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

David Noseworthy - CIBC World Markets Rob Hope - Macquarie Capital Linda Ezergailis - TD Securities Carl Kirst - BMO Capital Markets Robert Catellier - GMP Securities Robert Kwan - RBC Capital Markets Steven Paget - FirstEnergy Capital Matthew Akman - Scotiabank GBM

Thank you. Good morning, everyone.

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

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

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

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

Thank you Jess. Good morning everyone.

The weak energy environment persisted throughout the first quarter. Alberta spot power prices were the lowest since deregulation.

Year-over-year they were down to 50%. Spot frac prices declined by almost 90%.

Despite this our base business delivered cash flow in line with last year. Normalized funds from operations was $140 million up $8 million.

Normalized EBITDA was relatively flat at $178 million. On a trailing 12 months basis we continue to hit record cash flows achieving $482 million.

Even with the seasonal low river flows in the quarter both Volcano and Forest Kerr performed better than expected, delivering positively EBITDA. However, given depression and interest, this resulted in reduced earnings of $0.07 compared to the $0.09 we’ve previously forecast.

Our normalized net income for the quarter was $57 million or $0.43 per share. For the full year, we're still expecting a significant increase in powers, operating income and we're expecting the positive trend in our utilities to continue.

The gas segment continues to be challenged. Currently frac spreads remain weak and we're expecting to continue to re-inject liquids at some of our plants.

We were disappointed by the earnings contribution of Petrogas. Petrogas’ performance was impacted by falling energy prices and the Ferndale turnaround.

Our plants are performing well with FG&P volumes relatively flat with strong performance in Gordondale and Blair Creek. Near term in the second quarter we have turnarounds at Harmattan and Younger.

We see normal seasonal decline at their utilities. We expect to continue to face low frac and low Alberta power prices.

Petrogas is expected to continue to be weak in the second quarter with the stronger second half. Second quarter is expected to be our weakest quarter of the year.

For the full year, even with continuing weakness in Alberta power prices and low frac spreads, we expect to see significant growth in EBITDA and FFO. Earnings are expected to show modest growth.

Earning are more levered to the levels of Alberta power prices and frac spread. Based on the expected growth in cash flows and EBITDA, the Board has decided to increase dividend by $1.25 per month per share that's a 8% increase in dividends.

We're still one of the lowest payout in midstream space. We continue to work hard in developing our energy export platform and to deliver export solutions to our customers.

We now have the capability for propane export from the Ferndale Facility. The first shipment of propane was early April.

We're advancing Douglas Channel LNG. On-stream date is estimated to be 2018, but we would hope to advance it into 2017.

We are working to built out intergraded liquid solution in Northeast BC. This would include constructions of pipelines and fractionators.

Having the infrastructure in BC to provide producers with low cast alternatives compared to shipping NGLs to Fort Saskatchewan and then back to tide water. We're also in discussions with producers for additional 200 to 400 million cubic feet a day of new capacity in the Townsend region.

We are looking to develop a deep cut facility and hoping to have producers interest firmed up in the second half of the year. David Harris will provide an update on operations and projects under development.

I’ll pass the call over to David.

Thank you, David and good morning, everyone. The underlying strength and diversity of our assets was clearly highlighted in the first quarter.

As David mentioned, Forest Kerr and Volcano Creek performed better than expected. Volumes were also up at some of key gas processing assets including Gordondale and Blair Creek and our utility performed extremely well.

First quarter normalized operating income for the operating segments was a $132 million. Utilities delivered normalized operating income of $86 million compared to $81 million in Q1 2014.

This was driven by customer and rate base growth combined with favorable foreign exchange, but slightly offset by warmer weather. In power, normalized operating income was $15 million despite record low Alberta power prices results were essentially flat to Q1 2014.

The average realized power price for the quarter was approximately $55 per megawatt hour, which includes pricing from the Northwest projects compared to $69 per megawatt hour for the same period last year. We hedged approximately 54% of Alberta generation in the quarter at an average price of $58 per megawatt hour.

This compares to approximately 59% hedged at approximately $65 per megawatt hour in the same quarter last year. Alberta spot power prices were significantly lower at approximately $29 per megawatt hour in Q1 2015 compared to approximately $61 per megawatt hour in first quarter 2014.

