Jess Nieukerk – Director Finance and Communications David Cornhill – Chairman and Chief Executive Officer David Harris – Chief Operating Officer Debbie Stein – Senior Vice President Finance and Chief Financial Officer

Linda Ezergailis – TD Securities David Noseworthy – CIBC Carl Kirst – BMO Capital Markets Robert Hope – MacQuarrie Robert Catellier – GMP Securities Matthew Akman – Scotia Bank Robert Kwan – RBC Capital Markets Steven Paget – First Energy Capital Winfried Fruehauf – Winfred Fruehauf Consulting

Thank you. Good morning everyone.

Welcome to AltaGas’ fourth quarter and year-end 2014 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, Jeff. Good morning everyone.

We delivered record funds from operations of $472 million, or $3.72 per share, an increase of 17% over 2013. EBITDA was also at record levels of $546 million.

Normalized net income was $165 million, or $1.30 per share. The Forrest Kerr and Volcano hydro projects reduce earnings in the fourth quarter by about $0.04 per share, as a result of start-up late in the season.

Since our last conference call on October 30, we have seen dramatic changes in the energy markets. Crude oil is down by 37%, Edmonton propane prices are down by about 68% and natural gas is down by 24%, such a dramatic changes create challenges and uncertainties for oil and gas producers.

At AltaGas we could now have entered this time in a stronger financial position with over $400 million in cash on the balance sheet and our bank lines essentially undrawn. Looking at 2015, we are expecting challenges in our gas business as producers deal with the uncertainty, but we also see significant investment opportunities.

We are working hard to deliver flat operating income in the gas business in 2015. Being in this target, we’ll be challenging with continuing low commodity prices and plan turnarounds at our two largest plants: Younger and Harmattan.

Finally, our Utility business growth will continue on trend in 2015. One can see the value of AltaGas’ business mix and strong operating capability in the current environment.

2014 was a milestone year where we positioned AltaGas’ business for substantial growth through to the end of the decade. On the gas side, some of the key accomplishments are we began supplying the Asian markets with North American energy through our Ferndale facility, secured a site, which will enable us to begin LPG deliveries of the Canadian west coast in this decade.

Developed key alliances with Painted Ponys and others to unlock the vast natural gas reserves and deliver energy to Asia. Our power business made significant strides as well.

The completion of the Forrest Kerr and Volcano hydro projects, we have positioned ourselves to have the ability to triple the size of the Blythe Energy Center and we have reduced our position in the Alberta power market while increasing our contracted U.S. generation.

Our utility business continues to grow customers and rate base and deliver clean affordable and reliable energy to our customers. Finally, we grew our dividend by 16% in 2014 and expect to be able to increase our dividend again this year.

Any decision to increase the dividend will be made by the Board at the appropriate time. At this time, I’ll pass the call over to David Harris, President and Chief Operating Officer.

Thank you David and good morning everyone. In the fourth quarter, we experienced strong operation results in our Gas and Utilities segments.

Normalized operating income from our gas business was $41 million, compared to $39 million for the same quarter 2013. Our gas business benefited primarily from the acquisition of Petrogas and higher volumes at Harmattan, Gordondale and Blair Creek.

We continue to benefit significantly from the ramp up in volumes in liquid rich areas. Total volumes processed increased by nearly 100 Mmcf per day to 1,551 compared to 1,454 in Q4 2013.

For the fourth quarter 2014, AltaGas hedged approximately 72% of frac exposed production at an average price of approximately $26 per barrel. This compares to approximately 83% hedged at approximately $27 per barrel in the same quarter last year.

The Spot NGL frac spread for Q4 2014 was approximately $15 per barrel, compared to approximately $32 per barrel a year ago. The utilities segment continues to deliver solid results with normalized operating income of $57 million compared to $55 million in Q4 2013.

This was driven by costumer and rate base growth combined with favorable foreign exchange but slightly offset by warmer weather. Normalized operating income from our power business was $16 million in the fourth quarter.

The average realized power price for the quarter was approximately $64 per megawatt hour, which includes pricing from the Northwest projects compared to $65 per megawatt hour for the same period last year. We hedged approximately 57% of Alberta generation in the fourth quarter at an average price of $61 per megawatt hour.

The lower results were driven by Alberta spot power prices, which were significantly lower at approximately $30 per megawatt hour in Q4 2014, compared to $49 per megawatt hour in fourth quarter 2013. We expect Alberta power price to remain soft to 2015 with the 800-megawatt Shepard power plant coming online.

