Jess Nieukerk - Director, Investor Relations David Harris - President and Chief Executive Officer Tim Watson - Chief Financial Officer and Executive Vice President Randy Toone - Executive Vice President, Commercial and Business Development

David Noseworthy - Macquarie Capital Robert Hope - Scotiabank David Galison - Canaccord Genuity Robert Catellier - CIBC Robert Kwan - RBC Capital Markets

Thank you. Good morning, everyone.

Welcome to AltaGas' Third Quarter 2017 Conference Call. Speaking today are David Harris, President and Chief Executive Officer; and Tim Watson, Executive Vice President and Chief Financial Officer.

After some formal comments this morning, we will 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 Harris.

Thank you, Jess. Good morning, everyone.

The third quarter of 2017 was another very strong quarter for AltaGas. We achieved normalized EBITDA in the quarter of $190 million, an increase of approximately 8% over the third quarter of 2016.

Normalized funds from operations were up 4% at $143 million, compared to $137 million in the third quarter of 2016. Year-to-date normalized EBITDA was up 15% when compared to the first nine months of 2016, while funds from operations are up approximately 14%.

All three of our business segments are performing extremely well and delivering strong results. With this strong performance and our positive outlook for the remainder of 2017 and into 2018, the board decided to raise the common share dividend, 4.3%, starting with the December 2017 dividend.

On an annual basis, the dividend will now yield $2.19. Throughout the third quarter, we made significant progress on our construction projects.

On October 1, we completed and put into services Townsend 2A. The facility together with the additional field equipment was completed for approximately $125 million, $5 million below our budgeted number.

We also made very good progress on our North Pine NGL Separation Facility, which is scheduled to come online in early December. If you recall, the original scheduled for North Pine was Q2 2018.

So to advance this to early December 2017 is a significant achievement. We also expect to be under budget once the project is complete.

At RIPET, construction continues to move at a very swift pace with the fourth of eight concrete pours already underway on the propane tanks. The great progress we're making keeps us on track for Q1 2019 on-stream date.

We also continue to focus on our growth opportunities. On August 23, the Michigan Public Service Commission approved SEMCO’s application for the Marquette Connector Pipeline and we expect to move forward with the project beginning with engineering, which will start in 2018 and eventually moving to construction in early 2019.

The Marquette Connector Pipeline will be in service around mid-2020. Additionally, we continue to have very positive and active discussions with producers for additional processing and gathering capacity in various parts of both the northeast British Columbia and Alberta Montney resource plays.

In particular, AltaGas is in discussions with a number of producers in the Gordondale, Alberta area to expand the Gordondale gas gathering system to fill capacity at the Gordondale Facility and potentially expand the facility over time. Turning to the pending WGL acquisition, we continue to make progress on the regulatory side.

In Virginia, we expect the State Corporation Commission to issue a decision tomorrow. In Maryland, we just concluded hearings on October 16 and we expect a decision on or about December 5.

Finally, in DC, we will be filling our rebuttal testimony by the end of this month and expect hearings to begin in early December. We anticipated decision to follow in the first half of 2018.

We're also progressing with our asset sales plan. The process for the sale of the Blythe and Tracy facilities is off to a strong start.

We have a good participation by high quality counterparties and a very competitive process. We’re now heading into the final round with a strong group of final round bidders and we expect the overall sale process to close early in 2018.

As we start to see further progress on the regulatory front for the WGL acquisition, we will announce further phases of asset sales. As we have always stated, these need to be timed appropriately in conjunction with regulatory certainty.

We remain confident in our financing plan for WGL; including our ability achieve to the proceeds required from the asset sales and other forms of financing, which Tim will speak to more. As we've stated before, the WGL acquisition will position AltaGas with additional top quality assets and a significant footprint in all three of our business segments across both Canada and the U.S.

In addition to the size and scale comes the financial strength that we will have as a combined company. Starting in the first full year, the acquisition is expected to deliver strong accretion of about 8% to 10% on average to earnings per share between 15% and 20% on average to funds from operations per share through 2021.

