Jess Nieukerk – Senior Director, Investor Relations David Harris – President and Chief Executive Officer Tim Watson – Executive Vice President and Chief Financial Officer John O'Brien – President-AltaGas Services U.S. John Lowe – Executive Vice President

Rob Hope – Scotiabank David Noseworthy – Macquarie Robert Catellier – CIBC Capital Markets Patrick Kenny – National Bank Robert Kwan – RBC Capital Markets Ben Pham – BMO Capital Markets

Thank you. Good morning, everyone.

Welcome to AltaGas’ first 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 would 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 first quarter of 2017 was a very strong quarter for AltaGas both from a financial perspective and from a development perspective. We achieved record normalized EBITDA in the quarter of $228 million, an increase of approximately 28% over the $178 million achieved in the first quarter of 2016.

Normalized funds from operations were up 29% at $170 million, or $1.01 per share, compared to $132 million, or $0.90 per share, in the first quarter of 2016. These strong financial results were driven by the strength and diversity of all three of our business segments.

Normalized EBITDA increased 91% in gas, 16% in power and 6% in utilities over Q1 2016. Pomona Energy Storage improved Petrogas results, the termination of the Sundance PPA, colder weather at most of our utilities and increased frac spreads among other things, all contribute to our results.

We also made significant progress with the northeast B.C. and energy export strategy.

On January 3rd, we announced a positive final investment decision on our Ridley Island Propane Export terminal. This terminal is expected to be the first propane export facility off of Canada's west coast and only the second terminal on the entire North American west coast.

The Ridley export facility will have the capability to export 40,000 barrels per day of propane with expansion capability. The competitive advantage of Ridley Island is that it is a brownfield site with excellent railway access and ample deep water access to the Pacific Ocean.

The extensive land and water rights held by Ridley Terminals through the Prince Rupert Port Authority and the existing world class marine jetty at the site allows for the access and efficient loading of Very Large Gas Carriers, which can reach key global markets without limitations. Both Ferndale and Ridley Island Propane Export Terminal have strong locational advantages given very short shipping distances to Asian markets, only 10 days compared to 25 days from the Gulf Coast.

We have moved into the execution phase of Ridley Island with site preparation and pre-construction activities well underway. We have also made great progress on the construction of towns in two ways and are on track to move into commercial operation by October of this year and we are tracking ahead of schedule on our North Pine liquid separation facility, which we now expect will be online in Q1 of next year.

Finally, we are in advanced discussions with a couple of other producers to take capacity of towns in 2b, which would be another 99 Mmcf per day of processing capacity at the towns inside. We expect to have more news on this later this year.

As mentioned in our press release, in January Altagas entered into a non-binding Letter of Intent with a significant Montney producer to construct a 120 Mmcf per day deep-cut natural gas processing facility and a NGL separation train, capable of processing up to 10,000 barrels per day of NGL mix, and a rail terminal. Although significant progress had been made on the definitive agreements, negotiations have been placed on hold to allow for review of growth plans by the counterparty.

Our midstream strategy continues to open the door for numerous new potential customers with a lot of discussions taking place. We remain very focused on northeast B.C.

and on energy exports as we truly believe it will be a game-changer for producers and the industry. I also want to say a few words on our Gordondale deep-cut facility.

The acquisition of assets in the Gordondale area that Birchcliff completed in 2016 meant that they also assume the take-or-pay agreements we had on Gordondale. This agreement remains in effect until volume commitments unmet likely around the 2020 timeframe.

We are in discussions with Birchcliff for our potential expansion of their process agreement. The Gordondale facility is strategically located within the liquid-rich Montney Fairway with excellent NGL recovery capability and connectivity to product Egress.

We're also in active discussions with other customers in the area to potentially expand the Gordondale facility including extending the gas gathering network. Gordondale is a relatively new facility, which we brought online at the end of 2012.

It is a very efficient deep-cut facility with an operational capacity of approximately 135 Mmcf per day. It was designed and constructed with whitespace as our intent was always to expand the facility and tie in other customers in and around the area.

The Gordondale site has the potential to support additional processing capacity to reach up to 500 Mmcf per day. Turning to power, in California, we continue to move forward on various initiatives to strengthen our position in the market.

Following the successful startup of our Pomona Energy Storage facility, we received a certification from the California Independent System Operator to be able to participate in the ancillary services market. This allows us to offering ancillary services from Pomona expanding the flexibility of the energy storage facility and allowing us to earn additional revenues above the contracted resource adequacy payments.

With the success of Pomona, we have recently participated in another request for office in California and hope to continue to expand our energy storage footprint. All of our sites in California have the capability to host battery storage and we’ll continue to actively participate in this market.