We expect Alberta power price to remain soft in 2015 with the additional 800 megawatt supply from the shepherd power plant. We’re approximately one-third hedged at $54 per megawatt hour for the year.

However, we're starting to see positive signs, which could help bolster market prices in 2016 onward. Till 2016 we're currently 15% hedge to approximately $58 per megawatt hour.

Normalized operating income from our gas business was $31 million while lower frac spread and lower frac exposed volumes were a headwind in the quarter. We saw strong performance at some of our facilities.

Our energy services also had a strong quarter compared to the first quarter last year. For the first quarter 2015 Altagas hedged approximately 45% of frac exposed production at an average price of approximately $27 per barrel.

This compares to approximately 70% hedged at approximately $27 per barrel in the same quarter last year. The spot NGL frac spread for Q1 2015 was approximately $4 per barrel compared to approximately $36 per barrel a year ago.

Looking ahead at our 2015, given persistence low prices and reinjection we expect to produce approximately 5400 barrels per day of C3 plus that is directly exposed to frac spread of which approximately 55% is hedged at an average price of approximately $27 per barrel. Before moving on to our major projects, I’d like to about operational enhancements within our fleet.

At Hamattean with the addition of Cogen 3 and efficiency improvements to our frac plant, we have increased trucked liquids processing capacity by 3,150 barrels per day an increase of 50%. Gordondale now has the ability to process a 135 Mmcf per day an increase of 15 Mmcf per day compared to the base design with further initiatives in progress to take Gordondale to 150 Mmcf per day.

Lastly at Blair Creek Facility initiatives are underway to improve our plant capacity by 10 Mmcf per day by yearend and an additional 20 Mmcf per day by the end of 2016. Collectively, the initiatives at Blair Creek and Gordondale will increase our fleet processing capacity by 60 Mmcf per day for relatively low capital dollars.

Let me provide an update on some of our major projects. At McLymont construction of the seven kilometer intake access road is complete and intake construction is advancing steadily.

Excavation of the McLymont power tunnel has been completed. Construction of the power house and insulation of the turban generators are complete.

Dry commissioning has commenced with fact feed scheduled for Q2. At Blythe we continue to work on the opportunity to double the size of existing facility, while we view the new renewal standard set at 50% as a positive due to the need for backstop generation, these have constituted as a revisit to the generation needs and delay some of their expected RFPs.

We expect the Imperial Irrigation District was still issue on RFP around midyear, but suspect that the Southern California Public Power Authority RFP may be delayed to later in the year. We’re also looking how we leverage transmission connections to different substations.

Blythe is very well positioned to not only serve the California market but also Nevada and Arizona. At Townsend we are on track to bring the facility online through mid 2016.

Detailed engineering is nearing completion and all permit applications have been submitted. Long lead equipment orders have been released.

Sight clearing has been completed and preliminary civil construction work is underway. Full scale construction is expected to commence in Q3 2015, with receipt of regulatory approvals.

The DC LNG Consortium continues to progress the liquefaction badge project in Kitimat. Engineering feed is underway and we're preparing permanent applications.

We're targeting the summit permanent application to OGC at the end of Q2 with an FID target at the end of year 2015 and first Cargo in 2018. Finally we made good progress in Q1 to increase our LPG capabilities at the Ferndale Facility in Washington State.

We successfully converted one of the two tanks to propane service and have already shipment of propane earlier this month. We continue to advance work on the expansion and expect we could reach our target of approximately 30,000 barrels per day within the next 12 to 18 months.

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

Thank you David and good everyone. In the first quarter of 2015, Altagas reported normalized earnings of $77 million, or $0.43 per share, compared to $74 million or $0.60 per share in Q1 2014.

Normalized EBITDA for the first quarter 2015 was $178 million, relatively flat to the same quarter last year. Excluding the impact of commodity driven EBITDA in the quarter, Altagas reported a 16% increase in EBITDA.

Results were impacted by higher earnings from Blythe, higher volumes of some key processing facilities and NG services of frac and power hedges and favorable exchange rates. However, the weaker spot market for Alberta power and frac spreads, warmer weather than last year, lower earnings from Petrogas and higher interest in depreciation resulted in lower normalized net income in the first quarter 2015 compared to the first quarter last year.

