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Executives

Jess Nieukerk – Director, Finance and Communications

David Cornhill – Chairman and CEO

Debbie Stein – VP, General Counsel and Corporate Secretary

David Harris – COO

Analysts

Linda Ezergailis – TD Securities

Carl Kirst – BMO Capital Markets

Robert Catellier – Macquarie

Robert Kwan – RBC Capital Markets

David Noseworthy – CIBC

Steven Paget – FirstEnergy

Altagas Ltd. (OTCPK:ATGFF) Q2 2013 Earnings Call August 1, 2013 11:00 AM ET

Operator

Good morning, ladies and gentlemen, and welcome to the AltaGas Limited Conference Call. I would now like to turn the meeting over to Mr. Jess Nieukerk, Director of Finance and Communications. Please go ahead, Mr. Nieukerk.

Jess Nieukerk

Thank you. Good morning everyone. Welcome to AltaGas’s second quarter 2013 conference call. Speaking today are David Cornhill, Chairman and Chief Executive Officer, Debbie Stein, Senior Vice President, Finance and Chief Financial Officer, and David Harris, President, Power and Gas. 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.

David Cornhill

Thank you, Jess. Good morning everyone. I’m pleased to report we are continuing to deliver strong growth. This morning we reported a 150% increase in normalized earnings per share. We achieved $0.30 per share compared to $0.12 per share in the second quarter of 2012. Our normalized EBITDA for the second quarter 2013 more than doubled to $106.2 million compared to $51.7 million in the same quarter 2012. Normalized funds from operations for the second quarter 2013 were $83.1 million or $0.71 per share compared to $40.7 million or $0.45 per share in the second quarter 2012.

Our businesses are performing well and delivered over $200 million of normalized funds from operations in the first half of 2013. When we compare the trailing 12 months ending second quarter 2013 to the trailing 12 months ending second quarter 2012 for normalized income per share and FFP per share we are seeing growth rates of over 30% for both. Based on the corporate performance and a strong outlook the Board decided to increase the dividend by $0.25 per share per month. With this dividend increase we have increased dividends by 6.25% this year. In the second quarter the power and utilities businesses performed extremely well, however the gas business faced some challenges. The gas business successfully met those challenges and delivered a good quarter. Two compressors on our co-streaming section of the Harmattan plant had to be taken off-line for major repairs. This resulted in a significant reduction and processing capacity.

As a result of the reduced processing capacity we reduced the capital fee charged to our customer. Our gas team did an outstanding job in both compressors online before the end of June. We expect co-streaming section of Harmattan will reach full capacity in Q3. In the second quarter we saw low frac spreads with spot prices in the $18 range. Frac spreads have increased significantly over the last few weeks. The Gas group also faced increased operating costs which were primarily a result of increased power prices. This increase was more than offset by the performance of our power business. We expect the gas business to have a much stronger second half.

On our Northwest Hydro projects we made significant progress or as clearly remains on track to be mechanically complete by the end of 2013 and online by mid-2014. McLymont and Volcano remain on track to be online mid-2015. All three projects remain ahead of schedule and on budget. David Harris will provide further comments on them. We continue to see many organic growth opportunities in all our businesses. Combined with our energy export businesses we’re working hard to deliver on our next leg of growth. On the energy export initiatives we continue to make excellent progress. We are having active discussions with markets as well as supplies for both our LPG and LNG projects.

I will now highlight some of the progress we are making. Our PNG expansion is moving forward. During the quarter we began discussions with the First Nations on our pipeline corridor. We have submitted our project description to the BC Environmental Assessment Offices. We have received acknowledgement of the project from them and are now starting the environmental assessment process leading to application, evaluation and approval stages. We have also signed two transportation reservation agreements for a combined capacity of 520 million cubic feet a day. Active discussions are underway with several parties on securing additional transportation capacity. This support allows us to move ahead with the expansion through to the final investment decision. We expect to make a final decision in 2014 pending regulatory approval and agreements with First Nations.