We’ve said it will take some time for the market demand to absorb this new supply. For the full year normalized operating income for all segments was $398 million compared to $386 million in 2013.

Our gas segment processed higher average volumes in 2014 of 1,512 Mmcf per day, compared to 1,361 Mmcf per day in 2013 and benefited from the partial ownership interest in Petrogas and sales of NGLs. The increased earnings were partially offset by curtailments of storage in first quarter 2014 during extreme weather and lower transmission revenue.

Utilities realized increased operating income of $166 million compared to $150 million in 2013 as a result of customer and rate base growth, favorable foreign exchange rates on the U.S. utilities and colder weather in the Eastern part of the U.S.

and Canada. Stronger results year-over-year from the Gas and Utilities segments were partially offset by weaker results from the Alberta power assets.

Looking ahead to 2015, we expect to produce approximately 6,500 barrels per day of C3-plus for this directly exposed frac spread of which approximately 50% is hedged at an average price of approximately $27 per barrel. As David mentioned, we expect results from the gas segment to be comparable to 2014 normalized for our scheduled turnarounds at our Harmattan and Younger.

However, the oil and gas pricing of our – continues to weak and we may see producer activity decline. To-date we have not seen any material decline inside our facilities.

In parallel, we are approximately 55% hedged to $59 per megawatt hour for the first quarter. For full year 2015, we are approximately 25% hedged at an average price of approximately $60 per megawatt hour.

We will continue to hedge exposure to the Alberta power markets throughout 2015 to mitigate the impact of the weaker pricing environment. Let me now provide an update on some of our projects under development.

As David mentioned, our team is working hard to bring McLymont Creek online by midyear. Excavation of the power tunnel is complete and installation of turbines, intake structure and weir are well underway.

There is potential of higher cost at McLymont related to the road and intake construction as a result of increased complexity due to rock structures. We do not expect the higher cost of any material impact of the overall project.

At Blythe in California, we continue to work on the opportunity to double the size of the existing facility. We commenced preliminary engineering of the Blythe II project and have begun discussions with major equipment suppliers.

The formal RFP from the Southern California Public Power Authority is expected in the March, April timeframe. The Imperial Irrigation District, a member of the Southern California Public Power Authority is expected to use its own RFP in late Q1 to early Q2 2015.

These RFPs are for the replacement of retiring coal plants or for offtake agreements. RFPs from San Diego Gas and Electric and Southern California Edison aren’t expect until sometime in 2016 as those utilities work through the new clean energy standard to determine their requirements.

We continue to look at further opportunities to expand generation capacity in California over the long-term. Construction at our 15-megawatt Harmattan facility is in the commissioning phase with generation expected to start by the end of Q1.

We also continue press forward on our regional LNG business. In 2015, we are focused on completing the first facility in Dawson Creek.

We commenced construction facility in fourth quarter of 2014. Permitting, engineering work and preliminary groundwork is underway and purchase orders for the major equipment were completed.

On our Townsend project together with Painted Pony, we’ve revised the timing of the Townsend facility to mid 2016. The shift in timing will allow us to take advantage of potential cost savings, given the current economic environment, and still beyond time to meet Painted Pony’s production volumes.

Detailed engineering along with regulatory and permitting efforts have commenced, the ordering of long-lead equipment items is also underway. Finally, we’re working on increasing our LPG capabilities of the U.S.

West Coast at our Ferndale facility. We continue to target approximately 30,000 barrels per day.

We have already converted one of the two tanks to propane use and now have the ability to ship both butane and propane from Ferndale. That concludes my prepared remarks.

I’ll now pass the call over to Debbie.

Thank you David and good morning everyone. In the fourth quarter of 2014, we reported normalized earnings of $48 million, or $0.36 per share, compared to $60 million, or $0.49 per share, in fourth quarter 2013.

Normalized business operating income reported was $114 million, compared to $124 million. And the corporate segment reported normalized operating loss of $9 million, compared to $12 million in fourth quarter 2013.

Normalized EBITDA for the fourth quarter 2014 was $155 million and on a normalized funds from operations was $156 million, or $1.17 per share. For the full-year normalized net income was $165 million, or $1.30 per share, compared to $176 million, or $1.51 per share, in 2013.

As David said, normalized EBITDA and funds from operations were record levels at $546 million and $472 million respectively on a full-year basis. Our payout as a percentage of normalized FFO for 2014 was at the lower end of our range at 45%.