The financial strength provides us with enhanced opportunities to fund the significant growth platform the combined company has and provide solid support for visible dividend growth of up to 8% to 10% starting in 2019 while maintaining a conservative payout ratio. In summary, we are very pleased with our third quarter results and the progress we are making on construction, development, and WGL acquisition fronts.

We're starting to see some of our near-term catalyst come to fruition and we expect a lot of positive momentum over the final few months of 2017. We are very excited about the opportunities that the future holds and, as always, we will continue drive sustained long-term value for our shareholders from a diversified low risk portfolio of energy infrastructure assets.

I will now pass the call over to Tim.

Thank you, David. Good morning, everyone.

I’m going to cover a few comments here, Dave, emphasize some of these numbers – going to reemphasize some. The third quarter results highlight the strength in all three diversified business segments.

In total, normalized EBITDA for the third quarter of 2017 was up 8% to $190 million, compared to $176 million in the third quarter of 2016. Our base business and new investments have performed well this year and that's evident by the strong growth in the first nine months of 2017 versus last year.

Year-to-date EBITDA is up 15%. Funds from operations are up 14%.

Normalized net income was up 34% and normalized earnings per share up 22% versus the same period in 2016. As a result of the financial strength and strong operational performance year-to-date, the board, as Dave mentioned, has approved the 4.3% increase to the common share dividend payable on December 15, 2017.

With the corresponding growth and underlying cash flow, this represents a very sustainable dividend payout ratio. Now let me quickly review the Q3 2017 performance for each of our three business segments with further detail on the MD&A as well.

Starting with gas midstream, normalized EBITDA was $51 million, up over 21% versus the third quarter of 2016. Gas midstream accounted for approximately 25% of total normalized Q3 EBITDA.

Strength in our extraction business was the key driver for gas midstream this quarter with the strong increase in realized frac spread which increased to $15 per barrel versus $6 per barrel in the third quarter last year combined with higher frac exposed volumes. This easily offset the 4% lower volumes as a result of reduced volumes at the younger plant due to third party outages upstream of the facility and slightly lower ethane margins.

On the gathering and processing side within gas, total volumes were up over 30% and this was due to a full quarter contribution from our Townsend processing facility as well as strong volumes at Gordondale displayed a planned two-week turnaround in the quarter. Note that the turnaround at Gordondale was completed in the third quarter and costs associated with this turnaround are included in the $6 million maintenance capital for the gas segment.

Volumes at our other smaller diverse gas plants were also consistent with last year and operating expenses were lower. Note that the first quarter sale of the EDS/JFP pipelines impacted the Q3 results by about $3 million versus last year.

Higher equity income was also earned from Petrogas in the quarter due to higher netbacks on export shipments from Ferndale terminal and strengthening of Petrogas’ business line supporting the upstream sector. Turning to power, normalized EBITDA was $106 million, up slightly as compared with the third quarter last year.

Contributions from the new Pomona energy storage facility and a higher dispatch at the San Joaquin Facilities and at Blythe contributed positively. This was partially offset by lower realized gains on hedges.

Finally, normalized EBITDA at our regulated gas distribution utilities increased 15% to $38 million in the third quarter of 2017. Colder weather versus last year in Michigan and Alaska contributed positively and start to experience growth including an impact from the recent September rate case decision.

Results at Heritage Gas were also up in Q3 2017 as Q3 2016 had the negative impact due to the retroactive implementation of their customer retention program. Utility results were partially offset by lower interruptible storage service revenue at the CINGSA.

A weaker U.S. dollar also had a slightly negative impact on both the power and utility segments in the quarter resulting in a decreased to normalize EBITDA of approximately $3 million.

Normalized funds from operations or FFO were $143 million in the quarter, up 4% from $137 million in Q3 2016. On a per share basis, normalized FFO was $0.83 down $0.01 from last year.

Stronger results in all business segments were partially offset by lower distributions from Petrogas, we received $4 million in common and preferred share dividends from Petrogas this quarter versus $9 million in common and preferred share dividends for the same period of 2016, which was in line with our expectations. Petrogas continued to retain cash in the third quarter to fund its growth capital program and for general corporate purposes.

Depreciation and amortization was $69 million in the third quarter, compared to $67 million in the third quarter last year. This was obviously due to new assets placed into service.