For our LNG export business we currently are preparing preliminary engineering design and construction for the liquefaction facilities. This work is expected to be completed by the end of 2013. Our proposed LNG export business could potentially begin as early as 2017 subject to First Nations consultation, regulatory approvals, and permitting. We are also doing a feasibility study and preliminary engineering design and site scoping for our LPG export business. Again pending consultations with First Nations’ regulatory approval and permitting this is on track to potentially begin as early as 2016. We are having active discussions in the supply area and off-take area both for LNG and LPG and expect to be able to provide more information later this year.

We delivered strong earnings over the first half of 2013 and are well positioned to deliver on our goal of double-digit growth in earnings. We expect this to continue over the next few years with the projects and growth we already have in the pipeline. We remain committed to our strategy of increasing stable cash flows from long-lived assets. This supports both dividend growth and capital growth. Before I pass the call on to Debbie I’d like to update you on an organizational change. I’m very pleased to announce that David Harris has been promoted to Chief Operating Officer. David will be responsible for the day-to-day operations of all our assets as well as project execution across all the businesses. David brings a wealth of experience which will allow us to drive operational excellence across our asset fleet. His experience will also allow us to capture the tremendous opportunities we have. The growth we’ve seen over the past 24 months has been second to none. With this growth we have opportunities to streamline our operation and increased efficiencies. With David’s leadership we know this will materialize.

I will now pass the call on to Debbie.

Debbie Stein

Thank you, David, and good morning everyone. This morning we reported normalized net income applicable to common shares in the second quarter 2013 of $35.5 million or $0.30 per share compared to $10.4 million or $0.12 per share for the same quarter 2012. On a GAAP basis net income applicable to common shares for second quarter 2013 was $35.9 million or $0.31 per share compared to $25.8 million or $0.29 per share for the second quarter 2012. For the six months ended June 30, 2013 normalized net income per share was $91.1 million or $0.82 per share compared to $50.6 million or $0.56 per share.

On a GAAP basis net income applicable to common shares for the six months ended June 30, 2013 was $85 million or $0.76 per share compared to $67.1 million or $0.75 per share for the same period in 2012. Results were driven by strong performance from our three business segments which together reported $73.3 million and operating income in the quarter compared to $38.7 million in the second quarter last year. On a year-to-date basis the three segments reported operating income of $188.6 million compared to $115.2 million for the first six months of last year.

Operating results were driven primarily by higher throughput in the gas segment higher power generated and higher power prices. The addition of the U.S Utilities in August of last year as well as colder weather and rate being grown in our Canadian Utilities. Interest expense was $25.2 million and $49.8 million for the three and six months ended June 30, 2013 respectively. Higher than same periods last year as a result of higher debt balances as we added assets and partially offset by lower interest rates in 2013 compared to 2012.

In second quarter 2013 we reported in income tax recovery of $2.9 million compared to an income tax expense of $8.7 million in same quarter last year. The recovery was due to two adjustments. $2.4 million recovery related resulting from a statutory tax rate change related to dividends paid on preferred shares and $8 million related to an adjustment to the deferred tax liability account.

For the three and six months ended June 30 our net invested capital which is our book addition to capital was $667.7 million and $773.6 million respectively. The majority of which was related to the acquisition of Blythe and the continued construction of the Northwest projects.

For full year 2013 we expect our capital expenditures to be in the range of $1 billion to $1.1 billion. The increases related to the additional capital expenditures of the utilities. Moving forward in our energy export initiatives and our new gas and power assets. Our balance sheet remain strong with debt to total capitalization reported of 54.2%. We had a busy quarter on the financing front. In April we issued a $11.6 million shares for gross proceeds of approximately $405 million and issued two year U.S. Dollar $175 million MTN at LIBOR plus 0.79% and on June 6 we issued our longest tenure and lower interest rate MTN for $300 million and it carries a coupon of 3.57%.

Following upon David’s comment on our dividend increase our payout as a percentage of normalized FFO for the 12 for the trailing 12 months ending June 30 2013 was conservative at 41% at the lower end of our range of 40% to 50%. With the dividend increase announced this morning we expect to remain at the lower end of that range.

