David W. Cornhill - Chairman and CEO David Harris - President and COO Deborah S.

Stein - SVP Finance and CFO John Lowe - EVP John O'Brien - President Jess Nieukerk - Director, Finance and Communications

David Noseworthy - CIBC World Markets Linda Ezergailis - TD Newscrest Robert Hope - Macquarie Capital Markets David Galison - Canaccord Genuity Matthew Akman - Scotiabank Robert Catellier - GMP Securities Steven Paget - First Energy Ben Pham - BMO Capital Markets Dirk Lever - AltaCorp Capital Robert Kwan - RBC Capital Markets Patrick Kenny - National Bank Financial

Thank you, Wayne. Good morning, everyone.

Welcome to AltaGas' third 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 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 Cornhill.

Thank you, Jess. Good morning, everyone.

As you saw from the announcement yesterday, I’ll be transitioning to a new role of Chairman and Founder of AltaGas and stepping down as Chief Executive Officer in April of next year. In my role I’ll continue to be actively involved in the development of AltaGas’ strategy, capital allocation and stakeholder relations.

David Harris will succeed me as CEO and will continue to drive AltaGas’ growth and creation of long-term shareholder value. The Board and I have been working very carefully over the last three years to ensure a strong succession plan was in place.

David Harris brings with him over 25 years of experience in energy infrastructure and over five years with AltaGas. He played a critical role in the successful completion of our Northwest hydro projects, the growth of our U.S.

power business and he is now leading the charge on our northeast BC strategy. David has also led the creation of an outstanding operational and construction capability, which will support our energy infrastructure growth plan.

We have also added significant expertise to our executive teams with Tim Watson, John O'Brien and Brad Grant, all of whom were brought on over the last year. Our success has been driven by a business model of low risk, long life in energy infrastructure assets.

My priority will be ensuring we maintain the business model, our financial discipline and our entrepreneurial culture as we move forward. Now turning to some changes at the Board level.

First, Myron Kanik will not be standing as a board member next year as he will be 76 years old. Myron has provided leadership, counsel and advice to the Board over the last decade or more.

Neil McCrank will become lead director upon Myron leaving the Board. Neil has incredible experience in government, energy and regulatory fields and I am sure that Neil will be a great lead director.

He does have big shoes to fill though. We have added two new directors, Phil Knoll and Victoria Calvert.

Phil has extensive industry expertise in pipelines, utilities, midstream and upstream businesses. Phil is based in Halifax.

Victoria is a professor at the Bissett School of Business in Calgary and has done extensive work in writings on entrepreneurship and community outreach. We believe the additions of these two new directors will strengthen our already strong AltaGas Board.

Finally, we have made significant strides in delivering on our strategic plan with the completion of the Northwest hydro facilities, progress in gas infrastructure to support energy exports, growing our gas-fired powered generation in the U.S. and continuing steady growth in our utilities businesses.

These steps will create growth and long-term shareholder value in years to come. The AltaGas team has the skills to deliver on AltaGas’ growth strategy.

I look forward to be actively working with them in our future role. I’ll now pass the call over to David Harris.

Thank you, David, and good morning, everyone. Our base business continues to deliver solid results.

Normalized funds from operations increased 28% to $102 million, up $22 million over Q3 2014. Normalized EBITDA was up 19% at $125 million.

We delivered strong quarter-over-quarter growth despite the continued weak commodity pricing, especially Alberta power prices, which hit a new record low average of only $26 per megawatt hour for the quarter. The third quarter marked the first major water flow season for our Forrest Kerr and Volcano run-of-river hydroelectric facilities.

Although results at the Forrest Kerr were down slightly in September due to below average rainfall, a smaller snowpack and one-time environmental testing, the plant still performed exceptionally well. Both Forrest Kerr and Volcano exceeded the design parameters.

The underlying strength and diversity of our assets is clearly highlighted so far in 2015. Challenges driven by current commodity price environment have negatively impacted our gas and power results.

