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Executives

Jess Nieukerk – Director, Finance and Communications

David W. Cornhill – Chairman and Chief Executive Officer

David Harris – Chief Operating Officer

Deborah S. Stein – Senior Vice President Finance and Chief Financial Officer

Analysts

Linda Ezergailis – TD Securities

Rob Hope – Macquarie Group

David Noseworthy – CIBC World Markets

Carl Kirst – BMO Capital Markets

Robert Catellier – GMP Securities, LLC

Steven Paget – FirstEnergy Capital Corp.

Robert Kwan – RBC Capital Markets

Matthew Akman – Scotiabank

Dominique Barker – CIBC Global Asset Management

AltaGas Ltd. (OTCPK:ATGFF) Q2 2014 Earnings Conference Call July 31, 2014 11:00 AM ET

Operator

Good morning, ladies and gentlemen. And welcome to the AltaGas Ltd. 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’ Second Quarter 2014 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 will have a question-and-answer session.

Before we begin, I would like to remind you that certain information presented today may include forward-looking statements. Such statements reflect the corporation’s current expectations, estimates, projections and assumptions.

These forward-looking statements are not guarantees of future performance and they are subject to certain risks, which could cause actual performance and financial results to vary materially from those contemplated in the forward-looking statements. For additional information on these risks, please take a look at our annual information form under the heading Risk Factors.

I will now turn the call over to David Cornhill.

David W. Cornhill

Thank you, Jess. Good morning, everyone. It was another very busy quarter, we continue to deliver solid financial results, and executed on our growth strategy. Just yesterday we safely start generating power at Forrest Kerr. After four years of construction, we are very proud to have delivered such a significant project, on time and on budget. This achievement would not have been possible without the great contribution of our dedicated staff, with Tahltan First Nations and many contractors.

For the second quarter, our normalized earnings were $0.22 per share compared to $0.30 per share in the second quarter of 2013. Normalized FFO increased by 27% to $105.8 million compared to $83.1 million last year as we received the first dividend payment from Petrogas.

Our Gas segment is performing well. Gas benefit from significantly higher volumes processed, higher frac prices and the contribution of Petrogas. The Alberta spot power price however was one-third of what they were in the second quarter of 2013. This was partially offset by the positive contribution from Blythe.

Our utilities continue to benefit from rate based growth, but we did experience warmer weather in Alaska and Michigan in the second quarter.

On a trailing 12 month basis, we continue to deliver strong financial results. We achieved $543.3 million of normalized EBIDTA and $439.2 million of normalized FFO.

On the growth front, we continue to make progress and build on opportunity is given by the growth in natural gas supply. Marcellus play is displaying traditional Western Canadian markets. We need to develop new markets for Western Canada’s natural gas and natural gas liquids. We are planning solutions for those.

With Petrogas’ logistics capability, we are able to source transport and deliver LPG to Ferndale and ultimately to international markets. We are ramping up export volumes at Ferndale to approximately 30,000 barrels a day over the next few years. We also continue to target a site off the BC coast to export additional 30,000 barrels. We believe there is more than enough supplies.

We continue to work with various parties to support the Douglas Channel LNG export initiative. The CCAA court deadline to reach definitive agreements is August 1, 2014. Although much progress has been made on the agreement there is no assurance of definitive agreements will be reach with all stakeholders.

In the event, that the CCAA proceedings are terminated due to the absence of agreement, the current insolvent projects entities may be placed into receivership and a transportation agreement on PNG system to Kitimat terminates in accordance with the notice already given by PNG.

In this event, we will continue to work towards development of floating LNG plants using available PNG pipeline capacity and other available sites on Douglas channel.

With Energy Exports we are competitively positioned to provide producers with a full range of services and markets, is also providing us opportunities for gas processing. We are in advanced negotiations with a significant Montney reserve owner to form a strategic alliance. The negotiations include new processing facilities in alliance would offer us the opportunity to expand and built additional facilities to support ongoing drilling programs.

We are hopeful that a public announcement can be made within 30 days. We are also in advanced discussions with other reserve owners in Northeast BC to provide a range of processing services. These would complement ours and theirs energy export initiatives.