Our debt to maturity, our debt maturity remains very manageable and we will continue to balance our long-term and short-term financings as well as floating and fixed rate debt in order to execute the financing strategy that supports our business strategy. We continue to well positioned for long-term earnings cash flow and sustainable dividend growth into the future.

I will now turn the call over to David Harris.

David Harris

Thank you, Debbie and good morning everyone. We are pleased with another strong quarter. The power business more than doubled its operating income compared to Q2 last year benefiting from higher Alberta power prices and the acquisition of Blythe.

In our utility business some field had another solid quarter delivering over $24 million in EBITDA in the first nine months of ownership, this brings the SEMCO ENSTAR EBITDA contribution to approximately $120 million well in line with our full year guidance of a $130 million.

Canadian utilities also reported a higher earnings driven by colder weather and rate base growth. Our gas business had solid results primarily due to increased throughput from our new facilities but it was impacted by lower frac spreads and higher power cost, although the power segment saw the benefit of higher power prices.

As David mentioned our Co-streaming facility operated below capacity due to compressor modifications and low inlet pressure issues experienced by the NGTL system. As a result we prorated our take-or-pay revenues in Q2. The design modifications will allow the compressors to operate effectively across the wider range of inlet pressure conditions we expect to have these issue fully resolved the Co-stream returning to full capacity in Q3.

Our Q2 2013 total extraction volumes increased by over 16,000 barrels per day primarily as a result of higher throughput and higher capacity. We saw high volumes at Younger and the Edmonton extraction plant. Of note as well was low volumes in Q2 2012 of approximately 4300 barrels per day as a result of outages that were downstream from several of our extraction plants.

We had higher throughput at our FGNP facilities in second quarter 2013 averaging 413 Mmcf per day well above the Q2 2012 throughput of 351 Mmcf per day and higher than Q1 this year of 403 Mmcf per day and 377 Mmcf per day in Q4 of 2012. We are beginning to see shinning volumes come back on and continue to have healthy dialog with producers that lead us to believe that volume should continue to improve.

For the second quarter 2013 AltaGas hedged approximately 57% of frac exposed production at an average price of approximately $34 million per barrel. This compares to approximately 80% hedged at approximately $35 per barrels in the same quarter last year. This spot NGL frac spread for Q2 2013 was approximately $18 per barrel compared to approximately $27 per barrel a year ago.

Looking specifically at our Gordondale facility, it continued to operate it’s take a pay level and a utilization of approximately 45% throughput for Q2. Volumes have increased in Q3 and we have seen volumes steadily increased over the past few weeks and we expect them to continue to ramp up throughout the remainder of the year.

In our power segment we saw a significantly higher results primarily due to the higher Alberta power prices in the quarter and the addition of the Blythe Energy Center. Alberta power market was very strong in Q2 averaging a $123 million per megawatt hour compared to $40 million per megawatt hour in Q2 of 2012.

For the second quarter 2013 AltaGas’s Alberta power generation was 67% hedged and an average price of $62 per megawatt hour compared to 74% hedged at approximately $65 per megawatt hour for the same period last year.

Looking at the rest of 2013 as David mentioned. We expect strong results in our gas business is but volumes are continues to increase with Gordondale ramping up and with Co-stream returning to full capacity we expect to recovery our full cost of service revenue for most of the quarter. We are also seeing higher throughput at our Younger facility. We expect to produce approximately 6200 barrels per day of C3 plus that is directly exposed to frac spread of which 80% of hedged at an average price of approximately $30 per barrel before deducting extraction premiums. We have also stated to see spot prices for NGL increase in recent weeks due to strong oil prices.

Let me now turn to the new projects we announced today. We continue to see many opportunities for organic growth. This morning we announced Cogen III another 15 megawatt project at Harmattan which will bring our total cogeneration there to 45 megawatts. This project provides strong returns and capitalizes on synergies at the Harmattan facility and will also allow us to take further advantage of power prices in Alberta.