Also as mentioned back in February, we're in the process of reconnecting Blythe to the El Paso’s natural gas supply. The connection work was completed in the first quarter and provides Southern California Edison with additional flexibility and redundancy at very low cost.

We continue to believe that Blythe is in a very competitive position both from an operational and locational standpoint, which positions us well for recontracting. We also continue to look at combined offerings: gas with renewables or energy storage, which fits well with the requirements of the market.

Finally, our utilities continue to operate smoothly and reliable and grow at a steady pace. We continue to invest on average approximately 125 million to 150 million per year into our five utilities generating modest rate base growth.

We also continue to modest customers’ growth at the majority of our utilities. In December, we filed an application with the Michigan Public Service Commission seeking approval to construct, own and operate the Marquette Connector Pipeline.

This is the single biggest project at any of our utilities. And if approved, would be part of SEMCO’s regulated assets.

We expect a decision on this in Q4 of this year. The project is approximately US$135 million to US$140 million and we would expect it to be in service by 2020.

Let me turn now to talk about some of the questions we have been getting relating to the acquisition of WGL. First, we remain very committed to all three of our business segments.

These three segments may never be perfectly balanced in any given year, but our strategy is to balance them over the long-term. As I stated in my first conference call as CEO one year ago, Altagas’ success has been driven by a business model of low risk long-life clean energy infrastructure assets in midstream, power and utilities as was evident by our Q1 results.

This is not changed and will not change with the acquisition of WGL. In fact, this is why WGL was so attractive to Altagas.

Not only was the acquisition very accretive on both earnings per share and cash flow per share metrics, but WGL’s infrastructure assets also fit extremely well with Altagas’ portfolio. Beside as being a top-tier gas distribution utility, Terry and his team have done a very effective job at significantly diversifying WGL into an energy infrastructure company with complementary business segments utilities, midstream and clean power through distributed generation.

Furthermore, WGL has significant growth opportunities expected in each of these segments. By 2019, the first full-year with WGL we would expect our utility segment to contribute in the high 40% range of overall EBITDA with a natural downward trend as we continue expand the midstream and power segments.

Through WGL’s investments in key pipelines and positioning around the prolific Marcellus play, we believe we will see even further opportunities in the future to potentially expand the investments in those pipelines or even break into the Marcellus with our strengths in natural gas processing and liquid separation. Likewise on the power side, WGL has distributed generation in over 20 states.

This also provides a strong platform for future growth including the potential at large scale clean generation in these areas. Touching on the regulatory process, we filed our applications with the District of Columbia, Maryland and Virginia on April 24.

In advance of the filings, we've been actively interfacing with regulators, government officials, key stakeholders and community groups to gain a healthy understanding of what is important to them. We focused our efforts and commitments based on our learnings.

WGL and Altagas are well respected and well run companies that share a common culture and a commitment to safety and customer service. Both companies have strong relationships with regulators within the utility jurisdictions we serve and are confident we can work with the District of Columbia, Maryland and Virginia to achieve approvals in a timely manner.

In summary, our first quarter results were very strong and have positioned us well to achieve our high single-digit percentage growth guidance for 2017. We have a substantial number of projects and development opportunities on our plate across all three of our business segments and will not lose focus on any of them.

Finally, we will continue to work closely with WGL and the regulators to ensure the success of this acquisition. This transaction is highly transformational for our company by increasing both our scale and breath of quality assets.

The combined company will have approximately 22 billion in assets on a Canadian dollar basis and over 7 billion growth opportunities on a Canadian dollar basis and the ability to deliver strong returns to our shareholders. I will now pass the call over to Tim.

Thank you, David. Good morning everyone.

The strength of our first quarter highlighted the full breadth and extent of our diversified business platform with all three business segments contributing to significant year-over-year growth led by midstream and power. In total normalized EBITDA for the first quarter of 2017 was up 28% to $228 million compared to $178 million in the first quarter of 2016.

Growth was partially offset by a lower U.S. dollar in the quarter.

Now to quickly review each of the three business segments starting with gas midstream, where EBITDA was $67 million, up over 90% versus the first quarter of 2016. Gas midstream accounted for approximately 29% of total overall normalized Q1 EBITDA.

On a gathering and processing side excluding the non-core assets which were sold to Tidewater in Q1 2016, total volumes were up 34% due to the addition of the Townsend processing facility and partially offset by slightly lower Gordondale volumes delivered in excess of take-or-pay levels and lower volumes of Blair Creek. In addition higher revenue for NGL marketing, higher realized frac spreads and volumes and higher natural gas storage margins all contributed positively in the quarter.

During the quarter, Altagas completed the previously announced sale of EDS and JFP transmission assets to Nova Chemicals for net proceeds of approximately $67 million. Power EBITDA was $50 million, up 16% compared to the first quarter of last year.