The growth opportunities in our gas business are unprecedented. We are well positioned for this growth and have demonstrated that we can execute successfully and profitably. We have achieved solid results in the first half of the year and with the successful start of the Forrest Kerr and the pending start-up of Volcano there’s more to come.

I will now pass the call on to David Harris.

David Harris

Thank you David and good morning everyone. We performed well across all three business segments in the second quarter. Our Gas business had a very strong second quarter, normalized operating income from our Gas business was $40 million, nearly doubled the same quarter 2013. Our Gas business benefited from the acquisition of Petrogas, higher frac exposed volumes, and higher realized frac prices of $22.12 per barrel, compared to $20.80 per barrel in Q2 2013.

In the quarter, we also continue to benefit significantly from the ramp-up in volumes in liquid-rich areas. Total volumes processed increased by over 110 Mmcf per day to 1,476 Mmcf per day, compared to Q2 2013. Driven by higher volumes at Gordondale and Blair Creek. In addition, Co-Stream operating in accordance with contractual obligations to deliver returns in line with our expectations.

Normalized operating income from our power business was $13.2 million. The average realized power price for the quarter was approximately $56 per megawatt hour, significantly lower than the $87 per megawatt hour for the same period last year. We experienced exceptional strong spot prices in Alberta during the second quarter last year, as a result of prolonged unplanned outages at large generators. Prices this year are a more reflective of a typical seasonality in the Alberta power market.

Generation volumes were comparable to the same quarter last year. However, this was overshadowed by significant lower spot power prices. Weaker Alberta power results were partially offset by the contribution from Blythe.

Our utility segment continues to deliver solid results with normalized operating income of $19.9 million. Our Canadian utilities benefited from colder than normal weather and rate base growth at Heritage and AUI, compared to the same quarter last year. Results were negatively impacted by warmer weather at our US utilities partially – particularly in Alaska.

Let me provide an update in some of our projects under development. As David mentioned, we brought Forrest Kerr on line and have begun delivering power to BC Hydro in terms of our EPA. Over the next four to six weeks we will be completing online electrical and system functional checks in coordination with BC Hydro, during which time generators are expected to fluctuate. AltaGas expects final project commercial operations to be achieved by the end of Q3 2014.

We’ve made significant progress at Volcano. Construction of the turbines, powerhouse and intake is complete, installation of the penstock has commenced and commissioning will start in Q3 2014.

At McLymont Creek tunnel construction is nearly 80% complete, construction of the powerhouse and installation of the turbines is underway and progress continues on the intake access road. McLymont remains on track to be in service in mid-2015.

Our other projects are also progressing well. Cold Lake is on schedule and budget to be completed by mid-August. And we see the regulatory approval for our Harmattan Cogen III project on July 29. Construction is underway, at our AltaGas storage facility with civil works being performed at the river and cavern sites, installation of the water lines is approximately 40% complete and drilling at the cavern will begin in the first week of August.

On our regional LNG initiative, we have acquired a parcel of land in Dawson Creek in support of our first regional LNG project, final engineering, procurement and commercial arrangements of offtakers are progressing. On July 20, AltaGas signed an LOI with the government of British Colombia in support of this project.

We also continue to position ourselves to expand Blythe. In the second quarter, we acquired a shovel ready permitted site adjacent to our facility. We believe that with the expansion we can create synergies with our existing facility and are competitively positioned to participate in the upcoming California utility RFPs this fall.

That concludes my prepared remarks and I will pass the call over to Debbie.

Deborah S. Stein

Thank you, David and good morning everyone. In the second quarter, we achieved normalized earnings $26.8 million or $0.22 per share, compared to $35.5 million or $0.30 per share in second quarter of 2013.

On a GAAP basis, net income applicable to common shares for second quarter 2014 was $28.9 million or $0.23 per share, compared to $35.9 million or $0.31 per share for second quarter 2013. Normalized EBITDA for the second quarter 2014 was $107.3 million. Normalized funds from operations increased 27% to $105.8 million or $0.86 per share, compared to $83.1 million or $0.71 per share in the same period 2013. In the second quarter, we received our first distribution from Petrogas, which contributed to our increase in our funds from operations.

Our payout as a percentage of normalized FFO for the trailing 12 months ending June 30, 2014 remains conservative at 43%. Interest expense for the second quarter 2014 was $23 million. This is lower than the same period last year as a result of higher capitalized interest of $10.8 million and lower average borrowing rates.