Normalized funds from operations were $140 million or $1.05 per share compared to a $132 million or a $1.07 per share. Normalized funds from operations were higher as a result of the higher earnings from Altagas operated assets in the first quarter 2015 compared to first quarter last year.

Our payout as a percentage of normalized FFO for the trailing 12 months ending March 31, 2015, is 47%. On a GAAP basis, net income applicable to common shares for the first quarter 2015 was $66 million or $0.49 per share compared to $40 million or $0.33 per share for first quarter 2014.

For first quarter 2015, net income applicable to common shares was normalized for after tax amounts related to unrealized gains on risk management contracts and development cost incurred for energy export projects. In first quarter last year, we also recorded cost related to Nova’s exercise of its purchase option of EDF and GFT pipeline.

Right now in power assets, which are under development and the cost of early retirement of debt and a gain on sale of gas processing facility. Interest expense for first quarter 2015 was $30 million compared to $25 million in the same quarter last year.

Interest expense was higher primarily as a result of increased assets and service. Depreciation in the first quarter 2015 was $50 million compared to $9 million in the same quarter last year again as a result of increased assets in operation.

In 2015, we expect to record approximately $25 million of depreciation and amortization related to the Northwest projects. In the first quarter 2015, we reported an income tax expense of $30 million compared to $17 million in the same quarter last year.

Income tax was higher in first quarter 2015 primarily due to higher income subject to tax as well as a $12 million tax recovery related to one-time items recorded in the first quarter 2014. While the effective tax rate in the first quarter 2015 was 28% compared to 26% in the first quarter 2014, we expect the annual effective tax rate to be approximately 20% for the full year.

For the quarter ended March 31, 2015, net invested capital was $131 million and maintenance capital in first quarter 2015 was approximately $1 million. For full year 2015, we expect our capital expenditures to remain in the range of $550 million to $650 million.

Our balance sheet remained strong with debt-to-total capitalization of 45%. With a strong balance sheet and approximately $340 million in cash on hand and short-term investment at $1.8 billion available on our credit facilities.

On the financing side, in April we successfully completed a US$125 MTN offering. Our average debt maturity is 8.5 years and continues to be very manageable.

We will continue to balance our long term and short term financing as well as floating and fixed rate debt in order to execute our discipline financing strategy that supports our business strategy. And with that, I’ll turn the call back to Jess.

Thank you, Debbie. Operator, we’ll now turn the call over to you for questions and answers.

Good morning.

Good morning.

Maybe just start off on your LNG projects. You mentioned that you're still targeting an FID for end of 2015 for Douglas Channel.

When you sit down with your project management team and review the timelines, what are the areas for potential slippage? And can you provide us any color regarding the probability of those events occurring either individually or collectively?

David this is David Harris. I think the probability is high.

We always certainly monitor the permit and the application process, but we've got a tight package and a tight applications. So the double are in the details when it gets down to getting approvals like that.

So all things being equal, we see nothing at this point that would derail us from that initiative of achieving that goal by the end of '15.

So, the probability of hitting that is high?

Is high.

Okay. Just to make sure I understood that.

Okay. And then, when you think about the Triton project and the related PNG project, can you give us any update on your thinking around those two?

We're still progressing on the application process and the engineering that goes with that and monitor that closely depending on where the market is in the cost impacts and the timing of it. So it's still progressing as we have planned and as we get a little bit deeper into it, we will be able to give a little bit of final scope on timing of that.

Have you put out an expected FID for those projects yet?

No we haven’t.

Okay. And then, just in terms of planned off-takers, is the idea to have buyers of LNG?

Or is the idea of tying in sellers of natural gas within Canada or have you thought for that part well as yet?

We have -- we're looking at both of those avenues.

Okay, both. Thank you.

And then, just maybe, you mentioned -- and this is, I guess, to David Cornhill -- you mentioned that you expect to firm up additional gas processing demand in the second half of 2015. And I was just wondering; how high do oil prices need to recover for some of these prospective growth projects to be committed?

Or I mean maybe said differently; do you think producers will commit to long-term firm commitments in the current commodity price environment?