This represents approximately 22% total normalized EBITDA. Contributions from the new Pomona Energy Storage Facility in the absence of equity losses from Sundance B PPAs were significant contributing factors.

Higher wind conditions at the Bear Mount facility, higher dispatch at Blythe despite the plant outage as it contributed to California’s system reliability and increased generation of the Grayling biomass facility also contributed positively. Finally, normalized EBITDA at our regulated gas distribution utilities increased almost 7% to $115 million in the first quarter of 2017.

Colder weather versus last year, albeit not versus seasonal norms in Alberta, Nova Scotia and Alaska was very beneficial for the utility business as was the interim and refundable rate increase of ENSTAR. This was offset by the Customer Retention Program at Heritage Gas as well as warmer weather in Michigan, higher expenses and again unfavorable foreign exchange rates compared to the first quarter of last year.

Petrogas results were also strong in the quarter. Equity earnings from Petrogas increased to $11 million in the first quarter compared to $2 million last year in the same quarter due to the continuing strengthening of Petrogas’ business segments, which support upstream activities export shipments out of the Ferndale Terminal and dividends from the preferred share investment that we made.

Normalize funds from operations or FFO were $170 million, up 29% from $132 million in Q1 2016. On a per share basis normalized FFO was $1.01 up $0.12 – up 12% versus last year.

Stronger results in all business segments partially offset by lower common share dividends from Petrogas and higher interest expense contributed to this excellent performance. In the first quarter of 2017, we received $4 million in common and preferred share dividends from Petrogas versus $6 million in common sure dividends for the same period of 2016, which was in line with our expectations.

Petrogas retained cash in Q1 2017 to fund its growth capital program and for general corporate purposes. Total normalized net income for the quarter was $65 million, or $0.39 per share, up strongly from $38 million or $0.26 per share in the first quarter of 2016.

Normalized net income was higher due to the same factors impacting normalized EBITDA as you’d expect. Partially offset by higher income tax, interest and depreciation and amortization expenses.

Normalizing adjustments for the quarter can be found in our MD&A disclosure and includes certain items relating to the acquisition transaction and financing costs. On a U.S.

GAAP basis, net income applicable to common shares for the first quarter of 2017 was $32 million or $0.19 per share this compares to $55 million, or $0.38 per share, for the first quarter of 2016. Interest expense in the first quarter of 2017 was $46 million compared to $36 million for the same period last year.

The increase was mainly due to amortization of financing costs associated with the bridge facility obtained for the pending WGL acquisition, lower capitalized interest and higher average interest rates, partially offset by lower average debt outstanding. Depreciation and amortization was $72 million in the first quarter compared to $68 million last year, this increase is mainly due to new assets placed in the service.

In the first quarter of 2017, income tax expense was $21 million, up from $ 6 million in the same quarter of 2016. The increases was mainly due to the $10 million tax recovery related to the Tidewater disposition in the first quarter of 2016 and a portion of WGL transaction costs incurred this quarter, which were not tax deductible.

Invested capital was $87 million during the first quarter, down from $151 million in the first quarter of 2016. Over two thirds of total investment this quarter was directed into the gas midstream business segment.

Net of dispositions primarily the pipeline sold to Nova Chemicals that invested capital in the first quarter of 2017 was $18 million. Investment in property, plant and equipment decreased last year as we completed construction of Townsend and purchased the remaining 51% of EEEP back in 2016.

Maintenance capital for the Power segment was $3 million in the quarter and there is no maintenance capital specifically directed to the gas segment. Altagas’ balance sheet is in a strong position and well funded for 2017.

At the end of the quarter, debt-to-total capital was 42% down from 46% at the end of 2016. This remains well below our bank in term note covenant levels of 65% to 70%.

As a reminder, there is approximately $1.9 billion available on our existing bank credit facilities and we continue to have strong access to multiple sources of funding. So far in 2017, we've completed a successful $300 million preferred share offering, which was very well received by the market.

This financial was forward-looking in nature as we continue to see strong momentum in our development program with plans to construct several new infrastructure projects between now and the end of 2017. During the quarter, we also successfully issued $2.2 billion of subscription receipts related to the pending WGL acquisition in addition to the 400 million private placement with omers.

Turning to 2017 and our outlook, we continue to expect high single-digit percentage normalized EBITDA and FFO growth as compared to 2016. Each of the three business segments we’ll contribute to this growth led by the gas midstream segment.

The power and utility segments are expected to represent approximately 75% of total 2017 EBITDA, but gas midstream will see an increase in its proportionate contribution to total EBITDA versus last year. Increased annual 2017 EBITDA from gas midstream is expected to be driven by the first full year of operations at Phase 1 of Townsend, higher frac-exposed volumes and commodity prices and a partial year contribution from Townsend 2a or train – the first train there entering commercial operations in the fourth quarter of this year.