In the third quarter of 2017, income tax expense was $14 million, down from $17 million in the same quarter of 2016. This decrease is mainly due to higher taxable earnings at PNG, Pacific Northern Gas, in the third quarter of 2016 as a result of the recovery of development costs for the PNG Pipeline Looping Project partially offset by certain WGL transaction costs not being tax deductible in the current quarter.

Total normalized net income for the third quarter was $48 million or $0.28 per share compared to $38 million or $0.23 per share last year. Net income reflects the previously mentioned factors partially offset by higher depreciation and amortization expense and higher preferred share dividends in Q3 2017 versus last year.

Normalizing adjustments for the quarter can be found in the MD&A disclosure and include transaction and bridge financing costs related to the WGL acquisition of $13 million, unrealized losses on risk management contracts of $22 million and certain other items. On a U.S.

GAAP basis, net income applicable to common shares for the third quarter of this year was $18 million or $0.10 per share. This compares to $46 million or $0.28 for the third quarter of 2016.

Factors accounting for this mainly relate to the WGL deal including transaction costs and unrealized losses on risk management contracts as previously mentioned. Invested capital for third quarter was $155 million, up from $108 million in the third quarter of 2016.

Over 70% of total investment this quarter was directed into the gas midstream business segment. Third quarter maintenance capital was $6 million in the gas segment and $1 million in the power segment.

As previously mentioned, maintenance capital for the gas segment was mainly related to the costs associated with the Gordondale turnaround. AltaGas’ balance sheet is in a strong position and well funded for both the remainder of this year and into 2018.

At the end of the third quarter, debt to total capital was 44%, down from 46% at the end of 2016. And this remains well below our bank and our term loan covenants of 65% to 70%.

As a reminder, there's approximately $1.6 billion available on our existing bank credit facilities. And so far in 2017, we’ve successfully completed a $300 million preferred share offering if you recall back in Q1 of this year as well as $200 million of 10-year MTNs at 3.98% and $250 million of 30-year MTNs or medium-term notes at 4.99%, all of which were well received by the market.

So I will pause there and just turning to our 2017 outlook, based on a strong performance year-to-date and assessment of the remainder of the year, we are definitively on track to deliver low-double-digit percentage growth in our normalized EBITDA and high-single-digit percentage growth in normalized funds from operations. And this strong performance comes even with a stronger Canadian dollar in 2017 relative to last year, which will likely impact expected full year 2017 EBITDA by about $10 million to $15 million.

As compared to the fourth quarter of 2016, we expect the 2017 fourth quarter EBITDA to be positively driven by number of factors, including higher expected earnings from the Northwest Hydro Facilities resulting from higher volumes generated; materially higher frac exposed margins and frac exposed volumes; a full quarter of contribution from Townsend 2A, which entered into commercial operations earlier this month; a full quarter of contribution from the Pomona energy storage facility, higher results with fewer plant outages expected at the Craven biomass facility; higher earnings from the Bear Mountain wind facility due to stronger wind generation; colder weather based on historical norms at certain of our utilities versus the warmer weather that we saw in Q4 of last year; and finally, slightly higher Petrogas results versus fourth quarter of 2016. And these additional earnings will be offset by the sale of the EDS and JFP transmission pipelines, which closed in March of this year and will impact Q4 EBITDA by approximately $3 million relative to last year.

In addition, we expect moderately lower ethane revenue in the fourth quarter. Based on current forecast of commodity prices, the amount of gas midstream extraction volumes exposed to frac spreads is expected to increase to an average of 9,400 barrels per day for 2017, compared to 6,600 barrels per day last year.

We have hedges in place this quarter for approximately 6,500 barrels per day at a very attractive price of about $24 per barrel, excluding basis differentials. And as a reminder, every plus or minus $1 per barrel change in frac spread results in a change of about $2 million to total 2017 EBITDA.

And you can use about 20% of this as an approximation for just the Q4 2017 EBITDA sensitivity to frac spreads. Turning to 2017 capital expenditures, we expect to spend $500 million to $550 million this year, which is net of Vopak’s initial payment for cost spent to-date at Ridley Island Propane Export Terminal.