In the second quarter 2014, we reported an income tax expense of $5.7 million compared to an income tax recovery of $2.9 million in the same quarter last year. Recall the recovery was due to two factors: a statutory tax rate change related to dividends paid on preferred shares and an adjustment made to our deferred tax liability account.

For the six months ended June 30, 2014 normalized net income was $100.5 million, compared to $91.1 million. In both periods, normalized earnings per share were $0.82. On a GAAP basis, net income applicable to common shares for the six months ended June 30, 2014 was $68.8 million or $0.56 per share compared to $85 million or $0.76 per share for the same period 2013.

Year-to-date GAAP earnings included an after-tax gain of $9 million from the sale of assets, a non-cash after-tax provision of $36.8 million related to some of the assets we acquired with the Taylor acquisition back in 2008, costs associated with the early redemption of medium-term notes, and development costs incurred for energy exports.

For the three and six months ended June 30, 2014, net invested capital was $137.2 million and $231.9 million respectively. For full year 2014, we expect our capital expenditures to be in the range of $450 million to $500 million.

Our balance sheet remains strong with debt to total capitalization of 53% at the end of the second quarter.

On the financing side, in July, we successfully completed an 8 million share issuance of our Series G preferred shares for gross proceeds of $200 million. Our average debt maturity is just over six years and continues to be very manageable.

We will continue to balance our long-term and short-term financings as well as our floating and fixed-rate debt in order to execute a disciplined financing strategy that supports our business strategy.

And with that, I will turn the call over back to Jess.

Jess Nieukerk

Thank you, Debbie. Operator, I will turn the call over to you for Q&A session.

Question-and-Answer Session

Operator

Thank you. We will now take questions from the telephone lines. (Operator Instructions) The first question is from Linda Ezergailis of TD securities. Please go ahead.

Linda Ezergailis – TD Securities

Thank you. Can you maybe help us out a little bit with the Forrest Kerr and Volcano Creek contribution in 2014, given the start dates and the seasonality as a ballpark, maybe, percentage of normalized annual contribution or something to help us out?

David W. Cornhill

We will work on that, Linda. I think probably later in the fall is a better time. There’s a range now and I’m not sure that we’ll be getting that out to the market.

Linda Ezergailis – TD Securities

Okay. And just to confirm that you are going to start booking earnings on your income statement after payments are actually made, when you talk about commercial operations. So for Forrest Kerr, it would be kind of the end of Q3?

Deborah S. Stein

No. We will be booking earnings on test power as well, Linda.

Linda Ezergailis – TD Securities

Okay, yes, then we need a little bit more help even.

David W. Cornhill

Yes.

Deborah S. Stein

Yes.

Linda Ezergailis – TD Securities

Okay. Just another follow-up question. Can you give us a sense of whether there was any maintenance capital in your power or utilities or corporate segments? I just saw the gas maintenance capital in your disclosure.

Deborah S. Stein

Yes, there was – the gas would be the $0.9 million. It depends on how you look at the Blythe turnaround. There was another $1.5 million that we spent on Blythe, but again, that $15 million or so of cash went out the door on Blythe turnaround we’re amortizing over three to seven years. So it depends on how you treat that $1.5 million. And on the utilities – no, all of our capital is treated as regular capital. There’s no allocation to maintenance per see.

Linda Ezergailis – TD Securities

Okay, sorry. The $1.5 million…

Deborah S. Stein

Related to the Blythe.

Linda Ezergailis – TD Securities

Okay. That’s how you guys would look at it?

Deborah S. Stein

Yes.

Linda Ezergailis – TD Securities

Okay. Thank you.

David W. Cornhill

We treat it as normal capital.

Deborah S. Stein

Yes. We treat it as normal capital.

David W. Cornhill

Amortized over three to six, seven years.

Linda Ezergailis – TD Securities

The $15 million?

Deborah S. Stein

Yes. The full $15 million, but CAD1.5 million was in Q2. The rest we booked in Q1.

Linda Ezergailis – TD Securities

Okay. Thank you. Great, thanks.

Operator

Thank you. The following question is from Rob Hope of Macquarie. Please go ahead.