In addition, we expect higher earnings from Petrogas due to improved profitability in the base business, higher volumes at the Ferndale Terminal and a full-year of income from our preferred share investments. These additional earnings will be offset by the sale of the EDS and JFP transmission pipelines, which closed in March of this year and that transaction impacted EBITDA or will impact EBITDA by $10 million in full year 2017.

Furthermore, the Edmonton Ethane Extraction facility and the Turin gas facility are expected to undergo normally schedule turnarounds mid this year not only impact EBITDA by approximately $5 million. Based on current forecasted commodity prices, the amount of extraction volumes exposed to frac spreads is expected to increase to an average of 9,500 barrels per day for 2017 compared to 6,500 barrels per day last year.

We have hedges just in place this year for approximately 5,500 barrels per day at an average price of approximately $23 per barrel excluding basis differentials. As a reminder, every plus or minus $1 per barrel change in frac spread results in approximately $1.5 million change in our EBITDA in 2017.

Approximately 60% of our 2017 gas EBITDA is expected to be underpinned by take-or-pay in cost of service contracts, which again have no direct price or volume exposure. In 2017, we expect Petrogas will have several growth capital projects that will likely take some priority over common share dividends, but again this does not have a material impact on Altagas overall.

We do however expect to receive $13 million from a full year preferred share dividends from Petrogas. 2017 full-year growth in the power segment will be driven by the addition of the Pomona Energy Storage facility, which entered commercial operations in December 2016 including additional revenue from the ancillary services market, which Pomona recently became certified to participate in.

Higher earnings are expected from the Northwest Hydro Facilities as productivity improvements in contractual price increases take effect and lower planned outages at Blythe are also expected. Utilities are expected to see a moderate increase in normalized full-year 2017 EBITDA compared to last year.

This increase is driven by rate in customer growth as well the expectation of a normal weather year compared to the warm weather experienced in 2016. In 2017, ENSTAR EBITDA is expected to increase by approximately $3 million as a result of the interim refundable rate increase approved later in last year by its regulator and its final rates are expected to be set in the third quarter of this year.

Turning to capital expenditures, we expect to spend between $600 million and $650 million this year. The gas segment will account for approximately 65% to 75% of that total.

While utilities will account for approximately 20% to 25% and the power segment will account for 5% to 10%. Gas and power maintenance capital is expected to be approximately $25 million to $35 million.

Majority of 2017 capital will be allocated towards Altagas’ growth projects related to the northeast British Columbia and energy exports strategies including the Ridley Island Propane Export Terminal, Townsend Phase 2a, the North Pine Facility and the North Pine Pipelines. The 2017 capital program is expected to be funded through internally generated cash flow and the dividend reinvestment plan.

If required, we also have sufficient borrowing capacity available under existing credit facilities as well as strong market access. We expect approximately $295 million for depreciation, amortization and accretion expense this year as we have demonstrated over the past year we will continue to focus on enhancing productivity, reducing costs and streamlining our business including the disposition of smaller non-core assets.

Our 2017 corporate effective tax rate based on normalized earnings is expected to be approximately 24%. Approximately 50% of total expected 2017 EBITDA for Altagas will come from the U.S.

and again that just reflects our diversified business platform across all three major energy infrastructure business lines. As a quick reminder for every plus or minus 5% change in the Canadian/U.S.

FX rate, foreign exchange rate, the annual impact to total 2017 EBITDA is about $15 million. So in summary, we had just completed as record quarter for AltaGas.

Our guidance remains unchanged as we are on track to deliver high single-digit performance growth in 2017 with a number of key investments setting the stage for further growth in 2018 and beyond. Quickly and just rounding out a couple quick comments on WGL, we plan to complete the long-term transaction financing as the regulatory steps progressed through the second half of 2017 and into early 2018.

More specifically we will plan to undertake senior debt, hybrid securities, as well as selected asset sales of approximately 1.5 billion to 2 billion Canadian dollars. We believe there are number of attractive actionable opportunities to monetize portions of our three businesses in a manner, which supports our long-term strategy of growing in attractive areas and maintaining a long-term balanced mix of energy infrastructure.

These could include selected assets within the existing U.S. power portfolio, potentially some additional non-core assets within the mainstream business and our minority interest in one or more of a Altagas gases existing utilities.

Much of these additional proceeds will be realized in U.S. dollars and will help repay the U.S.

dollar bridge debt facility. We've also undertaken foreign exchange hedging for the large majority of the $2.6 billion in equity subscription receipts that we successfully raised in February of this year.

Our combined platform and financing strategy is set to deliver our balance sheet and it presents a clear path forward with FFO-to-debt of greater than 15% for the first full year in 2019. This will strengthen and maintain our currently very solid investment grade credit ratings.