Interest expense for fourth quarter 2014 was $35 million and $111 million for the full-year. This is higher than the same periods in 2013 as a result of higher average debt balances, lower capitalized interest and a slight increase in average borrowing rates.

For 2015, we expect higher interest costs related to lower capitalized interest from assets moving into service. We also expect non-cash charges in 2015 related to the Volcano and Forrest Kerr projects to be approximately $6 million per quarter in 2015.

In fourth quarter 2014, we reported an income tax recovery of $5 million, compared to an income tax expense of $15 million in same quarter last year. For the full-year, we reported income tax expense of $19 million, compared to $40 million in 2013.

Income tax decreased due to the lower taxable earnings in the year, driven by the provisions taken for the long-lived assets and tax on the capital gains realized in 2013. On a normalized basis, our effective tax rate for the full-year 2014 was 19%, similar to 2013, and for 2015, we expect it to be approximately 20%.

On a GAAP basis, net income applicable to common shares for fourth quarter 2014 was $10 million or $0.08 per share, compared to $53 million, or $0.44 per share, for fourth quarter 2013. For the quarter GAAP earnings included $70milion pre-tax provision taken for certain GAAP assets.

Of the majority of these gas assets are able to process gas. We are faced with low gas prices, declining producer activity and low to no throughput at some of these facilities in the dry gas area.

On a GAAP basis, net income applicable to common shares for 2014 was $96 million, or $0.75 per share, compared to $182, or $1.56 per share, for 2013. For the year, net income applicable to common shares was normalized for after-tax amounts related to the provisions taken on certain assets, the impacts from the sale of non-core assets, unrealized gains and losses on our risk management contracts, unrealized gains and losses on long-term investments and costs associated with the early redemption of medium-term notes and cost incurred for our energy export projects.

For the quarter and year-ended December 31, 2014, net invested capital was $157 million and $590 million respectively. For the fourth quarter and full year 2014, maintenance CapEx was $5 million and $14 million respectively.

Our balance sheet remains strong with debt-to-total capitalization of 44.9%. Coming into 2015, we had a very strong balance sheet with approximately $420 million in cash and $1.7 billion available from our syndicated credit facility.

We have ample liquidity to take advantage of acquisition opportunities. If they arrive or to fund the $3.5 million of committed and advanced development capital projects over the next five years.

Our average debt maturity is approximately nine 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 financing strategy that supports our business strategy.

Both our credit ratings from DBRS and S&P were reaffirmed in fourth quarter with stable outlook. And with that I will turn the call back to David Cornhill.

Thank you, Debbie. Before turning the call over to the question-and-answer, I want to take this opportunity to thank Dennis Dawson, who announced his retirement earlier this year.

He worked with us for over 17 years and he’s been a major contributor to the company. He will be working with us on a part-time basis until the General Annual Meeting at the end of April and retiring at the end of April.

I want to thank Dennis for his contribution over the years and his friendship. Now, I’ll pass the call on to Jess.

Thank you David. Operator, I’ll now turn the call over to you for question-and-answer.

Thank you. I have a question about your Younger and Harmattan turnaround.

When in the year are they scheduled for? And can you talk a little bit more about how long they'll be down and what the scope of those turnarounds are in the financial impact?

Sure. From a standpoint of Harmattan, Harmattan starts its turnaround on May 10 till end by the end of May and Younger will start on June 6 and end on June 27.

And normal turnarounds, nothing out of the ordinary, just part of our maintenance cycle. And about…

About $12 million…

About $12 million in aggregate between the two from an impacts perspective.

So, is that cost and loss revenues?

Correct.

Yes.

Okay, that's very helpful, thank you. And can you talk a little bit more in this commodity price environment for Douglas Channel, what are the key remaining steps to get to FID later this year?

And is there any risk of scheduled slippages you work through those key gating factors?

What we’ll be working through for the balance of the year is the environmental permitting for the Foreshore facility, continuing with the engineering effort on the barge. And right now we don’t see any significant hurdle that will lead us to believe that we think are scheduled to slip to be in a position for FID by the end of 2015.

Okay that's helpful. And then, maybe then just as a follow-on, there is some commentary around the oil and gas prices stay low.

You could see some deferral of projects, which ones, what types of projects in the value chain would you see is potentially being deferred? And how extreme could that be in terms of different areas, I guess of the basin as well?

Really none as it relates to the projects. It’s in the queue with respect to AltaGas.