Capital expenditures in the first nine months of 2017 were $366 million. These numbers exclude the first quarter sale of the EDS/JFP pipelines for $67 million [ph].

The gas segment will account for approximately 65% to 70% of total 2017 capital, while utilities will account for approximately 25% to 30% and power about 5% to 10%. Gas and power maintenance is now expected to be approximately $20 million to $30 million for the year with $15 million spent so far in the first 9 months of this year.

The majority of 2017 capital will be allocated towards AltaGas’ growth projects related to the northeast British Columbia and energy export strategies, including Ridley, Townsend 2A, and both the first train end pipelines of North Pine. We now expect approximately $290 million for depreciation, amortization and accretion expense this year.

And again just for your models for 2017, corporate effective tax rate based on normalized earnings is expected to be about 25%. Approximately 50% of total expected 2017 EBITDA will come from the U.S.

As a quick reminder, for every plus or minus $0.05 change in the Canada-U.S. foreign exchange rate, the impact EBITDA is approximately $15 million on a full year basis or about $4 million for the last quarter of this year.

Our current 2017 outlook conservatively assumes a moderately stronger Canadian dollar in the fourth quarter closer to its strongest point of the year and frankly even if the Canadian dollar strengthened dramatically in Q4 to much stronger levels, even to levels seen earlier in this decade, our 2017 EBITDA growth would remain solidly double-digit in percentage terms year-over-year. Looking a little further out to 2018, we believe that the excellent progress made to-date with the WGL transaction will result in the closing by mid-2018 as Dave said.

We expect that the first phase of our asset monetization process will be complete early in 2018 with the sale of the Blythe and Tracy facilities and other small non-core assets. Note that the foregone 2018 EBITDA for Blythe and Tracy post disposition will approximate U.S.

$100 million. Factoring in these events, we expect strong growth in 2018 pro forma EBITDA and funds from operations at approximately 40% and 25% respectively.

WGL’s performance in both 2017 and looking at 2018 continues to meet our original expectations as WGL continues to experience attractive growth in all three of their business lines. Looking at AltaGas standalone in 2018 and I’d call this maybe on a same-stores basis and adjusting for the expected California power disposition, we expect similar growth to what we've seen in recent years.

This would be approximately mid-to-high single-digit percentage growth in EBITDA and approximately low-to-mid double-digit percentage growth in funds from operations. We expect the gas segment next year to experience solid growth driven by full year Townsend 2A and North Pine, stronger realized frac margins, higher Gordondale and Blair Creek volumes plus moderate increases in NGL marketing, the Petrogas gas contribution and our new regional LNG facility.

For the power segment in 2018, adjusted for asset sales, we expect relatively flat year-over-year results and for the utility segment next year, it’s expected to be up moderately and should benefit if weather returns to a more normalized state relative to the last two winners. So, to recap the funding for the WGL transaction, we have secured the $2.6 billion of equity subscription receipts that were raised in February of this year.

In addition, AltaGas $3 billion available under its fully committed bridge facility, which can be drawn as required at the time of closing in mid-2018. As a reminder, the bridge facility remains available for 12 months to 18 months following closing of the WGL acquisition.

I'd also point out that at current levels, the Canadian dollar is stronger than it was at the time of the WGL announcement back in January 2017 and at these current levels, the effective purchase price in Canadian dollars is notably lower. With the remaining required approvals to close WGL tracking nicely and building momentum, we are actively planning the additional long-term financing steps to reduce the remaining bridge facility.

As discussed, the first asset sales are now in the final round and are expected to be completed early next year. We are now actively planning for the next step of our asset monetization plans and constant [ph] with continued developments on the regulatory side.

We continue to expect several additional asset sales involving either majority or minority interest in select AltaGas assets. In total, asset sales are expected to result in up to approximately $2 billion of proceeds.

Additional financing steps are also expected to be undertaken in 2018, including hybrid and equity linked securities of up to approximately $800 million and U.S. dollar term-debt of at least $500 million U.S.