Rob Hope – Macquarie Group

Good morning. I was just hoping maybe you could provide a little bit more clarity on this northeast B.C. alliance. Is this just for gas processing or does this extend down the value chain to fractionation and transportation? And if so, is that focused in B.C. or at Fort Saskatchewan?

David W. Cornhill

It is a full from wellhead to market alliance and locations are various places. I can’t quite tell – say anymore there, but we are focused clearly on supporting energy export both on LPG and LNG.

Rob Hope – Macquarie Group

Okay, that’s great. And maybe just switching over to Douglas Channel, is the August 1 a firm deadline or could we see extensions there and what are the main hold-ups right now?

David W. Cornhill

For us it’s a firm deadline.

Rob Hope – Macquarie Group

And are you still interested in owning part of the onshore assets there?

David W. Cornhill

We’re still actively working to resolve, but we’ll see what happens on August 1.

Rob Hope – Macquarie Group

All right. Thank you. I’ll jump back in the queue.

Operator

Thank you. The following question is from David Noseworthy of CIBC. Please go ahead.

David Noseworthy – CIBC World Markets

Good morning, everybody. Congratulations on the startup of Forrest Kerr. Just on the Douglas Channel, I guess we’re on July 31, you have a fairly good idea of what’s going to happen come August 1. In the case that you don’t have an agreement with Douglas Channel LNG, what does that do for your Triton project and the timing of your Pacific Northern Gas looping project?

David W. Cornhill

There are a number of other options that we have and I wouldn’t say it would materially disrupt those projects.

David Noseworthy – CIBC World Markets

And I guess, then, how do you think about the FID? You mentioned in your MD&A you’re looking for a late 2015 FID for the looping project. Is that predicated on an FID for Triton before that? And if not, how do you think about it?

David Harris

To David’s point, it wouldn’t be material to where we would be on FID for Triton for the looping project. If you’re referring into a guise of what happens or doesn’t happen on August 1.

David Noseworthy – CIBC World Markets

No. Sorry, no. This is a separate question. Just saying you’ve put out there that the looping project, you’re looking to FID in late 2015. And I’m asking is that basically – is there a precedence to that FID being FID on Tryton?

Deborah S. Stein

David, it would be. So that late 2015, we’ve had that in our disclosure for a while. We are working on the project and so we’ll see, as the projects unfold, whether that date moves or not. But until we have firmer dates we’re not inclined to keep moving our dates around.

So I would treat that as more to come on when a FID – actually what happens. Right now, based on how the projects are unfolding, there is a likelihood that it could happen by the end of 2015. But we’ve also said it depends on firming up the site, firming up the off-take agreements and all of the technology related to FID. So, all of the work is still progressing. On the FEED studies and the site locations. So that’s how I would look at that.

David Noseworthy – CIBC World Markets

Okay. And may be just one last question around this, the Douglas Channel and how it relates to other projects. Is there an opportunity if an agreement and definitive agreements were reached, that your West Coast LPG facility could also be located near or on the same site as Douglas Channel?

David W. Cornhill

It’s a clearly not our primary target for LPG export.

David Noseworthy – CIBC World Markets

Okay, great. I’ll be go back in the queue. Thank you very much.

Operator

Thank you. The following question is from Carl Kirst of BMO Capital. Please go ahead.

Carl Kirst – BMO Capital Markets

Thank you, good morning everybody. Just maybe staying with Douglas Channel, and considering where we are on the process, this may not be – you may not be able to qualify at this point, but if all parties were able to come to definitive agreement, as we sit here on July 31, is there any sense of what the sort of broader soup to nuts through development, what the capital outlay would be? Or net to Alta?

David W. Cornhill

It’s in the hundreds of millions of dollars to auto gas potentially and that we’d project to export. So, it’s not huge – the first phase of the Douglas Channel would not be a huge capital investment, it would be in the $100 million to $200 million.

Carl Kirst – BMO Capital Markets

Okay, that’s helpful. Thank you. And then just a question on Ferndale, if I could, because my understanding before Petrogas bought it was that it was one of the few operating facilities that were able to export propane that the facility itself – and I may be mistaken here – could in fact support the 30,000 barrels a day. So I’m just – I guess I’m trying to get to a better sense of as you look at this ramp to 30,000 barrels over the next several years, what is the primary gating factor to that ramp?