However, they have been more than offset by the addition of Forrest Kerr and Volcano power assets, the strength in our utilities and our U.S. power assets, all of which provided consistent and stable earnings.

Third quarter normalized operating income for the operating segments was 81 million compared to 66 million for the third quarter of 2014. Utilities delivered normalized operating income of 13 million compared to 8 million in Q3 2014.

This was driven by customer and rate base growth combined with favorable foreign exchange and the early approval of SEMCO’s Main Replacement Program. In power, normalized operating income was 42 million, an increase of 23 million over Q3 2014 as a result of Forrest Kerr and Volcano, the U.S.

gas-fired peaking assets purchased in January 2015 and a strong U.S. dollar partially offset by the impact of record low Alberta power prices.

Average realized Alberta prices was $39 per megawatt hour versus $68 in Q3 2014. We hedged approximately 51% of Alberta generation in the quarter at an average price of $50 per megawatt hour.

This compares to approximately 55% hedged at approximately $67 per megawatt hour in the same quarter last year. For 2016, we are currently 31% hedged at approximately $48 per megawatt hour.

Normalized operating income from our gas business was 26 million. This is down due to the significantly lower commodity price environment, lower process volumes and the impact of third-party pipeline curtailments, which have continued into Q4.

For the third quarter 2015, AltaGas hedged approximately 3,000 barrels per day of frac-exposed production at an average price of approximately $27 per barrel. This compares to approximately 5,000 barrels per day hedged at approximately $24 per barrel in the same quarter last year.

The spot NGL frac spread for Q3 2015 was approximately $11 per barrel compared to approximately $17 per barrel a year ago. Realized frac spread of $35 per barrel in the quarter was higher because hedge volumes exceeded frac-exposed production due to the propane reinjection.

Looking ahead at the remainder of 2015, we expect to produce approximately 3,000 barrels per day hedge at an average price of approximately $27 per barrel. As a result of persistent weak pricing, at this time we do not have any hedges in place for 2016.

Overall, with continued weak Alberta power prices and frac spreads, later than expected COD from a client line and continued TCPL curtailments, we expect EBITDA to be up approximately 10% over 2014 compared to the 10% to 15% growth we discussed last quarter. In fourth quarter, we expect to see higher EBITDA from the nominal seasonal strong utility business, stronger power results from the Northwest projects and the addition of GWF, partially offset by continued weaker results in the gas business, driven by the impact of continued curtailments, weaker frac spreads and weak Alberta power prices.

On our northeast BC strategy, everything continues to progress. Producers continue to move forward with their plans and we are actually seeing more opportunities, a lot of which are also driven by the significant progress we have made on our LPG export initiatives.

The overall investment opportunities we are seeing are in the 2 billion range and include the Canadian propane export site, the liquid separation facility near Fort St. John, a Townsend Facility together with gathering sales and liquid pipelines, high potential for further processing and liquid separation facilities and Douglas Channel LNG.

We are pleased with our progress on our Canadian propane export initiative. We signed a definitive project agreement to secure the site and we are moving forward with the consultations with First Nations and securing additional agreements required to move the project forward.

Preliminary engineering has been completed and a frontend engineering and design study will be initiated shortly. At Townsend, we are on track to bring the facility online for mid-2016.

Construction is well underway at this site, earthworks are 95% complete, pipeline fabrication is 30% complete and some major equipment modules have started to arrive at site. Also associated with the Townsend Facility are two other projects.

The first is a 25-kilometer gas gathering line estimated to cost 40 million to 45 million, which connect the Blair production area with the Townsend Facility. AltaGas has moved into construction phase in this project and is on track to be complete in mid-2016.

The second project consists of two liquid egress lines approximately 30 kilometers and a truck terminal on the Alaska Highway. The lines will connect the Townsend Facility to the truck terminal and have a combined initial capacity of 60,000 barrels per day.

This project is in advanced stages of engineering and upon execution of take-or-pay agreements. Expected by the end of 2015, it will move into construction.

We are also progressing on our liquids separation and handling facility near Fort St. John.