Okay, that's helpful. Thank you.

Thank you. Good morning.

Good morning.

Just a first question maybe for David Harris. I didn't hear all of the RFPs you highlighted, but can you give us any color on the two RFPs in 2015 for power in California in terms of size and/or preferred technology.

And then maybe just as another piece of that question is are you targeting these RFPs with an expansion Blythe or the re-powering of the facilities you've recently acquired?

No, these RFPs would be targeted with the expansion of Blythe. The two that I talked about was Southern California Public Power authority will be coming out with RFP some time in March and April and then the Imperial Irrigation District, which is also a member of Southern California Public Power authority will be coming out with a separate one themselves.

So both of those will be target for Blythe and we would expect a megawatt generation and maybe somewhere 500 megawatts to 1000 megawatts. We’ll know for certain once they come out, but probably somewhere in that range, maybe even a little larger depending on what they believe their decommissioning program may look like from a coal based assets.

Perfect, thank you. And then my second question is just maybe a bit bigger picture [indiscernible] some of your outlook.

Can you provide me context around your expectation for growing demand for processing structure in the Montney in terms of quantity and timing given our environment.

I don’t know how clear my crystal ball is at this point. We clearly see the towns in the region as a very active position and can see – are in discussions on multiple expansions in that region to or capacity.

I think the timeline is a little cloudy at this point. You can give me a commodity forecast that they can think on, but clearly the interesting is to be ready for the area and in terms of – we could see doubling or tripping types of volumes in the towns in area, gives you a feel for what we're seeing there, timelines probably 18, 19 is realistic at this point.

But it’s a little hard with the dramatic change in commodity price for producers to actually get their feet under them right now. So they’re still moving forward, but they don’t know the shape of the commodity currencies to be [ph] or a lot running at current prices.

Got it, thank you for that. And then maybe just one question, on the – in your outlook for 2015, you're saying, flat gas segment earnings provided recovery in frac spreads in later half of 2015.

And I was just wondering what kind of recovery in NGL fracs spread that you're expecting?

[Indiscernible] We were working for that target. I think the other thing clearly is that we think there is a – it’s a very attractive environment to put some money to work in the gas side of the business and other parts of our business and clearly we got the balance sheet to put those assets to work.

And so that’s also part of driving flat if commodity prices stay low at this level and with the turnarounds that we’re talking about.

Okay, thank you. I’ll get back in the queue.

Thank you. Good morning, everybody.

Maybe just to come back to two things that we’ve touched on, but the first in Dawson and I just want to make sure I’m understanding. So the delay or the reset in the timeframe was that something where you all were just taking stock of the activity levels in the side to push out six months?

Or was that a request that come from your partner? I just want to make sure I understand the timeframe change there and whether could be up for additional slippage in the future depending on what commodities prices do here?

I will take and then David will correct me that – it was a joint decision. 2015 target would have been very slow from our timeline and it would have resulted in additional cost.

So we were looking to push that timeline out. As well the producer is running through their cash flow models, their bank facilities and capabilities.

So what we want to do is optimize the timeline, lower the cost and work through with the producer. We don’t see significant delay from mid-year going forward.

There are some other parts to the equation in terms of takeaway capacities and things like that which we don’t control. But we feel pretty comfortable and working with Painted Pony that mid 2016 is a realistic target to have the plant ready for the gas year which is November of 2016.

Okay, thank you. That’s a very helpful color, David thank you.

Maybe just going down to California and Blythe. And David or Harris, I’d always sort of view the Blythe II is really kind of going after the [indiscernible] RFP and I’m just curious as you guys see what I guess is always an evolving landscape.

Was the extra - the Public Power Authority of the Imperial Irrigation is – was that something you’re always going after or is that just kind of feel the void perhaps as so called that pushed out a year and so in sense you’ve got now two bites of the apple.

Well, it was always in the mix.

Okay.

It was certainly – we looked at both San Diego Gas & Electric, Southern California Edison and the other two is part of SCPPA as being a potential candidates to help us expand with Blythe. So that was always there.

And as the landscape always does change, no matter what environment you're in, I think as Southern California Edison and San Diego Gas & Electric digest what the new renewable portfolio means going from the 30% to 50% range, just cause them to push out their RFPs. So, we still are in good shape and certainly gives a second bite of apple naturally as part of the process.

Okay I appreciate that. And then last question, if I could, this is just a clarification.