The strength and stability that depending acquisition brings to our funds from operations is expected to provide strong security to our dividend. This is an important point to emphasize that WGL transaction will allow us to grow the dividend by up to 8% to 10% annually while still lowering our payout ratio that speaks to the sustainability in the future growth in the dividend.

Finally, the acquisition of WGL will allow us to pursue and accelerate growth opportunities in all three of our diversified energy infrastructure business segments while ensuring financial strength and flexibility. And with that I'll turn the call back to Jess.

Thank you, Tim. Operator, we’ll now open up the call for questions.

Good morning everyone. Congrats on a good quarter.

Just moving on to WGL, I'm just kind of hoping you could add maybe a little bit of additional color on how those discussions with stakeholders have gone so far and whether or not the regulators have been receptive to your plans on bringing some additional let's say higher management functions into those key areas?

Thanks, Rob. This is John O'Brien and I've been on the ground a little bit down there.

And I would say that we have – first of all, WGL, it is clear has really – there's a high regard for WGL leadership in each of the jurisdictions and that has become clear during our meetings. I would say that that we have met across the board either with commission staff or others like the Office of Public Counsel in D.C.

and Maryland and there's been a healthy respect. There has been an open door for us to go in and brief them.

But as Dave noted today, the filing went in on Monday. So certainly, we're going to have parties now reading our filings in each of the jurisdictions.

And I would say that I think that the case that we put together is a good strong case, but we certainly are giving the parties now time to read what we've actually filed. But I would say that the meetings that we've had in each of the jurisdictions have gone well and people are open and receptive to the transaction.

And again, I would say that WGL has really strong relationships in each of the jurisdictions.

All right, that's helpful. And then just moving over to your 2017 outlook, it appears Q1 was a very, very strong quarter in part on the back of some NGL pricing.

Just with maintaining the high single-digit EBITDA and FFO growth outlook there, is this just being conservative or are you giving yourself some wiggle room if you do pursue some assets sales towards the back half of the year?

No, I think – so to be clear our guidance hasn't changed still that that high single-digit guidance for EBITDA and FFO in aggregate and that’s consistent of what we said for press quarter. You're right.

There were several things I think that maybe helped us although there were some offsets as well in the first quarter. On a comparative year-over-year basis, we didn't have Sundance to report in the first quarter of this year.

We had some arguably some very strong storage margins. We had Petrogas prior period adjustment that contributed to the first quarter of this year.

We had some offsets. As I mentioned, the U.S.

dollar was a little bit weaker and notwithstanding better weather from our utility perspective. It still wasn't normal weather in most of those utilities frankly.

And we had things like the Nova Asset sale that was programmed in as you know. And so, there are a bunch of puts and takes Robert.

And I think those are just natural for a business because we've got a nice set of diversity across our three business lines. And so I think as you work through those, our expectations really have not changed.

We think it'll be a very strong year overall from a gross standpoint in that high single-digit range.

Thank you. That's helpful.

But just to clarify would it be correct in assuming that Q1 was above your plan?

Yeah, I would say it is just – Dave Harris, chime in a little bit. Yeah, we’re certainly seeing some favorable signs in the business, but again it's a solid first quarter.

Let’s get deeper into the year and see how few other things shake out, but consistent with Tim we're very confident on a very high single-digit year-over-year growth delivery.

Perfect. Thank you.

All right, good morning. Thank you for taking my questions there.

So just with regard – so with your regulatory WGL, with your regulatory applications submitted, when does your focus turn to the asset divestitures and kind of – can you give us any kind of timing on opening up the data rooms? It sounds like your timing has moved up from kind of timing with the close, close of these acquisitions from the timing of the close of WGL to something that could be in 2017?

No, David. This is David Harris.

I'll jump in and Tim and others can join if they like. It is our timing really hasn't changed.

We've just did the filing on Monday. As John O'Brien pointed out, we’ll give the regulators time to read and digest that filing.

We’ll see what comes out of our filing from a commentary standpoint. And then as we get to probably the middle of this year, we'll put a finer point on what the timeframe looks like with respect to asset sales and other things, we will do to complete the transactions of WGL.

Yeah, there's certainly nothing that we've said in this call is any different from what we would have said a quarter ago, David. So they have to be in sync ultimately and so the milestone this past week was the filing on the regulatory side.

We are not in the market on asset sales in a material way. And that will be as David said a second half exercise and into early 2018.

Okay, sorry, I was just reading into your outlook saying that asset sales may impact negatively our EBITDA growth expectations for the year and previously you had stated that asset sales would be kind of a first half 2018 close. So that just suggests to me that you’re expecting a sooner close.

No. Actually in the last quarter, I did actually say that asset sale processes can take anywhere from – you name it a month to six months depending on the nature of the process.