Consultations are well underway and we will soon file for regulatory approvals. We continue to work with our partners at the DCL consortium to progress our LNG export plans pending resolution of the import duty on the barge.

Let me now talk about our acquisition of GWF. We have always said that we would be opportunistic with energy infrastructure acquisitions that are a strong strategic fit for AltaGas.

The Tracy, Hanford and Henrietta facilities which combined amount to 523 megawatts are in the market that we well know and are underpinned by PPAs with PG&E for approximately the next seven years. They enhance our stable cash flows and provide additional support to both our dividend growth and stability.

They also provide us with geographical and customer diversification in the California market. Regulations in California, including greenhouse gas emissions, once-through cooling and increased RPS standard of 50% by 2030, all mean that California will need both existing and new flexible generation to be online over the next 15 years.

This bodes very well for re-contracting these assets as well as our Blythe facility at the end of their PPAs. It also bodes well for the development of Blythe II, which we’ll address more at our Investor Day.

Having a diversified engineering infrastructure business across North America gives us opportunities for growth and for creating shareholder value. Finally, at McLymont, we are proud to say that the facility has started generating power on October 1 and on October 25, successfully completed all the requirements under Electric Purchase Agreement with BC Hydro to achieve commercial operations.

We had planned to have McLymont on early to capture upside from Q3. That said, it was still slightly ahead of the original schedule.

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

Thank you, David. Good morning, everyone.

Normalized EBITDA for the third quarter 2015 was $125 million, an increase of $20 million over the same quarter last year. Excluding the impact of commodity driven EBITDA in both quarters, AltaGas reported a 32% increase in EBITDA.

Normalized funds from operations was $102 million or $0.75 per share compared to $80 million or $0.63 per share. Normalized funds from operations were higher as a result of higher earnings from our power and utilities business, partially offset by lower earnings in our gas business, higher interest costs and cash taxes in the third quarter 2015 compared to third quarter last year.

Earnings in our power and utilities businesses have been strong this year despite weak Alberta power prices and the gas business has reported lower earnings due to weak frac spreads, lower throughput at some facilities, the impact of curtailments, downstream of some of our processing facilities and the turnarounds at Younger and Harmattan. In the third quarter 2015, AltaGas reported normalized earnings of $19 million or $0.14 per share compared to $17 million or $0.13 per share in Q3 of 2014.

For third quarter 2015, net income applicable to common shares was normalized for after-tax amounts related to provisions as a result of the expected sale of certain development assets, costs related to energy export projects and unrealized gains on risk management contracts. On a GAAP basis, net income applicable to common shares for third quarter 2015 was $20 million or $0.15 per share compared to $17 million or $0.13 per share for third quarter 2014.

While we have strong cash flow growth, EPS has been impacted by higher depreciation and higher deferred income tax. With execution of our strategy, we have added assets that are underpinned with strong contracts that add stable low-risk cash flows that have been able to more than offset the impact of a weak commodity price environment.

The addition of new infrastructure does result in increased depreciation, which dampened the impact to net income. This compares to the impact to net income from EBITDA from commodity sales, which have very little depreciation charges.

Interest expense for third quarter 2015 was $31 million compared to $29 million in same quarter last year. Interest expense was higher, primarily as a result of increased assets in service and higher interest costs on U.S.

denominated debt due to the strong U.S. dollar.

Depreciation in third quarter 2015 was $53 million compared to $44 million in same quarter last year as a result of increased assets in operations and the impact of the strong U.S. dollar.

In third quarter 2015, we reported normalized current tax expense of $2 million compared to a recovery of $1.5 million in same quarter last year. Income tax is higher in the third quarter 2015, primarily due to cash taxes related to our prior fixed tax on preferred dividends, partially offset by a cash tax recovery at one of the utilities.

For the quarter ended September 30, 2015, net invested capital was $181 million. In the quarter, maintenance CapEx was approximately $7 million.

For full year 2015, we expect our capital expenditure to be at the lower end of our $600 million to $700 million range, excluding the GWF acquisition. We expect FFO to be slightly lower in 2015 compared to 2014.