Debbie, you had mentioned in your prepared commentary, and I just couldn't scribble fast enough, something to the extent of – in the power business I think $6 million per quarter of non-cash charges in 2015, and I didn't catch what that was relating to?

It’s related to Forrest Kerr and Volcano, Carl.

Just in the normal…

Yes.

Normal course of OpEx or…

Yes, yes it’s amortization and other non-cash charges related to the assets.

Understood, I appreciate that. Thank you guys.

Good morning, everyone. Maybe just one quick clarification on the California RFPs would you look to potentially to Blythe II and Blythe III concurrently?

That is a potential, it’s a little too early to tell, it just depends on how the RFPs and the timing of them and the landscape of those, but we’ve certainly positioned ourselves that we could do that, if we saw the opportunity.

Okay, that’s good. So the Irrigation District would also be an additional 500 megawatt to 1000 megawatts?

Yes, we think – and they both will come out in those ranges, it may move a little bit and obviously we’ll be able to throw it that on while we get to the April call because they should be out by then.

Okay, it’s good to hear. And then maybe just on your gas side, strong volume growth year-over-year, and I realize that a significant portion of your volumes will be contracted.

However, if you see gas and NGL stay where they are right now. What potential downside you think you can have on your volumes maybe 12 months?

In key areas we’re seeing fairly firm in key areas where our producers Gordondale area, Blair Creek and things like that. So we don’t see a lot there.

We would see some general erosion activity levels as declines happen. We don’t see significant at this point.

And it is hard to say what kind of cash flow that producers drilling activity. But for 2015, we don’t see significant declines.

All right. That’s great.

Thank you.

Hi, good morning. Looks like you have the most of my questions.

But I just wanted to maybe David Harris could talk about the strategic relevance of the newly acquired California plants to the Blythe expansion.

I think they positioned us well for – maybe continued participation in RFPs in those specific areas. But even more importantly, they certainly lend themselves quite licensee [ph] for repowering and expansion.

So that’s how we see the fit right now. And certainly gives us a good offset to the Alberta power market as well.

Okay. When you look at the capability of those sites and the transmission of it stands today, what order of magnitude are you – as possible in terms of expansion opportunity?

Well, for the existing it could replacing kind and with a little bit of pushup in megawatt output, but depending on the size and scale of what RFPs may come down the line. You certainly not limited, you certainly always have the opportunity upgrade existing transmission.

And so I would use 30 megawatts to 45 megawatts maybe as much as 60 megawatts from an expansion capability to what we have currently existing there today, in aggregate.

Okay. And then, I just wondered if you can comment a little bit on the proposal by the Federal government for accelerated depreciation for LNG.

The impact that it have on FID not only for Douglas Channel but also for Triton and then maybe you could address the same question on the regional LNG side?

It is clearly helpful. But clearly, it is not a game changer from a decision perspective, anything that helps is positive and that’s clearly does help, but it is not a critical decision factor.

Okay. That’s all I had, but just wanted to say congratulation to Dennis.

Yes. Thank you.

Hi, good morning, thank you. On the power business in the outlook section, there’s a reference to higher contribution from U.S.

power due to continued growth and development opportunities. Obviously, there is the Blythe opportunity which is a great opportunity, but it’s not a 2015 thing.

So I’m just wondering what that reference was, was it to potential for further short-term acquisitions in the U.S.?

No, it’s a result of the opportunities, as a result of the Verizon acquisition.

Okay, I got it. But you guys don’t – okay, okay the purchase price of those assets, sorry, I can't recall that was disclosed.

No, was not disclosed.

Okay, but obviously not really material done?

No.

Other comment in power I was just curious you said AltaGas expects to continue to hedge its exposure throughout 2015. Would you continue to hedge at the forward price in 2015 or will you just expecting prices to pick up and to hedge into that?

No, we wouldn’t hedge at the forward price that’s more towards the point of as opportunities would present itself with volatility. We would pick our positions and take advantage of that from a hedge perspective.

Okay. Yes, that that makes more sense.

Final question on utility, in terms of degree days was it actually colder than normal in Michigan during the quarter?

No, you’re talking for Q4?

Yes.

No, just slightly below average.

Just slightly below average?

Yes.

Slightly warmer.

Yes, just slightly warmer. Q4 weather wasn’t a big impact, the weather – the colder weather was on a full year basis, Matthew.

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

Good morning. Just on the growth capital plan, you talked about being able to finance that out of free cash flow, the lot – all the liquidity you have and then the drip, I guess specifically.