And if you start to look at those sorts of things in the middle of this year as David said, you could very well see some conclusions on certain of those asset sales in calendar fiscal 2017, now it wouldn't be a full year impact. But if you were to close a certain asset again if I'm just making up an example for you, end of Q3, early Q4, there would be some impact not huge from a full year perspective.

So that's entirely consistent with what we said in terms of some of the questions on that subject.

And David, the only thing to just keep in mind is in the absence of the WGL transaction as there was some non-core assets that we would be looking to turnaround and move on anyways as we consistently have said over the last year that are not necessarily tied to WGL.

Right, that makes sense. Thank you for clarifying that for me.

And if I could just turn to your Ridley Terminal, can you provide an update on the third party option to precipitate?

Sure. We have been in in-depth discussions and we will have more color on that in Q2, but discussions are going quite well.

And that option expires at the end of this month?

No, it actually goes into Q2.

Oh, okay.

Yes. So we think we've got some time on that, but as I said the discussion is going quite well.

We like the counterparty and we will have more color on that in Q2.

And if I just – sorry just one last question on Ridley. Can you help us understand how are your contracts with producers where you're basically acquiring your physical propane volumes match up with the off take agreement you have with Astomos for the 50% of volume off take of the Ridley plant.

In terms of I’m just trying to understand what are the factors are going to make your margins move on that 50% of volumes?

David, I’m not sure I quite understand. Did you want to just repeat that again?

Yes, sure. So I'm just thinking you talked about your supply.

Basically, you have 50% physical supply through your own facilities. And those are – that supply garnered through a number of contracts with producers at your facilities.

And then at Ridley, you have basically offtake or a sales contract with Astomos for 50% of the volume that would go to that facility. And I guess I made the assumption that the idea would be that your physical supply that Altagas controls would satisfy the sale of that propane to Astomos to Ridley.

And then I was trying to figure out are those back to back in the sense that you’re able to lock in a margin? Or are there elements that aren’t back to back and therefore you could see margin expand or contract based on factors, which I'm not sure which ones those would be?

Yes. It's a 60:40 split with respect to what we're targeting right now.

So there is a mixture of both actually quite frankly.

Okay. That's not just – it's not that clear cut.

Got it.

That’s correct.

Okay. Thank you very much.

Those are my questions.

Hey, good morning, everyone. I just wanted to question you a little bit on Blythe, the re-contracting strategy.

And it seems like things were rewarded a little bit in the MD&A. And there is no mention of – not as much mention of RFPs, but more of a focus on bilateral discussions yet the plant had some pretty strong dispatch in the quarter.

So can you comment on the significance if any of that wording change and has there been any modification to your re-contracting strategy?

Rob, this is John O'Brien. I don't think in anyway the wording means to change our strategy.

I think it does highlight right now for instance in the California market you see as an example these community choice aggregator entities that are growing, whereby they would be taking load from the IOU and going out and supplying themselves with generation and that could be a mix of renewable having to be balanced with gas. So I think in the wording you may see that that we're indicating that is also part of our strategy in addition to working on a re-contracting strategy, which ties a little bit to our discussion of Blythe being able to take gas from two systems both So Cal and El Paso.

So I think the wording may highlight some of the things that are right now prominent, which are in particular this community choice aggregator type of customer that might be out there. So all things are on the plate in terms of how we look at Blythe post 2020.

And it may just be that it's an emphasis on some of the policy changes that are going on in California right now and making sure we're aggressive and trying to track down opportunities there.

Okay, got it. Thank you.

And then just a little bit of an update on the Montney facilities, where you signed an LOI in January yet the discussions are placed on hold. So maybe you could give us a little bit more color on what led to preliminary negotiations on hold?

And an extension of that what impact do you expect the B.C. NDP government would have on your Northeast B.C.

strategy?

Robert, this is David Harris. I'll start first and then I'll let John Lowe to chime in on the thoughts around the elections coming up in B.C., but really not too much more color to add than what I had in my commentary on my script is we certainly have forged a very good and healthy relationship with this counterparty.

And like all companies have that times of the – the fact to take a step back, it just reflects that what they want to do with growth plans for a number of different reasons, but I really couldn't give clear line of sight on. But I think we've decided to turn around and just put this on hold for right now.

We don't see it impacting anything with respect to our Northeast B.C. strategy.

We're seeing a tremendous amount of activity and into varying levels of discussions with multiple counterparties, especially after the announcement of RTI from an FIV perspective and that we've actually physically moved into the pre-construction. Phase 2a is going along quite nicely finishing up.

That's getting some highlights with some other produces out there as we've also said with folks having a healthy interest in 2b and expansion beyond that and then also another areas of the Montney. You always got to respect the company's decision to take a step back and reflect.

We like the relationship and the positive about this, we had a good working relationship with them and we still do and it’s just one more counterparty that we can partially look to do things with in the future.