The WGL acquisition will provide us with greater financial flexibility and strength with a visible line of sight to grow the dividend by up to 8% to 10% annually starting in 2019. Our expectations for enhanced growth per here with attractive accretion beginning in the first full year 2019 remain fully intact.

Some of these benefits will start to appear in 2018 even though this is only a partial year with WGL. We intend to pursue value accretive growth in a balanced manner across all three of our business lines.

We believe that AltaGas shares present an attractive total return opportunity for investors while maintaining a strong investment grade balance sheet. The fourth quarter of this year starting this month holds a number of exciting catalysts for AltaGas both within our existing business as well as key milestone to be achieved with the WGL transaction.

And so with that, I will turn it back to, Jess.

Thanks, Tim. Operator, we will now open the call to the investment community for question-and-answer.

Thank you and good morning. So, maybe just to start off on the WGL, can you talk a bit about the negotiations with the PUCs, the commissions, and the submissions that you originally made to them and kind of the value of where you see those going in the negotiation process?

Hi, David, this is David Harris. I will address that.

I think you know there’s certainly always – there’s going to be opportunity for negotiations during a process like this, but we don't see anything that's not already factored into what we think was going to be required to turnaround and close the deal effectively and that's what I believe in at this point.

Okay. And there’s nothing you see in the commentary despite some of these interveners come in with perhaps negative recommendations that you can't address?

No, no, nothing at this time.

Perfect. Okay.

And then just with regards to your below on – bringing Townsend under cap budget and looking at doing the same with North Pine, who bears the capital cost risk in those projects?

It’s Randy Toone. We bear their capital risk on the Townsend facility and we do have some contractual arrangements on North Pine, we’re just – the savings go back to our customer.

Okay, perfect. And maybe just one last one then, Randy, on that.

With regards to securing third party volumes on North Pine, how does that look at this juncture, is it just Painted Pony and if it’s just Painted Pony, when do you expect that you might secure additional volumes?

Currently, it is just Painted Pony volumes that we are going to go through North Pine, but we are talking to a number of producers in the area. There’s a lot of trucked volumes that go right by our truck terminal and we're working on securing those for the new NGL year coming April 1, 2018.

And David, I would say just our expectations are, I mean, in terms of the guides for providing you for next year are very much obviously [indiscernible] Randy just articulated. So, we expect progress on that, but that's totally incorporated into our assumptions.

Thank you very much for the color and congratulations on a great quarter.

Thanks, David.

Yes, good morning, everyone. Maybe just turning up on the dividend increase, can you maybe add some color on the thinking regarding the timing as well as the magnitude just given that the magnitude would be less than what you're projecting forward as well as less than what you've done historically and then I guess is there potential that we could see a second increase after the WGL close?

Yes. So, there are a couple of things I want to just make clear Robert.

This is a 2017 dividend increase. We have consistently grown our dividend year-in, year-out for quite some time period and this year is no different.

And so, this is payable in December, December 15, I believe. This is a 2017 dividend increase.

We expect that with the strong standalone growth next year that I mentioned earlier as well as the WGL transaction that we will be considering our plans and the board – this is a board decision as you know for 2018 dividend and beyond. And that's separate from what we announced today from a dividend perspective.

Clearly, we've got significantly enhanced cash flow, EBITDA and other financial metrics next year in 2018 and we’ve always said that the dividend has to be in line with the underlying fundamentals of our financials. So, I think, you can tell directionally where we are heading here and will be a good healthy discussion next year in 2018 in terms of where we take the dividend from there.

And then as Dave said earlier, our guidance for first full year and beyond is fully intact, we remain confident in terms of our guidance.

All right, that’s helpful. And then just moving over to the asset sales, it looks like Phase 1 is well in hand, how many additional phases do you think you will be required to get to that $2 billion bogey that you mentioned as well as are you highlighting any specific assets or asset classes at this point?

Well, I think, it’s no great surprise here because we’ve said it right from the start. There is a number of different groups of assets within AltaGas that are candidates and we’ve got three business lines.

We happen to be moving on sort of the power assets with that business segment. And that's step one.

But we've got some noncore assets, more on gas side and that's active as well. We also have active consideration; other assets, minority or majority, types of opportunities, including utilities and that’s again existing, that’s – I’m referring to the existing AltaGas utilities just to be absolutely certain, this is all AltaGas, okay?