The growth in EBITDA is offset by higher interest and cash tax as well as lower dividends from Petrogas. In fourth quarter 2015, AltaGas expects to receive $11 million in dividends from Petrogas.

AltaGas continues to work with other shareholders of Petrogas to finalize a dividend policy, which will allow for quarterly dividend payments that ensures Petrogas manages its cash flow and capital expenditures in a prudent manner while returning cash flow to its shareholders. Our balance sheet remains strong with debt to total capitalization of 42% at the end of the third quarter.

On a pro forma basis after closing of GWF, we expect our debt to total capitalization will be approximately 50%. Our average debt maturity is eight years and it continues to be very manageable.

And with that, I’ll turn the call over to Jess.

Thank you, Debbie. Operator, I will now turn the call over to you for question and answer.

Operator, can we just move to the next call please or the next question.

Operator?

Thank you very much. Maybe I will start congratulating David Cornhill for first your wonderful career and I wish you continued success in the next stage.

Thank you.

And maybe I’ll also add to David Harris, congratulations on your appointment. No doubt, you’ll have your hand full in what is a very exciting time for AltaGas.

Thank you, David. Surrounded by an excellent team.

No doubt. So maybe you could start off with regards to the development of liquid separation and handling facility near Fort St.

John. What are the milestones you will have to reach before making FID on that?

Right now, we’re in the next couple of months through consultations. Once we get those under wraps, we’ll move towards filing for application.

The application process will take, say, a three to six-month period of time. So we’re anticipating to have an FID decision on this towards the latter half of '16.

And will you need to have a producer commitment prior to FID or is that following?

It’s not necessarily dependent upon that. We certainly like to have – we’re certainly seeing positive signs in that area but it’s not necessarily dependent on it.

Okay. And then just one last question on that.

Are producers likely to commit to new infrastructure in this commodity price environment, like what’s your – what are you hearing in your discussions with producers?

What we’re hearing is very positive. We certainly believe they are willing to commit in this environment because when you link it with our export strategy, it provides an excellent opportunity for diversification of markets.

So it’s very promising.

Perfect, okay. And then just maybe one question on the curtailments that you talked about in Q3 around the NGTL, I’m assuming it’s NGTL curtailments.

Can you quantify the impact that we saw in Q3 and perhaps what you expect to see going forward?

Sure. In Q3, it was approximately $3 million to $4 million and I would expect it to be approximately half of that potentially for Q4.

All right. And how long do you think the curtailment will last?

I’ve heard things to end of 2016?

We think they will certainly go through '15 and we’re hopeful that we’ll see those start to fall off in the Q1 timeframe to Q2 timeframe of '16. But we’ll see when we get there.

They could extend longer depending on material condition issues.

All right, thank you. I have a lots more questions, but maybe I will get back in the queue.

Thank you. Congratulations to David and David, and Debbie I hope to see you at the Investor Day on Monday, but congratulations to you as well.

Thanks, Linda.

With respect to this import duty that you’re appealing, can you just describe maybe the basis of your appeal, when you might expect an outcome of that and if it’s possible to get to a positive FID before resolution of that?

It’s John Lowe. I’ll chime in here.

The essence of the appeal is the characterization issue and it’s whether it is a vessel or a light vessel. And in fact the floating unit is incapable of navigation, it has no self propulsion and it’s going to be moored permanently.

And so our case is that it really is classified properly as machinery for liquefying air and other gases and that’s the essence of it. And we had our appeal heard on September 25.

We expect a decision in November, by the end of November of this year. And really it is a necessary condition for us to reach FID.

That’s great. Thank you.

And with respect to the gas plants that you are looking to build, can you talk about what sort of assumptions you might be using for frac spreads assumptions or forward pricing on NGLs that are informing some of your outlook for some of your development projects on the gas plant?

Sure, Linda. This is David Harris.