I think it's -- we are looking at Townsend, it's more understanding the commitment of some of the LNG projects going ahead with Douglas Channel first, but there is a couple of coming down the road that would really enhance the probability there. We have a lot of interest, we have resource, producers want to be ready, but I think they need a little more color on some of the export opportunities, because I think it's clear to everyone that Western Canada doesn't need more natural gas production without energy export.

Got it. And would the Pacific Northwest LNG project be one of those catalyst projects?

Or is that one not really going to impact the producers that you'd be working with?

Any exports positive for the producers that’s integrated into the Trans-Canada line as well as Sumas can supply alternative market so there is any growing gas markets for Western Canadian gas is positive generally for the environment.

Okay. And maybe one last question on your California RFPs.

I guess, David Harris, what is the expectation of the impact of this additional review time in terms of what the nature of those RFPs will look like?

I think it's more of a balancing act David, it's obviously you press up on renewable portfolio standard. It means the mix change is obviously getting more with renewable, but as a result of that you need more firm energy to come in behind it.

And so it certainly take a look at the supply curve and demand. I think it's positive.

It's just a matter of the utilities getting a feet underneath them and what their actual needs are, so they can go out with a credible RFP.

Perfect. Thank you very much.

Those are my questions.

Thank you. Good morning.

Maybe just one quick follow-up on David's question. So, you had mentioned that you still expect the Imperial Irrigation District RFP in not too long.

But, what about the Southern California Edison and San Diego Gas and Electric ones? Are those still expected in early 2016?

Early to maybe a little bit of a shift. I think the other thing that’s at work is some transmission discussions as well and then not only the RPF as far as being in and out of basin what that may hold firm, but we're still expecting them to be here in a reasonable timeframe within 16, they may drift a little bit two to three months, but nothing that’s a radical change.

And has the expected sizes of any of these RFPs, including the Imperial Irrigation, changed?

I think the expectation is they may. I certainly can't read the minds utilities out with the RPFs, but you could see a little bit more firming coming to that as a result of press up in the renewable portfolio standard requirement.

Okay, good. Then one last question.

Just in the MDA you made a comment about there's a potential that projects under development could be delayed given the slowdown in the Montney. Is that in reference to Townsend?

No not at all. Townsends on a very solid firm track and we see no expected delay with Townsend whatsoever.

Then, what projects of AltaGas' would that be referring to, then?

It’s a Phase II timeline commitments for additional 200 million to 400 million cubic feet a day. I think that’s where producers until they get a clear vision of export will want to be ready, but whether they will commit to long-term processing when they don’t see a market is another matter.

Alright. Thank you for that.

Thank you. You pronounced that perfectly.

In terms NGL volumes, I'm wondering the degree and the composition of what you are re-injecting. Is it primarily ethane or substantially propane as well?

And has your expected NGL volumes exposed to frac declined over the year because of the change in your re-injection assumptions or gas composition or something else?

I will start and then David will correct me. Last composition we have actually seen richer streams at various plants, especially the straddle plants.

We’re re-injecting C3 plus at a lot of the facilities because of other places we're re-injecting more propane are the principle volumes where we're injecting. It's pure price.

Propane the energy of propane are more valuable than the gas stream than it is as a at this point.

Okay, that's a very helpful context. And just a follow-up on Debbie's earlier comments on tax.

It was helpful to get a full-year outlook for the effective tax rate. Can you maybe give us a sense of how your cash taxes might look for 2015 and beyond, an update on that front?

It's not materially more than we had in 2014. We will have a couple million more as a result of the higher tax on preferred dividends, but overall I would say no material impact.

Okay, that's helpful. And we're still discovering the seasonality associated with the Forest Kerr and Volcano.

So, can you maybe provide some more detail around what a Q2 contribution might be seasonally, either normalized or for the actual water levels that you're seeing?

Yes. Based on where we are now and what we are expecting the facility to produce, we expect Q2 to be just likely above breakeven for the quarter.

Okay. That's great.

Thank you.

On an EPS basis.

Thank you. Good morning, everybody.

David, I just wanted to make sure I understood what you were saying with respect to Townsend and the question of, perhaps, slippage in project development. That just at the base Townsend is fine, locked and loaded.

It's really just talking about Phase 2 that could potentially slip if we do not have, for instance, clarity on B.C. exports and, obviously, commodity prices stay where they are.