You see that all internal not having to go out for external funding, specifically common equity. So I guess, when you look at your Montney outlook and you said that if prices stay down, you might see delays, but you've got the ability to redeploy in the power and utilities.

So it sounds a bit like are you – with those power and utility opportunities are you rationing capital right now?

No, we haven’t rationing capital at all at this point. We do have a minimum return type rationing that goes on but not – there are not projects that we want to move forward with – not moving forward at this time.

Got it. So the statement more about redeploying capitals just maybe you’d kind of spend a little bit more time focusing on finding new initiatives.

There's not initiatives out there that you're just deciding to forgo at this time?

Yes.

Okay. Just going into the gas business, you've talked about on the frac spread site, 6,500 barrels a day exposed to the frac spread for 2015 and that's down from 2014.

So I'm just wondering have you been able to migrate some of those volumes to either fee-for-service or some other type of contract or is that just a function of you're seeing lower volumes through the facilities?

We’re doing some targeted reinjections.

Okay. And, I guess just the last question here.

You had mentioned you expect increased volumes from Sundance. Is that related to you guys taking control of the dispatch on your portion or is there some thing else going on?

It’s more of turning around and taking advantage of the availability in the asset. If it’s available we would like push more megawatts out of it.

So, I recall that and previously you were not controlling the dispatch. Are you guys now controlling it as you go forward?

No, not, but we’re working pretty collaborative with TransCanada.

Perfect. Okay, great.

Thank you very much.

Good morning and thank you. Dennis, best wishes to you in your retirement.

Debbie, you’ve noted that taxes will increase in 2015. Would you mind giving a little bit more detail - taxes to – they took less than 10% of pre.

Do you think they will take more or less than 15% of pre-tax?

No, no. Really the higher taxes is fairly, fairly small.

We do look at overall net income subject to tax and that’s going to be slightly higher. But the raise is going to be around at 19% to 20% that we’ve seen in the last couple of years.

Overall. Not just cash?

No.

Okay, thank you. Maybe some one would mind giving us a bit of break down on your…

Sure?

$600 million in capital spending you have planned in 2015?

Okay. I will do that If you just.

Of course.

Give me a minute here to find my little – so of that between $550 million and $650 million at the lower end of the range about 30% of that is utility, 45% will be gas and 25% is power. And if we push up to the higher end of range right now it’s probably going to happen in on the gas side is how we get to that $550 million to $650 million range.

So the 45% will obviously bump up if we get to the higher end of the range.

Thank you, Debbie.

Okay.

It appears you’ve got lower liquids volumes exposed to frac spread than last year. I mean that you right on this wrong.

But if so what’s the cause of the lower volumes?

Targeted reinjection at certain facilities at certain times based on price.

Thank you, David. Utilities normalized operating income grew by 11% last year.

So, it’s fair to assume similar growth this year?

Some of that – you said normalized?

I believe normalized operating?

The normalized for weather, yes. So some of that would have been weather, Steven.

And but based asset growth and customer growth – I would say would be – similar and that some across all utilities is about 3%.

Which would give you a better than 3% growth in income?

Correct, yes.

Thank you, if I may – there is a couple more. Are you seeing overseas propane or butane buyers, trade flexibility for security supply and in other word do you getting buyers to find take-or-pay contracts at Ferndale.

We are having active discussions there our long-term opportunities there, but we have not yet – we don’t feel comfortable yet to going to that – we want some more operating history at this facility and flexibility. So we are not going to pursue at this point through Petrogas.

Thank you, David. Debbie, one last question, what are the rating agency saying about the amount of preferred to AltaGas might issue, while maintaining its credit rating?

Not anything knew and what we said in their report, Steven. We have on DBRS, I think we’ve got some room and then on S&P they give us 50% treatment of all prefers that we issue.

Well, thank you all for your patience, this morning.

Thank you

Thank you. The press release, refers to net income normalized for certain non-recurring unusual or extraordinary events and while I don’t expect to have this answer right now.

I’m wondering weather you could provide for each of these items for 2014 and 2013 the breakdown?

I have it here, Winfried but I’m not sure if you want to do this on call. But I’m happy to give it to you, right now.

Or we can – why don’t we do it after?

Yes, we’ll do it after. Thank you.

Okay. Thanks.

Thank you, operator. That concludes AltaGas’ Q4 and full year 2014 conference call.

As always we are available after the call for any follow-up questions. Thank you.