The total project provides strong returns and capitalized on synergies at the Harmattan facility also allow us to take further advantage of power prices in Alberta. Total project is expected to cost approximately $40 million and be in service in Q4 2014. We also announced this morning the expansion of our Cold Lake natural gas transmission system. The expansion is to provide more natural gas which we use for steam generation of the two SAG heavy oil projects in the region.

We have long-term take-or-pay agreements in place for both projects. The total cost is approximately $17 million and the expansion is instructed to be in service in late 2014. Let me conclude today with an update on our Northwest projects. Construction on Forrest Kerr continues ahead of schedule and on budget.

The total project and it is now approximately 84% complete. The intake structure is complete and work continues as planned within the powerhouse. Turbine generator installation is progressing eight to nine draft tubes are in place and the final concrete pour sets have started on unit nine.

We continue to expect the plant to be mechanically complete by the end of 2013 and synchronizing to the grid by May 2014 once the Northwest Transmission line is complete. We continue to monitor the progress of the NTL and it remains on track for COD in May 2014. On our McLymont project construction activities continue to ramp up at a steady pace.

Construction of the intake access road is approximately 55% complete and excavation of the power tunnel was 15% complete with 480 meters out of the total 2800 meter length excavated. At Volcano excavation of the intake site and diversion have been completed and the installation of the weer end beds has commenced.

The Volcano Creek powerhouse foundation is complete and the concrete pour for the powerhouse walls and the turbine foundations we completed within the next 90 days. Excavation of the penstock right of way has commenced and clearing of the transmission line right of way has been completed.

McLymont, Volcano expected to be in service in mid-2015. That concludes my prepared remarks. I’ll now pass the call back to Jess.

Jess Nieukerk

Thank you, David. Operator we’ll now move into the Q&A please.

Question-and-Answer Session

Operator

Thank you, Mr. Nieukerk (Operator Instructions) The first question is from comes from Linda Ezergailis with TD Securities. Your line is now open. Please go ahead.

Linda Ezergailis – TD Securities

Thank you. Congratulations on a strong quarter and congratulations on your promotion David.

David Cornhill

Thank you.

Linda Ezergailis – TD Securities

With respect to the PNG expansion can you give us a sense of approximate cost and how you might expect the TRA returns to be structured? Would it be a BCUC return, plus some sort of risk premium and what that might look like? And how – when might you expect these TRAs to firm up? Is it solely conditional on the LNG projects being sanctioned and regulatory approval or are there some other contingencies like other company Board approval or something like that?

David Cornhill

I’ll handle some of it. I think there is seven or eight questions in there. We think it will be fall under general regulation from the BCUC and the rate yet to be determined on that. With respect to the TRAs, we’re going forward to develop preliminary tolling information for the customers and once that goes through, we’ll expect it to have all capital required to make a final decision and signing on a long-term transportation agreement. So, that will firm up all over the remaining quarters of this year and so that will be a final commitment of – these commitments fund all the cost to get a final decision and execution of long-term transportation agreement, which would be another board decision for us as well as the LNG customers and other customers. I’m not sure if I answered everything.

Linda Ezergailis – TD Securities

And what is the approximate cost potentially?

David Cornhill

We’re still looking at about $1.5 billion roughly plus or that’s plus or minus and fair percentage at this point.

Linda Ezergailis – TD Securities

Okay and the big spend on that would start in 2015 not sure?

David Cornhill

1205 more in 2016, 2017. We’re thinking somewhere between over 18 months construction time.

Linda Ezergailis – TD Securities

Great. Thank you.

Operator

Thank you. The next question is from Carl Kirst with BMO Capital Markets. Please go ahead.

Carl Kirst – BMO Capital Markets

Thanks, thanks. Good morning, everybody and congratulations as well, both for the quarter and to you David. With respect to maybe just kind of following Linda’s question on PNG really sort of two questions. If you guys were to make a positive FID with it admit to but somehow Douglas Channel I mean this is the one train Douglas Channel enough to sort of underwrite this 520 or is the potential if one goes forward and one doesn’t that that would be a gaiting factor to the project?