Is that the correct understanding?

We feel very comfortable with this program for Townsend on the first phase and gas being there mid 2016.

Great. That's what I thought I heard.

I just wanted to make sure. One other clarification, if I could.

You had mentioned in your prepared comments talking about maybe building fractionation in B.C. in support of, essentially, B.C.

exports, LNG exports. And I just wanted to make sure I understood that.

Are you talking about that generically as the B.C. LNG picture clarifies, perhaps if Petronas goes forward this summer?

Or were you specifically linking that to your Triton initiative?

Its more general environment in British Columbia and I think I may have misspoken, I said LNG instead of NGO. We're putting together -- we think it's a compelling economic reason to frac NGLs from producing Montney area to support LPG export, whether it's Frendale or other BC locations when we think it’s a significant cost advantage to that compared to transporting C3 plus to the Fort Saskatchewan and then moving it back to tidewater.

Excellent. I appreciate the clarity.

And then, last question, if I could. Just wanted to get your thoughts on what you still think ALA can deliver from a long-term dividend CAGR perspective recognizing the pressures we have today, perhaps offset with the additional opportunities you still see.

We've done I think 25% over the last two years. We're targeting double digit plus or minus I think is a reasonable expectation.

Our payout ratio is low. We've taken a quite headwind with respect to commodity prices, but the base business as Debbie said grew by 16%.

We're seeing good growth in that part of our base business and with any positive tailwind on commodity we can see that type of growth easily.

Great. Thank you, guys.

Thank you. You've gotten to most of my questions, but I just want a little clarification on Phase 2 of Townsend and how much capital you expect could be deployed there as currently envisioned.

And further, I'd like a clarification if you're looking to expand the raw gas processing capacity as well as the deep-cut?

To answer your first question Robert on the capital side, somewhere between $350 million, $400 million approximately and as far as the processing side we would be looking to expand may be both ends of that.

Okay. So, then, to make it all the way to the deep-cut decision, you'd need more commitments from the producers on the raw gas side beyond just the Painted Pony commitment to the base Townsend plant.

Thanks correct

Yes. And I'm curious about two things with respect LNG.

The first is how the -- it seems to me, in the current price environment, you're still relatively bullish on achieving FID at Douglas Channel. But, at least from what we can tell, it looks like a more economic project than maybe some of the others.

So I wondered if you could comment on how the commodity price environment is impacting the FID decision there. And then, if you could maybe give us some direction as to what you think the relative cost competitiveness of Triton will be.

So, I assume it's going to be more expensive than Douglas Channel. But can you give us sort of an order of magnitude that we're expecting cost for that project on an MMBtu basis to end up?

No. answer for the last question.

Not at this time. Clearly what we're seeing in the market place of Douglas Channel is significant interest and we think we are competitive.

We are looking at -- and on two fronts one is from my perspective how important exports markets are for the Western Canadian base and current pricings it’s a significant uplift for producers to export even at lower LNG prices worldwide. So that’s still critical and we see Douglas Channel is very competitive and from indications in marketplace that supports.

Triton still is a little early with lots of moving parts to clearly we know, where the target is and where to get over for pricing. We think we can do that with our phase 2 projects, but to be honest our organization focus is first to get Douglas Channel going.

We think it's critical and then moving to putting a little slower phase on Triton just from a resort perspective we don’t want to stumble up with Douglas. We want to make sure that success and then put more resources on the Triton project.

Yes. So, I think you've answered my question there.

So, with what you know today, you expect Triton to be able to clear the market's expected cost hurdles.

We think so. We're working optimize.

Clearly the goal is to get -- become lowest cost. I think you will hear that from producers as well.

You want to be lowest cost. You want to drive that efficiency and we are looking at ways of doing that with Triton and all our LNG projects including Douglas Channel.

Okay. Those are my questions.

Thanks.

Great, thank you. If I can just start with more of a higher level on California and power.

And, Dave, you're lucky you've got a very long history with the California market and you've seen lots of changes in regulatory. So, when you look at Blythe and some of the RFPs being pushed back with the changes in the renewable requirements and then you look at the plants that you just acquired, two older ones in California, what's your vision for both Blythe and those two plants playing into that market, particularly given where the environmental side is going both with respect to renewable requirements, but the other one on water rights?