I mean, right now when you take a look at frac currently today, it’s around the $4 mark, relatively flat through '16 and '17. So the reason for the build out of facilities into our energy export strategy is looking to arbitrage the value in Asia which is considerably above those current frac rates we’re seeing within Western Canada.

Okay, that’s helpful context. I’ll jump back in the queue.

Good morning, and I’ll echo everyone’s congratulations all around. Maybe just to keep on the liquid theme, just in terms of the propane export terminal, these definitive agreements are just for the site and would you need customer commitments to make this move forward or would you be open to having some exposure there?

You’re correct. The agreements are just for the site to allow us to go forward with developing and constructing the project.

And the way exports work, you usually get year ahead type commitments. So we’re not looking for any type of long-term commitments to underpin this.

And in terms of the site, would this be co-located with some of your other investments on the coast?

I’d just hold on, on commenting on that at this point.

All right. And then maybe just finally, just in terms of how connected all these liquids projects are, is the export terminal dependent on the frac, dependent on some other investments in the area or could you do one-off investments?

They could either be linked or we could certainly do one-off. This certainly gives us a tremendous brush of flexibility.

All right, thank you. I’ll hop back in the queue.

Good morning, everyone, and I’d also like to send my congratulations all the way around. My first question would just be to touch back on the Douglas Channel duty.

Obviously getting a resolution you mentioned could have an impact on FID. But could it also have an impact on your discussions for off-take agreements?

I think it’s a significant cost item. And so any cost item does bear on off-take agreements.

That said, EDFT is our off-taker. They are already in place and they are well aware of the duty impact.

Is there anything like – seeing that this is unexpected, is there anything like this that you’re currently evaluating as a potential impact on maybe the Trident or the LPG export projects?

Well, it does potentially affect other barge-based liquefaction projects and we’re not the only one, and we feel that on a policy basis it’s not in Canada’s interest to impose this sort of a barrier to these developments, particularly when there really aren’t any shipyards in Canada that would be able to undertake this sort of a project.

Okay. Thank you very much.

Good morning. Few questions just to clarify what happened in the power segment in the quarter.

In particular, I noted that Forrest Kerr was down 5 million from normal. But as I understand, Forrest Kerr is supposed to normally do 40% or so of EBITDA – of its annual EBITDA in the quarter.

And I think guidance there was for about 100 million of EBITDA. So the 42 million of operating income reported for the quarter doesn’t seem to reflect much other than Forrest Kerr, maybe a little bit more, but there’s lots of other assets in there like Blythe and Bear Mountain and the co-gens in Alberta.

So I guess I’m just wondering if it’s because Alberta is losing money or if there is something else in there like business development costs that dragged the results down in the quarter, or is it something else and maybe just some general commentary in response please?

So, Matthew, there were some incremental costs at Forrest Kerr just related to operating expenses just through the first full quarter of water flow. So the impact of the lower water was about 5 million but there was some higher OpEx that impacted results in the quarter as well.

Okay, thanks. Anything else in there?

No, everything else was pretty much normal from a Sundance perspective. We did have hedges in there.

So that helped offset the impact of spot. But overall quarter-over-quarter, it was really – in the Sundance asset, it was really all around power price.

All the other assets operated pretty much on spec.

Thank you, Debbie. Just a follow-up question on power.

In invested capital, there is 11 million invested for construction and operation of Northwest Transmission Line. Can you confirm that that will be an ongoing annual type of payment and that it will be – continue to be capitalized?

Yes. So it is.

I think it’s 20 years. We have the commitment and then that goes in as an intangible asset that gets amortized over the life of the PPA.

So that will be an annual cash outflow and cash flow from investing.

Correct.

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

Good morning, everyone, and congratulations on your career developments. Most of my questions have been covered.

I just wanted to go back to the liquids up again. Specifically my question is, I just want to discuss the linkage between the deep cut at Townsend and the liquids hub.

Is there any link between the two? In other words, can you reach FID and liquids hub without the Townsend deep cut?

Yes, we can, Robert. And Townsend is a shallow-cut.

So they’re independent of one and other.

So it was in the phase II with deep cut.