David Cornhill

It would at this point complicated, but we’ve – we’re under discussion with a number of additional customers that want additional capacity on the line. We have just not signed Transportation Reservation Agreement with those yet. We actually want to firm up the first two before we continue those discussions. So, at this point we’ve extending queue of interest for additional capacity. So, we think we’re in good shape too to fully fill the pipeline even if one of the projects didn’t go ahead.

Carl Kirst – BMO Capital Markets

Excellent. And maybe just sort of an extended question then and Debbie, this is probably more for you from a risk-management standpoint. As you eventually go through the regulatory process and recognizing I guess what you might call some unique risks of putting this into rate base but outside of sort of the residential load. How does that get managed from a credit profile in the future?

Debbie Stein

Very carefully.

Carl Kirst – BMO Capital Markets

Okay. Well said. Yeah. I mean, is there – I mean is Idemitsu perhaps I mean, I don’t know can they sleeve their credit rating to the JV or do they take the long-term risk or how should we think about that?

Debbie Stein

Well, how you should think about it is our working assumption right now is that this investment goes into a regulated asset. And so, when we look at regulated returns, we look at the risk that is appropriate for those regulated returns. And so, what we’re, what we’ve done and what we’ll continue to do is require fairly stringent credit requirements to support those long-term contracts. David has often said, we can’t afford a flare at the end of that pipeline. So, we need to make sure that the counterparties that are committed to these long-term transportation agreements have the credit worthiness that we would need to support a regulated return. And we’re protecting both the ratepayers and the shareholders at the same time.

Carl Kirst – BMO Capital Markets

Excellent. And then last question if I could and I’ll chalk this up to the brilliance of David Harris buying Blythe right before SONGS announced retirement. What do you see as far as the potential or when do you actually start, I guess negotiations for either extending Blythe or in fact expanding Blythe, given what So Cal’s needs may be?

Unidentified Company Speaker

We’ve actually started to have about those dialogs internally and to a certain extent externally that started pretty much right after the close right. And besides just SONGS you are seeing a lot of other activity within California with shrinking megawatt based because of environmental regulation and plants just reaching natural retirement cycle – on the lifecycle.

Carl Kirst – BMO Capital Markets

David, do you think those talks kind of take like two years to play out or is this something that the path is fairly straightforward that the long-term future of those assets will probably be determined sooner rather than later? Is there any color on timing you can give?

David Cornhill

That’s a little bit of a difficult collective picture to paint right now. I would – I would suspect that California is trying to get the feet underneath them a little bit right with the acceleration of SONGS being shut down. There is also some other rumblings out there in the press about Diablo Canyon. So, I would think, we should see something a little bit faster than what we anticipated. I wouldn’t handicap it right now or within two years but I would definitely say, we’ll see it a lot sooner than the 7 yeas, which is left on the contract. And then, we can revisit that once we’ve a little bit better indication of what’s going on as we probably get into the early part of 2014.

Carl Kirst – BMO Capital Markets

Fair enough; those were my questions. Thanks, guys.

Operator

Thank you. The next question is from Robert Catellier with Macquarie. Please go ahead. Please go ahead.

Robert Catellier – Macquarie

Congratulations David Harris on the new title. And my question here is on the dividend. I’m curious as to what incremental comfort level, what led you to that incremental comfort level to go with a second distribution increase this year?

David Cornhill

Well the company has performed very well. Projects are continuing on stream and quite frankly my board thought I was a little conservative in the first quarter and with discussion they thought this has been a more appropriate level. So, it was just strength of the performance. We just got through our planning meeting. This is more traditional time we would dividend so they decided we should right size the dividend to three quarters (a percent) increase for the year versus the half cent that we made in the first quarter. So, that was the dialog and we just saw very strong performance in the company and with our Northwest projects continuing on stream the NTL looking at May next year and adding that type of capacity we just, the board thought I was being a little too conservative.