David Harris

I’ll jump in, this is David Harris. The facility itself has the ability to turnaround and handle 30,000 barrels a day, the primary hurdles will deal with in cooperation with Petrogas, work down logistics, and converting one of the tanks that are there now, both tanks were in butane service we’ll help to convert, one of the tanks back to propane service.

Carl Kirst – BMO Capital Markets

Okay, that’s helpful. All right, thank you guys.

Operator

Thank you. The following question is from Robert Catellier of GMP Securities. Please go ahead.

Robert Catellier – GMP Securities, LLC

I would like to talk about Blythe for a minute, here. You made an announcement today that you’ve acquired an additional project that looks like it’s shovel ready. That’s a gas-fired project. With the additional land that you’re buying in addition to that, are you considering more gas-fired projects or are renewable projects, such as solar, included in your strategy?

David W. Cornhill

Now the primary focus in the Blythe area would be gasifier projects at this time.

Robert Catellier – GMP Securities, LLC

And I just want to clarify that the land acquisition there – I don’t want to double count anything, I want to make sure that that is different from the access line that was acquired during the original acquisition in 2013.

David W. Cornhill

That’s correct.

Robert Catellier – GMP Securities, LLC

So there’s two additional pieces for the Blythe site today?

David W. Cornhill

Correct.

Robert Catellier – GMP Securities, LLC

Okay. Just to clarify the goings-on on the Douglas Channel here, it looks like you’re maybe a little bit more cautious in your wording and it’s obviously quite sensitive. But I just want to clarify the siting decision on Triton. So, should you not conclude a definitive agreement on Douglas Channel, do you have enough siting options currently that you wouldn’t jeopardize the Triton FID estimate at this point?

David W. Cornhill

Yes.

Robert Catellier – GMP Securities, LLC

Okay, Okay. I, too will voice my opinion that it will be helpful to have a little bit more clarity on the Q3 utilization now for Forrest Kerr, understanding that they’re – so some obvious commissioning work to be done there. But maybe on the bigger picture with the northeast BC alliance, just to give sort of a general sense of the scope here, do you foresee being able to use the Petrogas assets and any of your BC LNG assets in a material way to help with that alliance? Is that currently contemplated in the scope of the alliance?

David W. Cornhill

We are looking at fully integrate services all the way to markets whether those our international markets or domestic markets.

Robert Catellier – GMP Securities, LLC

Okay, and then finally on the ramp-up of Ferndale, have you published or otherwise given the market a capital expectation to get that facility up to 30,000 barrel a day potential?

Deborah S. Stein

No, we haven’t.

Robert Catellier – GMP Securities, LLC

Do you care to ballpark it now?

David W. Cornhill

It’s relatively not two material dollars were probably looking at something that could range $25 million to $50 million is may be a little bit that, and telling how we expanded.

Robert Catellier – GMP Securities, LLC

Right, so it’s really just the tankers, then, [net DRI] is the issue?

David W. Cornhill

That’s correct in the initial stages with a little bit of contemplation for logistic support potentially extra real siting capability.

Robert Catellier – GMP Securities, LLC

Great, okay well congratulations on Forrest Kerr and those are all my questions.

David W. Cornhill

Thanks.

Operator

Thank you, the following question is from Steven Paget of FirstEnergy. Please go ahead.

Steven Paget – FirstEnergy Capital Corp.

Good Morning, My first question on Petrogas – how much of the cash dividend comes from revenue based on commodity prices and how much from fee-based revenue?

Deborah S. Stein

Generally speaking about I would say the commodity is about two-thirds and the fee or – no the commodity is about 50% and the fee base is about 50%..

Steven Paget – FirstEnergy Capital Corp.

Thank you.

Deborah S. Stein

And then overall, overall about 10% of their earnings are, I would say commodity typically the way they transact is back to back deals.

Steven Paget – FirstEnergy Capital Corp.

Which are not exposed they are locked in right away.

Deborah S. Stein

Correct.

Steven Paget – FirstEnergy Capital Corp.

Thank you, Debbie that is very useful. On the Sonoran Energy project, the proposed power plant would be a duplicate of Blythe, is that correct?

David W. Cornhill

That’s what’s been contemplated this time but we also have some optionality to look at some slightly different may be little bit more megawatts but, I’m very, very closed to what we at Blythe I, excuse me.