Okay, well first let's start with Blythe and then I'll talk about how it links to the recent assets we acquired, which is Ripon and San Gabriel, but we certainly like our position and we like our position. We thinks it's improving with each passing day.

As renewals push up you obviously get a press up the firming power and the other thing that's started to take shape is we always said even when we went back to acquire Blythe is as you get to the later half year of '19 and '20 that’s when you see in the main stream of coal retirements coming into play. So there will be a fair amount of coal retirements coming into play.

I think its causes so many utilities and utility commission in California to revisit what they do at certain transmission if they may need it and it just helps firming up the advancement of Blythe 2 and potential even Blythe 3. The other thing we're liking what we see is Arizona has a fair amount of coal retirement is coming up around 2019-2020 timeframe as well and that’s we like diversity that we have where Blythe can go both in an East and Westerly directions factoring Arizona and to a certain extent reasonable extent, Nevada.

Moving that in and how that links with what we have with Ripon and San Gabriel we like the in-basin type of play that Ripon gives us and we're extremely confident that we will see an expansion within Ripon as it relates to support in base powers as a result of all the changes and dynamics taking place in California. And I think the other thing that comes into play too because it goes through cycles, but they certainly feel the pain when it happens and you're seeing it right now, right when water flows off and you don’t have stone pack in seasonal rains.

You're already in a drought condition. You’re not going to get as much as hydropower coming down in the upper side of the Northwest and it puts added stress on loads as it relates to California.

So all in all, I think we situated our self exceptionally well with the recent acquisitions California and our existing plan in Blythe and expandability. And then just a touch on water rides is with the hold of only one licence right now within California for power, which is invaluable and provides a competitive advantage on heat rate perspective.

So, I guess is it fair to say that while the timing of some of these RFPs has been pushed back, you feel probably even more confident at this point on the certainly of Blythe 2 and maybe 3 and the economics of it?

We do. The words I use is its not if it is when.

Okay. And is there a chance, then, to marry-up Ripon and San Gabriel with Blythe, to package it up to maybe use the other two on peaking side?

We're looking all alternatives right now. We've just brought on Ripon and Sam Gabriel.

So we're working through a number of analysis on what’s the best way to look at our powerful folio within California. So it’s a good question, but there is still a lot more analysis that we are looking at.

Okay. And if I can just turn to M&A opportunities.

What are you seeing out there both on the power and the gas side and maybe even more especially on the gas side with what's going on in Western Canada and the potential to get some infrastructure out of producers?

We're busy we are seeing a lot both on power as well as gas. We're being choosy at this point I would say.

We want to understand market a little better. We've got all our finances in place to do some significant acquisitions, but we’re seeing a little conservative at this point in terms of opportunities.

I would expect some this year. The other thing is producers are still somewhat shell shot and they're going through their financing, bank relationships and things like that.

So I would say the second half will be much busier than the first half, but we want to be conservative on making sure we buy the right assets for the long term strategy. So we're not in the rush to acquire something.

It's going to be right piece.

All right. Thanks, David.

And just you mentioned understand the market better. Was that in reference to the power market or the gas market?

No other gas market. It’s the change the volume -- producers are still unsettled and I think it's just prudent for us to make sure that we are very comfortable with the asset with the producer with the economics.

You've got to be able to structure something that makes sense for the long term and relatively low gas price for the long term and that’s something that sometimes is a disconnect with producers with their price expectations.

Got it. Okay and just one last question.

I think it's to you, Debbie. Just a bit of a cleanup here.

There was a contribution into the equity account investments. Was that funding a cash loss in the quarter or are we seeing a change where that line item is now going to be funding CapEx or growth CapEx?

Are you looking at the cash flow Rob.

I am, yes. So, $4 million went in.

That’s really related to operating for Sundance.

So there was a cash call this quarter then.

No its really -- it's not so much a cash call. With the world oil prices we pay out instead of getting cash in.

: So there was a cash loss.

Yes

: Okay. And just to be clear, growth CapEx will still go in, in investing activities.

Correct.

: Okay. Perfect thank you.

Thank you and good morning. You've talked about the potential of Ripon, but could you also please comment on the strategic advantages as you gained by purchasing San Gabriel and Brush off Harrison?