Phase II will be a deep cut. That’s correct.

Right. So there’s no link between phase II deep cut and the liquids hubs now?

No, not at this time. It would certainly be complementary but it’s not necessary.

Okay. And then you’ve mentioned in the past Forrest Kerr in normal sense the water flow issue with Forrest Kerr and Volcano were exceeding design parameters.

With limited experience you have with and the climate being on line, how would you characterize this performance versus the design --?

Yes, it’s extremely limited. As you know, we started up on the 10th and we just achieved commercial operation datas.

We’re certainly seeing signs that it should be equally as favorable, but I want to keep my powder dry on this. We’re getting into the low flow seasons and I’ll come back at you with that as they get, probably not even in February, let’s get a couple of quarters under our belt, we’ll discuss that in more detail.

But certainly expect and see similar conditions as we have with the other units at this point.

Okay. Thank you.

Thank you and congratulations to David, David and Debbie. First, could you please comment on this gas distribution acquisition fad that appears to be going on in the U.S.

with the potential mergers of Duke-Piedmont and Southern-AGL. So it looks like you bought SEMCO at the bottom of the cycle at 9x EBITDA and they were hitting the top of the cycle here.

Is there a potential for AltaGas to buy or sell gas utility assets here? And if you might be a buyer, what would be the maximum size of the gas utility acquisition?

I’ll jump in quickly. Thank you for the compliment.

I think we’re still looking at tuck-in natural gas utilities. I wouldn’t see any – we would not be looking at doing a merit type transaction, but small tuck-in utilities we would continue to look at that would drive our strategic direction.

But we’re not in hurry. We’ve got good capital growth on rate base and we’ve got some interesting projects on our utility side as well with pipeline expansions and things like that.

So we’re pretty comfortable with our portfolio, but clearly the long-term objective is to grow our utility asset base.

Thank you, David. What kind of returns might you be modeling on power assets, post re-contracting such as GWF post its PPAs?

Do you expect to hold equity returns flat after paying off the assets or do you expect increased returns?

This is John O'Brien. I think that we would – we view both the GWF assets as well as Blythe as being from a locational standpoint in very good shape.

If the PPAs roll off, obviously we think with both Southern California Edison in the event of Blythe and in the instance of the GWF assets with PG&E that there is a good opportunity to re-contract the assets in light of where California is going because of renewables. So the assets we’ve purchased or about to purchase in California are very flexible and we think meet the demand in California.

So we think there’s an opportunity both to re-contract. But in the event that there is some merchant opportunity, we didn’t put a lot of value on that in our GWF assets when we looked at it, but there is certainly opportunity on a merchant basis.

Thank you, John. Debbie, you noted that you look to reach a 50% debt to capital ratio after the GWF acquisition.

Is there a threshold around which your debt providers might start looking for an additional equity contribution, or could you go well above 50%?

We can certainly go above. I mean we’ve historically said that we’re comfortable with our debt to total cap in the 55 to 60, especially with the Northwest projects coming on.

So we certainly have the ability to increase that debt to total cap. There is no expectation there that anyone will look for us to do further equity.

I mean we just did I think a fairly decent flood of equity with respect to the GWF acquisition. So don’t expect any pressure on that front.

Thank you, Debbie. Those are my questions.

Okay. Thanks.

Good morning. Just wanted to stay on California and the GWF.

You talked about the re-contracting opportunity. Do you guys need to put more capital at the end of the contract term to continue running those plants in California?

No. Obviously, we’re eager to get in there after the close and operate the assets.

But as through our due diligence, we think that the assets are in good shape and have been well run. As you probably know, Tracy was converted to a combined cycle facility in 2012.

So there was a great infusion of capital there to convert the facility. So we think that pre-close here that the assets have been well run and that we’re taking over some assets that aside from normal outages and maintenance, which obviously we will continue and have to do, that there’s not a huge capital infusion at the end of the PPA.

Okay. And then maybe just on a broader level and sticking with the M&A side but more in the power side rather than utility and maybe you can just comment on the deal flow you’re looking at over the last quarter?