Robert Catellier – Macquarie

Okay. Then on PNG, I wondered if you would talk a little bit about the backstopping agreements and the risk. Presumably the counterparties on the TRA including AltaGas and Idemitsu are taking their proportionate share of the backstopping for the development costs. So, I wonder what amount of capital that means to AltaGas when you net everything out.

David Cornhill

It’s little over $10 million and with respect to that, we’ll have LC commitments for all that capital from a PNG perspective so it was secured by LC, so there will be no credit risk to the utility.

Robert Catellier – Macquarie

Okay. And then there has been a change in your agreement with PNG. You have given up your reversion rights to I guess the right of way for an extra $18 million. So, I wondered if you could just talk a little bit about that and what led you to come to the conclusion that you could afford to give up the reversion rights to that asset and also the accounting treatment on that?

David Cornhill

I’ll speak to the first part and Debbie can speak to the second. Short answer is Chevron, that the group has changed dramatically with the Chevron we had capability certainly are going forward long-term and we want strong relationships with them as we go forward and it’s just made sense we viewed it as a low probability and low value to have those reversion rights of Chevron could not make a LNG project we just felt that it was in a high value and working with them a lot more sense. So, that was the reason our projects gone forward well from an expansion perspective so we saw decreasing value to our company for with the announcement with the announcement that Chevron was taking a lead in the project.

Robert Catellier – Macquarie

Yeah and the accounting?

Debbie Stein

So on the accounting side, it will get recorded as a – gain so it will show up in operating income in Q3 of course subject to the approval of the BCUC. And, from a tax perspective it will actually get tax as a capital gain.

Robert Catellier – Macquarie

Okay, and so obviously that’s noted off your capital requirements for the year?

Debbie Stein

Sorry?

Robert Catellier – Macquarie

You’ve already netted your budget for CapEx for this amount I assume?

Debbie Stein

Yes.

Robert Catellier – Macquarie

Yeah. And then finally I’m just curious to see how much more runway you think you have both in building out additional Cogen capacity at the Harmattan Co-stream as well as potential additional investments to serve Cold Lake, SAG D producers?

David Harris

Robin, I’ll answer that on Cogen side, after Cogen III that will probably hit for the base facility. If we do anything else on the generation or peaking it will be outside of the (inaudible) Harmattan and as far as Cold Lake we like what we see with the announcement made we’ve got a good solid project here underpinned mostly with Pengrowth right now. So we like what we see with the expansion opportunities at SAG D.

Robert Catellier – Macquarie

Thank you very much.

Operator

Thank you. The next question is from Robert Kwan with RBC Capital Markets. Please go ahead.

Robert Kwan – RBC Capital Markets

Good morning. I just wanted to follow up first on the dividend question that Robert Catellier asked. David, you talked about just being conservative and this being the normal timing. I just wanted to make sure that you’re still kind of looking at more annual increases versus moving to smaller increases every quarter?

David Cornhill

That’s my intention, but Board purview on dividends so that would be my recommendation. And as Debbie pointed out you could see the dividends now approaching the low end of our target range and from what I’ve seen lower than a number of the large pipeline FFO payouts as well. So, yeah we expect it to be an annual announcement, but the Board has a right to review at any time.

Robert Kwan – RBC Capital Markets

Was there discussion at the Board level of moving to just an every quarter type increase?

David Cornhill

No.

Robert Kwan – RBC Capital Markets

Okay. Just the other questions I have are on the Gas business. You mentioned, with respect to Harmattan Co-stream that you’ll move to full cost of service in mid-August and that you reduced the capital fee while you were doing some of the work. Was that contractual or was that just your choice with respect to maintaining the NOVA relationship?

David Harris

It was a little bit of both, couple of things working in dynamic there we did some of the issues with two of our compressors as David said and we’ve seen some variations in pressure so we made the decision to turn around and make some improvements to those compressors to give us a lot more robustness across of on operating range. And then in combination with that there has been issues on the NGTL side with pressure coming from TransCanada for a number of different reasons. So, in the sake of keeping a healthy relationship with NOVA which we have a great relationship with both parties agreed that was a right thing to do and then move on and we’re well added towards on that now and we should be completely added towards out of that as David said here early in the first part of our Q3.