And so, that’s no different really from what we said right from day one. How many different steps?

I mean, I think, I want to just keep it simple. I mean this is the first step, gets us through the year end, and then think of it as the next step, which will be a decisive step to complete all the rest that has to be done.

So – and you should also understand that we're actively working and preparing for that as we speak. We can't comment more at this moment, but it's being worked.

All right, that's helpful. Thank you.

Good morning, everyone. So, just a quick question on the pro forma guidance for 2018.

What was the level of the Canadian dollar that you have on the assumption that you provided?

We would have – I won’t give the exact estimate. We can go offline with you and go through specific model questions, but it would be – first, let’s step back and you look at where the market thinks the Canadian dollar is going, it’s actually quite a wide range that tells me that nobody is certain where it’s going to go.

We’ve obviously taken that into consideration. I’d say our expectations on 2018 are that the Canadian dollar will remain relatively strong and in line with where we’ve seen it here in the second half of the year.

If it weakens that’s great, but I think we’re relatively prudent in terms of our underlying assumption.

Okay. That’s helpful.

And then on the asset sales that you are hoping to complete. Is there some color that you can give on – maybe what the EBITDA impact would be from that?

And just to verify that’s included in the 2018 pro forma guidance?

Yeah, everything is – everything I work on, plan doing that would happen in 2018 is in the 2018 guidance. The number I put out there, which I think is the one we can give you right now is the Blythe and Tracy EBITDA, which I mentioned earlier, that’s U.S.

$100 million, round numbers.

Okay. All right, thank you very much.

Hi, good morning. I just wanted to follow-up on the asset sales here.

The $2 billion level of potential proceeds seems high relative to your initial expectations, which I think were $1.7 billion. And as you’ve noted previously, the Canadian dollars actually strengthened and that effectively lowers the purchase price.

So, can you just walk us through the decision and realizing you haven’t realized these sales proceeds, under what circumstances and why would you go all the way up to the $2 billion in asset sales?

I think the keyword Robert is up to $2 billion. I mean I’m allowing flexibility because there are several different asset sales that where we are currently having a market and which we will be moving forward further in the second round – in the second stage.

So I can range it, but I – what I said was up to $2 billion and I'm not sure – [indiscernible] much more than that frankly.

Yeah, actually, that’s the answer, so thank you for that. And just moving onto the CapEx, so there was about $100 million reduction in 2017 CapEx, so I was wondering if you could identify the source of that, is that they are structuring it up for the Vopak contribution and timing or are there other scope items or did you drop any projects from the queue?

No. So, I mean, this is a good news story, let’s just be real clear about that.

I mean the Vopak was – Vopak came in this year, as you know, and as a full contributing partner at 30%, that's their level for the capital expenditures on RTI, which is our biggest project on the go right now. So there was some benefit from that that probably accounted for a meaningful portion of the reduced capital guidance versus Q2.

There were some timing differences, very minor, on multiyear projects. And frankly, there was some positive efficiencies achieved, as Randy referred to and Dave referred to earlier on two projects that are on-stream third quarter, Townsend 2A and North Pine.

No other changes in terms of our plans. There’s a lot of developmental work going on.

We think there will be new things to talk about, new projects and associated capital as we move into through the end of this quarter and then through early next year. So, it’s a dynamic number, but we certainly have achieved some very good efficiencies and that’s a positive.

Okay. And then finally on the dividend, pretty clear growth for 2019.

You are silent effectively on 2018 other than comments you made on the call. But there's significant things happening, the financing and closing the acquisition, so in the circumstance that you close WGL as envisioned, would you still need clarity and effective way that have the bridge loan repaid before you consider the 8% to 10% range or would you be able to considered it or would you remain prudent until that’s close or would you be able to consider 8% to 10% range if WGL is closed and bridge is still outstanding?

Well, I think, the timing is setting out quite nicely for us. I mean as you’ve heard again from, Dave, I mean, we've made excellent progress, we’re tracking at or faster than what we would have thought from a WGL perspective up to first half of next year is our conservative view on closing that.