And on the election, it's difficult to predict elections these days. Of course, I will say that elected officials of all political stripes are very supportive of our Ridley Island Propane Export Terminal and that's in a strong NDP area of support.

On the natural gas front, I think that the both parties see scientifically sound oil and gas development particularly natural gas development in B.C. as a driver of jobs and prosperities, First Nations’ benefits.

And we don't really see much change on that front, no matter who ends up winning this election.

Yes. I think I agree with that.

And then just finally on the regulatory apps here, can you give a maybe more fulsome description of how if there's been any change really to the customer benefits you’re proposing now versus what you may have contemplated at the time of the transaction?

I would say no. In general, we have done a pretty healthy amount of research in terms of the precedents in each of the jurisdictions, while also adding we're a different case then some of those cases.

So I would say in general no. There are we – it's not something different than what we contemplated at the time.

I would say within a general aggregate number, dollars may have switched, because you do. We heard things on our listening tour for one of a better term for instance job training and workforce development is very important in each of the jurisdictions.

So that is highlighted in our filing is something that we want to work with the jurisdictions on, because quite frankly in our industry, we need to be doing that kind of development anyway. So it dovetails with what is important to our industry.

So you will see in the applications that there are things that are specific based on the jurisdictional provisions and the test that we have to meet in each of the three jurisdictions, but in an aggregate on number it is not different from what we were planning on when we looked at the transaction.

Okay. That's helpful.

And just last question for Tim, I was wondering if you could quantify the Petrogas prior period adjustment and if you don't have it here I just maybe let me know offline.

Very low single-digit.

Okay, thanks.

How are you guys? I know there's a competing project right next door to you Ridley.

Just wondering if you could remind us what the ultimate capacity potential is at RTI over and above the initial 40,000 barrels a day. And what I guess the full build out EBITDA multiple might look like relative to the initial phase at 8 to 10 times?

Thanks.

This is David Harris. So certainly this expansion capability at Ridley and reasonable amount – it's not something we'd really want to talk about right now on any expansion though.

I would expect the multiple to be equal to or probably even greater than by modest amounts on any kind of expansion.

Okay. And then just lastly on the frac volumes relative to the 9,500 barrels a day forecasted for 2017, can you just remind us across your fleet what the maximum frac volumes could be in a high frac spread environment?

Yes. Currently right now it's about 10,000 barrels per day.

That's great. That's all I have guys.

Thanks.

Good morning. If I can just turn back to the WGL regulatory filings and I know John you mentioned job training workforce development.

I'm just wondering outside of things like rates. I'm just wondering if there were other key issues that were put in front of you that and that you felt comfortable addressing in the filings.

And specifically, we've seen a bit of a trend or some other filings of what I'd call win-wins where [indiscernible] that are easy for you to provide that helps make your business better.

Yes, I would – the one that – this is John O’Brien again. The one that came to mind certainly prominently was workforce development.

We certainly – because of our power business and because of WGL’s unregulated business, you will see and there are commitment to develop 5 megawatts of either a Tier 1 renewable resource or battery storage. So you will see that in there.

You will certainly see some because we've heard it and it's particularly important for utilities, including our utilities you will see some emphasis on what we can do for low income folks in the jurisdictions. And so you will see those in the filing.

We pay particular attention to governance and making sure we do that correctly. So that what is important and you see this throughout when utility transactions are put before commissions, they want to know that that local WGL management is still there and that that when you pick up the phone, you are still calling Washington or Virginia or Maryland.

So those provisions are in there in terms of our local management of the utility. And again I would say that our team has worked with WGL’s team.

What I would say and I think this is important as we go forward is that both teams are working very well together that there is really a unity of purpose in terms of taking guidance from WGL’s long history in each of these jurisdictions. And I think that that when you see the benefits that we've laid out in the application that's part and parcel of WGL’s experience and are taking some guidance there.

So if I summed it up, it would be – you will see some customer benefits in there depending jurisdictionally on the test you have to meet. You will see workforce development dollars.

You will see some environmental dollars both in terms of a commitment to develop and also a commitment to study some other uses of biogas. And you will see some dollars that can be used to help those in low income either on who are in multifamily housing or who in fact are high users and we can help them be more efficient with gas.

So I would think you will see benefits like that that come from the discussions we've had in the jurisdictions.

Got it. And was there anything that came up in the pre-filing consultations and discussions with interveners that will after they kind of read through it.

You think will become the forefront as an issue that you just didn’t feel comfortable addressing or addressing in the manner that they initially wanted?

I would say that we have – the things we’ve listened to are in the filing. There is nothing that came up in the meetings that would be uncomfortable and that we would not address.

So I would say that that from the meetings, no, where we had a comfort level, but now it's time to read the filings. So the filings are with everybody.