Robert Kwan – RBC Capital Markets

And that makes sense. Are you able to quantify what the reduction in cash flow was for the quarter, based on what you did at Harmattan?

David Harris

Well I can give it on our production standpoint it probably heard us out of the 250 a day that we would design forward took it down to about 160 on a commercial take-or-pay basis. It was probably around…

David Cornhill

Several million.

David Harris

Yeah.

Debbie Stein

About $3.

David Harris

About $3 million to $3.5 million I think.

Debbie Stein

Yeah.

Robert Kwan – RBC Capital Markets

Okay. And then just on Gordondale; so you mentioned you’re operating 40% capacity and really at the take-or-pay level and then you mentioned that volumes have improved. Are you still then within the take-or-pay contract or are these increased volumes actually expected to improve cash flow?

David Harris

No, we’re actually above the take-or-pay contract right now and we’re on an even a slightly steeper trajectory than we thought as far as bringing volumes on. So, we’re cautiously optimistic that we’ll continue through the balance of the year and we have no reason to believe it, it won’t so we like what we’re seeing from can now bring an additional volumes on.

Robert Kwan – RBC Capital Markets

Okay. So I guess just for the Gas business overall, given that Op income was fairly flat to last year despite Co-Stream and Gordondale. It sounds like it’s really just– as you get the increased volumes, that’s really going to hit the bottom line and you’ve got that guidance for a much stronger second half. Are those the reasons? Is there anything else going on that we should be thinking about?

David Cornhill

Gordondale, has most of the cost effects so as volume grew up (inaudible) increases significantly. The other is frac spread, year-over-year was down and we’re seeing a stronger performance in the second half and we saw in Q2.

Robert Kwan – RBC Capital Markets

Okay. And just with the lower volumes moving through Empress; is that expected to drag on things or?

David Cornhill

Not material to us.

Robert Kwan – RBC Capital Markets

Okay, that’s great. Thank you very much.

Operator

Thank you. The next question is from David Noseworthy with CIBC. Please go ahead.

David Noseworthy – CIBC

Thank you. Let me add my congratulations on the great quarter and your new appointment, David Harris. So, perhaps I could just start off; Debbie, you gave some detail on the increase in your CapEx guidance. But if I just look at it quarter over quarter, your CapEx guidance gone up on the low end – $50 million on the high end $200 million you announced about $60 million between Harmattan and Cold Lake. The remaining $100 million to $150 million; can you provide us any granularity on what that’s for?

Debbie Stein

So about 50 to 75 of that is incremental capital the utilities. And then there is the Cogen, did you catch the Cogen III?

David Noseworthy – CIBC

Yeah.

Debbie Stein

Okay. And then there is some incremental capital on the JV, JV side and moving our energy export initiative forward. And I think that pretty much covers that. We are seeing lots of projects in the pipeline and so that’s why I gave you a range, but I would say about 80 to 100 of that aren’t completely pinned down yet, but it at least gives you directionally where we’re going.

David Noseworthy – CIBC

Thank you for that. And then just on the gas volumes; obviously there’s been a little bit of concern recently about the widening AECO-NYMEX differentials and the potential impact on production in Alberta. What’s AltaGas’s perspective on that?

David Harris

We watch it just as close as everybody does, but we’re not really overly concerned at this point we’re also seeing our FGMP volumes if you look that it from Q1 of last year to the end of 2012 there were on a descending track and if you look at Q1 and Q2, I mean obviously because of our new assets volumes have picked up but also within the base business we’ve seen shut-ins return. So gas pricing is up a little bit as well so that’s helped out tremendously it’s up about I think almost $0.45, $0.50 on average come fit to where we were last year. So, right now we have it on the radar screen, but are not worrying about it being overly impactful to us as the year pins out.

David Noseworthy – CIBC

Thanks for that color. And then just one last question; when I look at your frac spreads average spot price and I compare that to either an Edmonton posted price or Mont Belvieu posted price; the kind of relative ratio has diverged from what we’ve seen historically. Can you give any context of why that’s happening?

