kind of the [indiscernible]?

TransCanada is controlling dispatch at this point and we're moving towards a mechanism that we would take control of dispatch for our properties.

And David, I guess that's been something that's been talked about for a while here. So what steps are left or what's been hold out and not being able to implement that?

Well, the market itself is relatively low. So it's not that this is an official amount of impact from Sundance at this point anymore, especially now that the Northwest project is around swinging a pretty big back in the lineup for us.

So there are some things that you have to work on with them and I would say we're probably 80% of the way there. And my expectations will be before we get to the end of the year in the next six months, we have that cleaned up and worked out as far as what we're dispatching or what they’re dispatching.

Okay, that's great. Thanks very much Debbie.

Best of luck in retirement.

Thanks Rob.

Thank you. Just some clean-up questions.

I'm looking at page 31 on your balance sheet, and I'm just wondering if you can comment on the nature of the $50 million [ph] short-term investment that you sold.

So, Linda that was really some -- because we were sitting with cash on hand at the end of the year, we had that in short-term market money and we took it out of there and put it into our bank, I believe in the second quarter.

Okay. Thank you.

And can you comment on the degree to which you are hedged beyond just your U.S. denominated debt to U.S.

dollar exposure and give us an updated sensitivity to that?

So, I'll give you the sensitivity. For every $0.05 in FX, it's about $0.01 in EPS and about $0.02 to $0.03 on FFO.

Okay, that's helpful. And just final clean-up question, extraction premiums, have they been stable recently or are you seeing any trending on that?

They are pretty stable Linda, no trending one way or the other.

Okay, great thank you.

Thank you very much. Congratulations Debbie, and I guess congratulations over to Tim, I am sure he is listening in.

If we could focus on Ferndale, give us an indication of what the current export levels are out and how we're going to get to the 30,000 a day, where we are at on that. Thanks.

That's an important information that we don't want the market to know at this point of buying and selling of commodity. We're well on our way to meeting the target of 25,000 barrels by the end of the year.

So all we are saying at this point.

Thanks. That will be good enough for me for the moment.

Thank you very much, David.

I am just trying to understand some little better here, on your realized NGL price of $2.51 per barrel, how come that’s so much lower than what wholesale pricing would suggest? What's going on there?

Sorry, David. The $2.51 is spot.

It's what we sell at plant's gate.

I guess what I'm trying to figure out is that, and I am not sure if I am using the exact same barrel assumptions as you are, but if I look at kind of our wholesale posted price and make that up, I am looking at something closer to $19. So there is a $17 difference here and I'm trying to figure out what is causing that?

David, if you're buying at $19, I will be selling all day to you.

We’ll look into that one, David, and get back to you, but off the top, we don't have an answer.

I think maybe it depends on the mix in terms of what's condensate butanes propanes, and then from that, it probably make sense to walk through it with you.

The spot that we provide is a spot that we get at our plant's gate.

Right, right, that I got it. And maybe just one last question.

In the past you've talked about Townsend and Townsend II and that there's been a lot of interest up there. I just wondered if you can just kind of give us an update on what you're seeing in terms of producer interest for another project there and how half commodity prices impacted those conversations?

We're still seeing good interest. We expect to have people signed up this year.

As everyone knows it, the commodity price has caused more uncertainty for producers and what their capital budgets are. So that has impacted somewhat their timelines in terms of when they would want to commit, but we have producers that we expect to be committed by the end of the year.

Perfect. Thank you very much.

Thank you. First question on the potential LPG export facility, is the facility served by multiple railways]?

The answer is yes, depending on how far back you go.

Second question. Could you please update us on the progress at Dawson LNG?

Sure. We're well into the construction.

We will be finishing up towards the -- till end of this year as expected. So no bumps in the road there.

So it's going well, Steven.

And for final cost, is it $40 million?

No. It's well below that, not well below that, it's probably in the mid $30 million range -- is the target they are going to use.

Thank you, David.

Thank you, operator. Thanks everybody for joining us for our Q2 2015 conference call.

Both Debbie and I will be available for any follow-up questions you may have. So, good day.

Thank you.