Certainly Steven. As it relates to Brush we're just taking a look at that right now.

It certainly is a little bit of an out lie, but we like where it is and especially considering we own a piece of Brush Ranch, so it’s a natural fit for the company in many respects. But again like I had stated earlier, it's a relatively new transaction for the company.

We're getting our arms around what we would do with that and how to best leverage it. In the same way, with San Gabriel.

The other reason Ripon’s a little bit high of priority is just uniquely where it sits and as it relates to in-basin generation and some of the stressors we're seeing there. So there will be more color to come on that as we working ourselves through this transaction over the next two to three months.

And to recall Steven we sold Alberta peaking. So we really dropped out commodity exposed power earnings for contracted earnings.

Thank you, Debbie. Thank you, David.

You've got a significant, I think 1,000 megawatt wind development portfolio across North America. What's the potential of converting some of these assets into developed construction projects?

We continue to monitor those everyday Steven. It certainly has caused it go for maybe a bit of what used to be a floodlight to a spotlight so to speak especially with the press up of the renewal portfolio standard and whether we elect to go forward with them all is an opportunity to turn around and either trade those assets or sell those assets.

So we're evaluating that now.

Thank you, David. Will AltaGas Kitimat to Petrogas be putting some of its own NGLs on its books through Ferndale?

Petrogas will be clearly selling product out of Frendale.

Thank you, David. Are you seeing more interest in Ferndale from U.S.

or Canadian producers?

We’re seeing interest in Frendale from all North America Western half.

Thank you. And how many barrels have been committed to Ferndale for the remainder of 2015?

We can’t release that.

And what are you seeing in terms of the appetite of Pacific Basin consumers for North American propane and butane?

They have significant appetite for propane and butane short shipping and getting product finding markets for product is not an issue.

Excellent. And, finally, could you please comment on the progress on Alton Gas Storage in the quarter?

Sure we’ve -- there are two fronts as it relates to all the construction based activity. We've completed everything we can do to date.

And John Lowe is here with us he can talk on the regulatory front, but we have made I would consider substantial progress on the regulatory front especially in the wake of some many announcements around Deep Panuke and Salyle and the added stress that could cause to that province for future gas pricing.

We have got a science review with the Mi'kmaq and that's progressing well. The government of Nova Scotia, we believe, is quite interested in getting this plan constructed as there are some difficulties with the offshore Nova Scotia shop.

So lots of support to the act.

David, John, thank you, everyone. Those are my questions.

Thank you. Good morning.

David, I think you mentioned that you were disappointed with Petrogas results in the quarter. I'm wondering if you could expand on that.

What areas of the business in particular weakened and what’s your outlook for those areas.

Some of it was just a drop in energy prices narrow margin business so they get percentage of price and as well the liquids market reset at the end of March. So they have been able to resettle a lot of things.

So that was it as well as the Ferndale turnaround where we decreased their capability to move product off for about four months. So some of that was expected.

But those were the two that we see were disappointing compared to last year if you look quarter-over-quarter. We were hoping for a little stronger performance than they delivered in the first quarter.

We were very comfortable in second half with the turnaround at Frendale behind them, we think they are in excellent position.

What was the -- there was a comment in the MDA outlook section that the EBITDA of Petrogas is expected to increase with the growth in fee-for-service and margin. What are some of the assets that they've just brought online that will result in that?

They have a number I think strategic storage facilities whether it's in Sarnia and Chicago and at the Fort. Those are all coming online.

So those are probably -- those are the key once Ferndale as well. So they have a number of strategic storage positions there are just as coming online this year.

Okay, thanks. And just, final question.

I know that the Company, Petrogas, working with ATCO on some cavern storage in that areas as well. And do you know if those will be fully-contracted types of assets and what the returns on capital look like, roughly.

I can’t be -- but generally I would say that they are contracted.

Okay. Thank you very much.

Those are my questions.

Thank you, we have no further questions at this time. I would like to return meeting back to Mr.

Nieukerk. Please go ahead.

Thank you, operator and thank you everybody for joining us today. That concludes our Q1 2015 conference call and if anybody interested we can have our AGM webcast later today as well at 3 PM Mountain Time.

Thank you.