I know you’ve been pretty busy on the Cali side. Just in terms of spreads and multiples and also you talked about diversification earlier in your comments.

I mean is there a lot of opportunities outside California now that you’re taking a bit more look at right now?

Well, David, do you want to --?

Well, there’s always abundance of opportunities. I think our primary focus right now, we certainly like the assets we’ve acquired and our primary focus will be on the building out of Blythe II.

There are repowering opportunities we have with some of the Veresen assets that we acquired early during the year. The re-contracting of Blythe I probably will consummate the majority of our focus.

It doesn’t mean if something exceptional came along we certainly wouldn’t consider it depending on where we sit, but it would certainly have to fit with us strategically and visualize on where we’re going as a company if that helps answer your question.

Yes, it does. And maybe just lastly, just as you mentioned Blythe, where are we with the California RFP?

You talked about Q4, this quarter before. What’s the latest on that?

Are you on Blythe II?

Yes, the California RFP.

Yes, we are continuing to meet with customers. There is no official RFP out yet that would meet with what a Blythe II would look like.

So we are hopeful that we’re going to see RFPs either late this year or early next year. But that does not mean that we’re not out talking with customers because we do believe that what we’re proposing to do when we amend our technology application at the CEC, the machine we are proposing to build down there we think is really a good, flexible unit for California.

So we eagerly await RFPs, but [Technical Difficulty] talking with customers about Blythe II.

Okay, very good. Thanks a lot.

Thank you very much. Good morning, and I will give a triple D congratulation out there to keep it short.

Wanted to touch on the propane side first and I’m wondering if you can give us a little bit of color on what’s happening at Ferndale. And then on your West Coast British Columbia solution, is this a rail shipping type solution or is this a rail pipeline shipping solution that you’re looking at?

This is David Harris. So into the first part first, Ferndale is going exceptionally well.

We’ve completed another number of modifications. That facility has got the capability now to be in the 30,000 barrel per day range in combination both with propane and butane, and we’re extremely pleased with what we’re seeing there.

To your second question, this will be a rail and export facility and right now it’s not planned to have a pipeline connection to it.

Okay, thank you. And then on the Douglas coal, clearly surprised by the 25% import duty charge.

What import duty charge were you expecting if any then?

Zero was what we’re expecting and that’s the rate for machinery for liquefying air and other gases.

Got you. Thank you.

Good morning. If I can just follow up on a couple of answers that you gave around potential contracting for new projects, and apologies if I didn’t hear it correctly.

Around the LPG, were you mentioning kind of one-year forward type deals? And then there was a comment on the liquids separation that having customer contracts in place wasn’t a prerequisite to move forward to FID, did I hear that right?

That’s correct.

And I guess how do you think about that? Is that just because you’re not anticipating material amounts of capital that has to go out the door or are there other kind of contracts that you have either upstream or downstream that you feel you either have a supply push or demand pull that gives you the comfort to put the capital in without contracting?

It’s David. We have significant control barrels now and so we’ve got it already primed.

And with the response we’re seeing from producers, we feel very comfortable that that capacity will be filled very quickly. So I guess it’s the confidence that we have, position we have in place today plus the response we’re seeing in discussions.

So we just feel very comfortable with our position.

Got it. So effectively it’s a year-long barrels and based on what you see in the market, you’re just making your own long kind of commodity position better to underpin it and then you’re assuming everybody else will show up.

Is that the best way to think about it?

Yes. And as more – in a project as you get more defined, you get more traction with producers.

And clearly at this point from indications, we could fill this facility over several times. So it’s more how we move forward in that position.

Got it, okay. And then you mentioned kind of the $2 billion of gas-related opportunities in BC.

And if you look into through the end of 2016 without handicapping specific projects, what’s your sense of what percentage of this amount you actually see reaching FID by the end of next year?

Probably approximately 50%.

Okay. Thank you very much and congratulations, best of luck to the two Davids.

Thank you.