David Harris

Definite. Well I guess one thing that we potentially lead to that is I mean we’ve spent some to win the gas is moved around Canada there is in the recent TRAs associated with TransCanada you see actually more gas being put in the storage on the Alberta side and.

David Cornhill

The other is Edmonton is becoming less reliable on most of our pricing that’s based on Conway and Mont Belvieu with differentials from there. So, we find Edmonton is not a reliable market for any liquids prices. I would say it’s more of the issue with Edmonton than anything else. We moved over the last few years to Mont Belvieu and Conway pricing.

David Noseworthy – CIBC

Okay. So what we’ve seen in terms of almost weaker pricing in the U.S. versus Canada, that would have– we’d see some of that reflect through what you’re seeing on your spot.

David Cornhill

Yeah.

David Noseworthy – CIBC

Okay. Thank you very much. Those were my questions.

Operator

Thank you. The next question is from Steven Paget with FirstEnergy. Please go ahead.

Steven Paget – FirstEnergy

Good morning and thank you. Just with the success at McLymont and Volcano and Forrest Kerr as well, do you see further material opportunities in the BC renewable market?

David Harris

We’re always watching and I think it depends on what happens with LNG growth and commercial and industrial growth but I would certainly think there will be opportunities on our horizon.

Steven Paget – FirstEnergy

What about opportunities for renewable growth in Eastern Canada?

David Harris

We watch Eastern Canada, there is always a number of hurdles with respect to renewables in Eastern Canada especially around the wind side of the business. We haven’t elected to dabble in the renewable market there. It doesn’t mean we won’t down the road but we watch it just like any other market within Canada as it relates to opportunities for renewable generation.

Steven Paget – FirstEnergy

And I’m cheating with a third question. Is there a possibility that you might spin out your renewables into some sort of high-yield vehicle like we’re seeing TransAlta do?

David Cornhill

We’re not contemplating that.

Steven Paget – FirstEnergy

Thank you.

Operator

Thank you. The next question is a follow-up question from Linda Ezergailis with TD Securities. Please go ahead.

Linda Ezergailis – TD Securities

Thank you. With respect to some of the new projects you’ve announced and what you see in the pipeline; can you please provide us maybe with an updated financing plan?

Debbie Stein

So, Linda right now with the projects that we have in the pipeline we’re fully funded. We will look at terming out some debts, there is always the option of doing some preferred as well as we have done in the past. But for all intents and purposes we look at our current capital program is fully funded with no need for any equity or common share equity I should say. If you see us announce any other major acquisitions or major projects then we would look at – we would look at what we need to do on the common share issuance front. But as you well imagine and you’ve heard us say many times we are focused on maintaining our investment grade ratings. So a lot of our financing plan is really underpinned by making sure that that’s not jeopardized.

Linda Ezergailis – TD Securities

Thank you. And is this a five-year plan or one-year plan and how does the PNG expansion announced today reflect in your comments?

Debbie Stein

So, with respect to the large energy export capital initiative when we look at the timing of that capital, right now the assumption is that we will be able to fund that with the free cash flow that we’ll see coming off of the business in the next two to three years, by the time we do bulk of that capital is needed or that cash is needed for that capital we’ll be seeing the Northwest projects come on.

Linda Ezergailis – TD Securities

Great. Thank you.

Debbie Stein

So, our working assumption is until we get further clarity on the timing of the cash flow our long term are five year plan shows that it will be internally funded.

Linda Ezergailis – TD Securities

Okay, great. Thank you.

Debbie Stein

Thanks.

Operator

(Operator Instructions). There are no further questions registered at this time. I’d now like to turn the meeting back over to Mr. Nieukerk.

Jess Nieukerk

Thank you. That concludes AltaGas’s second quarter 2013 conference call. If there are any follow-up questions, please feel free to give me a call. Thank you very much for joining us today.

Operator

Thank you. The conference call has now ended. Please disconnect your lines at this time. Thank you for your participation.

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