And there will be procedural schedule set out in each jurisdiction, which will allow for a time for interveners to come in. And so more to come on this, because we're actually have put on paper in our filings what our commitments are.

So – but there is nothing that came up that was uncomfortable to us.

Understood. If I can turn to Ridley, can you just talk about the pace of how the capital spend is going to be and is the construction or the Ridley kind of moving into full swing on the construction activity?

Is that tied to actually getting complete definitive agreement signed?

Not necessarily. We've got a clear runway ahead of us, Robert.

So right now, we started a pre-construction activity. So we’re expected to go into full scale construction here in Q2.

It’s a first half 2019 project from a COD perspective. So we don’t see anything in our way that would cause us to throttle or step change as it relates to the construction plan.

Things are moving ahead. A detailed design is pretty much done.

We've got others on long lead equipment. Tank, which is probably the largest cost in the project, has been designed in on order.

I would say when you look at the capital spend profile taking us from where we're sitting here today, June 2019, you will probably see us, but we're in a little bit more than half as we get through the end of 2017. And then as we get through the end of 2018, you will probably see us burn about another 35%, 40% of the capital and then the trim up on that 10%, 15% will take place in closing out in 2019.

Got it. And if I can just a quick question here, around your turnaround plans for the gas side.

I apologize if I missed the previous change, but it looks like the Gordondale turnaround, has come out of 2017. If that's the case, has it just been deferred to 2018 or is there something else going on there?

No. We’ve deferred them.

The other thing is we've got a data with what we're doing with operational throughputs and other things and based off of actually wear and tear on the equipment. We were in a predictive program that is based on high availability, so we make the decisions accordingly.

Okay. So that’s going to push into 2018 or is that kind of undetermined at this point what year it might fall in?

We'll turnaround take a look to see how we run through the facility at the end of the year.

Okay. That's great.

Thank you.

Okay. Thanks.

Good morning. Just given the process of a pretty large WGL transaction and complexities of asset sales.

Do you feel like your balance sheet is constrained here that you can do anything on the acquisition front until transaction close if strong strategic assets were to come up for sale gas process and contract and power?

No. I think we look at trying to grow each of our three business lines in an opportunistic manner.

And whether capital is directed externally or internally as you can see we're actually are growing our business and expending capital to do it. A lot of it is just through this year momentum we have internally on projects, whether it's new projects like Marquette, which are coming in the horizon or the whole slate of gas projects that you've heard about or some of the optionality around future battery projects and things like that.

So that’s all capital. We are always looking externally as well.

Those are less predictable and less out of our control or more out of our control I guess. But that's – we don't see it as that’s – as you think about it normally, I mean you're talking assets and functioning assets, there's cash flow and things like that associated with those assets.

They could actually be credit enhancing, frankly. So it just depends on the situation, but to answer your question, we don’t feel constraint.

Just one other quick point, I just want to follow up from the previous comments from the previous questioner. Just to be clear in Gordondale, we are – there is a turnaround here, but as David said, we fine tune the numbers.

We'll actually capitalize a good portion of that that turnaround, which will have a specific impact on certain of our financial metrics.

Okay. And maybe just to my second or last question, when you look at your internal propane supply demand expectations in Western Canada, do you think that there's a need for Triton LNG export facilities as well as [indiscernible] propane facilities.

And how do you think about that dynamic plan of contracting on Ridley in terms of pace and quantity?

This is David Harris. I'll go ahead and start on that.

We've certainly done a healthy look at what's available for our propane demand within Western Canada and certainly more than supports the activity that's going on out there. So we really don't see any impact whatsoever with meeting the 40,000 barrels per day on the initial design.

And as things pays all the time certainly has the expandability capability to go beyond that. So we don’t see that as any kind of impediment on the project.

And I think just this year numbers give us a lot of confidence and you can look at these numbers up yourself, but if Western Canada is producing 150,000 a day or so of propane, not including propane that’s in trains and certain pipelines like Alliance. And if we're only consuming call 20,000, 25,000 here in this market, you can sort of figure out that there has to be a home for the balance.

And the RTI project from a timing standpoint is far ahead of the two Alberta based petrochemical projects you just referred to either which is received a green light or final investment decision. And we'll be several years behind the launch of RTI in early 2019, so there's a quite a timing difference.

As you know each of those projects probably takes up to 20,000 a day if they actually do decide to go ahead, but you won't see that impact till early next decade. And the other propane project that you refer to as a smaller scale project.

So I think there's actually plenty to go around here and that was part of our thinking all along.

Okay, that’s good to hear. Thanks, Tim.

Thanks, everybody.

Thank you, operator. That concludes our first quarter 2017 conference call.

Ashley and I are available for any follow-up questions you may have. Thank you for joining us this morning.