Just wanted to – one quick follow-up, Debbie, on a comment you made around the $11 million dividend from Petrogas, especially in Q4. Is this sort of the regular dividend we might expect going forward?

I would say it would be in that – we would expect it to be in that range, David.

Okay. And then just a follow up on the, David Cornhill, you made a comment about tuck-in acquisitions in natural gas utilities.

I was just wondering with the change in tax law in Ontario reducing tax barriers to private company M&A, would AltaGas consider less utilities as well?

We’ve been looking at that market for about a decade, so yes.

All right. What might cause you to take the plunge?

Well, I think a little more clarity on where Ontario is going but it’s something that the other day, we would feel very comfortable with John O'Brien. So I think – and it’s really consistent with what the Board would feel comfortable with.

So we’re just looking at and trying to find the opportunities to make sense for us. It’s nothing more than that.

Okay. Thanks for the color.

And maybe one last question, just on the LPG export, we’ve seen both on the LPG and LNG sell situations where companies kind of move forward with the site only to run into snags later on in the development and perhaps wish they had taken the strategy of developing two sites at once. What do you think about that strategy and if that’s something you will consider as you look to have a Canadian-based LPG export facility?

I mean, we certainly wouldn’t rule anything out that we thought was a smart thing to do for the company. I think AltaGas is also uniquely situated that we’ve got excellent reputation in dealing with First Nations and government.

We certainly view the First Nations as an ally and they are part of the solution for certain. So right now, we’re not really running a parallel path from a standpoint of multiple export terminals.

So we’re pretty comfortable with the position we’re in right now. But we certainly wouldn’t rule out optionality down the road depending on what we come up against.

Great. Thank you very much.

Those are my questions.

Good morning, and congratulations all around as well. Debbie, just back to the California acquisition once the deal closes in a month or so, I know you’ll be layering on some U.S.

debt as a partial currency hedge. But will you also be looking to lock in your FX exposure on the U.S.

dollar cash flow over the next seven years?

No, Patrick. I mean we continue to look at the FX exposure that we have and with the U.S.

denominated debt we think we’re fairly comfortable with the FX exposure that we have today.

Okay. And then maybe just a follow-up to Steven’s question with respect to the balance sheet.

I’m sure we’ll get some more details on Monday. But perhaps we can get a snapshot on your target credit metrics, debt to EBITDA, FFO to debt once some of these larger projects come on stream here over the next couple of years.

I don’t have those right at my fingertips, Patrick, but you are right. You’ll see a little bit of that on Monday.

But needless to say, the overarching strategy is really making sure that we maintain our credit ratings. So our credit metrics really are all about supporting that credit rating.

Okay. Thanks, Debbie.

We’ll look forward to Monday.

Yes. And we do have – saying that, we do have lots of room on our covenants, so no issues there.

Great, thanks. That’s all I had.

Thank you. With the new governments in Alberta, are you involved in discussions around potential electricity market redesign that might include capacity payments?

At last year's Investor Day, you noted a capacity market might be necessary to affect a transformation away from coal.

We’re always engaged with the new government. We’ll certainly be staying close to them.

And they contemplate what they’re going to from a power program. I guess it depends on how things actually materialize on the environmental side with the new regs coming in and then from there what are the appropriate triggers for new builds to turn around and replace coal.

So a little premature at this point to really get a clear view, Steven. We’ll see what happens over the coming months.

It’s David. We’ve had discussions at the ministerial level both on environment and energy and are actively engaged in various fronts there.

Thank you, gentlemen. The next question is on LPGs.

Producers seem to be willing to fill your BC LPG export terminal. But you also have a line of sight to overseas buyers, or more specifically has Idemitsu indicated how much LPGs it might be willing to buy to hold up its end of the partnership?

Idemitsu directly and through their subsidiary at most is very engaged in looking to acquire barrels off our Canadian LPG on a long-term basis.

Excellent. Thank you.

Thanks, operator, and thank you to everybody for joining us today. We are available throughout the day for any follow-up questions and look forward to seeing many of you at our Investor Day on Monday.

Thank you.