We typically will – this is a board decision. We will evaluate a dividend decision.

It could be in the Q2 or Q3 timeframe. This year it was Q3, but historically it’s been Q2 or Q3.

So, our Q2 next year is late July undertaking or Q3 next year is a mid October timeframe, right. So there's going to be a lot that's actually happened and been accomplished by the time we get into that typical timeframe for dividend.

But that's normal cyclical rhythm in terms of dividends for us. And so, again, I just want to emphasize what we announced today is the 2017 dividend and we think that there's a lot of things setting up fundamentally for us to support some progress on dividend next year as well.

So that’s the high level comment.

Okay. Thanks for your answers.

Good morning. I guess since you were just talking about the dividend I will continue there.

Can you just talk about the post-WGL dividend growth, [indiscernible] there was the comment of up to 8% to 10% and I don't believe the up to is there previously, is there something being considered in terms of the underlying growth? Certainly, that message is very clear and the accretion and the economics all sounds intact, I’m just wondering are you reconsidering the growth target?

No, the answer is no. So, first of all, very good listening, Robert.

But I think Dave’s comment maybe was more clear than mine. 8% to 10% was the guidance and is the guidance.

And the numbers, the WGL performance and our performance fully support it and so that's the answer, right.

Okay. I guess moving to the business here.

You've got the Montney infrastructure [indiscernible] been where a lot of the growth has been, you are continuing to track a bunch of things, but you also have via Petrogas especially assets in the Fort Saskatchewan area, you’ve got your Empress position as well. I'm just wondering when you look at those assets and those areas, are those areas that you want to be bigger, is there strategic case to be made essentially to be bulking up the assets in and around the Fort and at Empress?

Robert, this is Dave Harris. Those are certainly strategic areas for us and we'll continue to look at adding robustness in those years especially as it supports our build out with respect to our northeast BC strategy and then particularly as that links to RTI, which will be a significant game changer, not only for the sector, but for the producers in western Canada.

So, we will certainly continue down that path with vigor.

Okay. And I guess with that though, a lot about what your Montney has been to try to cut the liquids and support RTI, so is your thought of wanting to potentially be bigger in the Fort and at Empress, just a situation where you see a lot more growth in the Montney that will outstrip even with RTI there is an expansion or are you hearing from customers that they would prefer to also get some optionality to put the liquids to east?

I’m not sure I completely followed the question Robert. So, I will try to answer it this way.

I think at this stage of the game what we are seeing from – first, I’ll answer it starting at the end and work on myself back to the beginning part of the question is that we're certainly seeing producers thirsting for optionality, right, and – but at the same token that optionality still comes with nimbleness, right. So having the opportunity to turn around and push product off the West Coast to Canada and take it into Asia and Asia is one word, but with multiple markets within Asia and then also been able to provide that flexibility to turn around and still push product within North America as well is something that they're thirsting for and we’re able to deliver on.

Though I think that's the general tone right now within the producer community. And then in addition to that as it relates to earmarking any particular area of what we would go after was certainly in tune to where the markets may migrate to and depending on how they migrate, they will certainly look to take up the appropriate positions as we see fit.

But again right now I think what we're seeing more the focus is, is, really how do you turn around and get – take product from the Fort West quite frankly and also in northeast BC as northeast BC continues to grow out. So that’s – I would say that's where the focus is right now.

Understood. And then just to finish, previously you’ve been talking about a potential NGL driven infrastructure in the Deep Basin, that's been, I think, dropped from this quarter's commentary.

I’m just wondering if there's an update on that.

Sure. I will let Randy talk to that.

Yeah, the level of interest for a liquid facility in the Deep Basin has tapered off. We're still are looking in that area for another liquid facility, but we – just the level of interest has dropped off, so we removed it from our disclosure.

Understood. And is the level of interest, has that drop off been just the customers you're talking to adjusting their drilling plan or that they want to take the liquid somewhere differently?

It was around drilling plans.

Okay. That’s great.

Thank you.

Thank you, Karen. That concludes AltaGas’ third quarter 2017 conference call.

We are available for any follow up questions after this. I'd like to thank everyone for joining us today.