Steven Paget – FirstEnergy Capital Corp.

Thank you, David. If it doesn’t get an RFP for California, what’s the timeline on possible RFPs for Arizona?

David Harris

That’s a good question. We are looking at that ourselves, we believe there is optionality in Arizona and that may follow a little bit later on say it, middle to the tail end of 2015.

Steven Paget – FirstEnergy Capital Corp.

Thank you, David. On gas processing, how big in terms of either dollars or Mmcfs per day could the processing alliance be?

David Harris

And probably up half a B.

Steven Paget – FirstEnergy Capital Corp.

Thank you, David. Those are my questions.

Operator

Thank you. The following question is from Robert Kwan of RBC Capital Markets. Please go ahead.

Robert Kwan – RBC Capital Markets

Good morning. If I can just start on Forrest Kerr – so Debbie, you said you’re going to book earnings or revenues, I guess, while you’re going through the testing. I assume that means everything is going to come on to the income statement, including the capitalized interest and depreciation?

Deborah S. Stein

Yeah, once we have enough critical mass and we are generating enough test power into the BC grid, we believe will be recording that as income and then the full depreciation look start coming on to the income statement as well.

Robert Kwan – RBC Capital Markets

Okay, so everything comes on the income statement? You’re not going to book the cash flows back against CapEx?

Deborah S. Stein

And it’s not likely that it will be a material amount, if we do book anything for capital

Robert Kwan – RBC Capital Markets

Okay. And then just turning to Douglas Channel – the August 1 date, it’s kind of followed continual delays here. So from your perspective though, is this a hard drop-dead date, where if nothing comes together tomorrow, you guys are going to pull out of the process?

David Harris

That’s our position.

Robert Kwan – RBC Capital Markets

Okay. So effectively, I guess, the way to think about it is as of August 2, you’re going to have access to the PNG pipe one way or the other?

David Harris

That’s what we expect and shortly after that.

Robert Kwan – RBC Capital Markets

Okay. And then I guess just last question here, with Petrogas or just around the dividend payment. I know you mentioned that was a semiannual expectation. Was this payment representative of six months or was it a little bit more, with the stub period from last year?

Deborah S. Stein

It did represent the stub period from last year as well.

Robert Kwan – RBC Capital Markets

Okay. And then are they paying out all of the or virtually all of the free cash flow after growth or is this effectively an FFO payout from them and then you kick capital back in as they have growth projects?

Deborah S. Stein

Right now the working assumption is that we would pay out – subject to the Petrogas Board approval we would payout whatever is available to be paid out.

Robert Kwan – RBC Capital Markets

And is that calculated before or after growth CapEx?

Deborah S. Stein

It would be before growth CapEx.

Robert Kwan – RBC Capital Markets

And then you would kick capital back in if they need something for growth?

Deborah S. Stein

If required, yes. There was a requirement for minimum dividend payout, but we did declare a dividend that was above that for the period that we’ve owned it.

Robert Kwan – RBC Capital Markets

Okay. And this was virtually all of the free cash flow? There’s no holdback?

Deborah S. Stein

They did have remaining free cash flow. We didn’t take it all.

Robert Kwan – RBC Capital Markets

But is it substantially…

Deborah S. Stein

Yes, they didn’t dividend it all out.

Robert Kwan – RBC Capital Markets

But is it a substantial portion? Like this is pretty representative of the underlying or…

Deborah S. Stein

I think it’s consistent with what you should expect from Petrogas. We have not made any incremental investments or capital to Petrogas and they have been growing their business with internally generated cash.

Robert Kwan – RBC Capital Markets

Okay. And then, Debbie, just on your comment, 50% commodity, 50% fee, but 10% of the earnings are commodity driven. So just to be clear, the other, call it, 40% in the commodity bucket is basically spread driven?

Deborah S. Stein

And it’s back-to-back.

Robert Kwan – RBC Capital Markets

So I guess the downside is more spreads converge and therefore the profitability there would be at risk?

Deborah S. Stein

Yes. That’s the way to look at it.

Robert Kwan – RBC Capital Markets

Okay. Thank you.

Operator

Thank you. (Operator Instructions) Following question is from Matthew Akman of Scotiabank. Please go ahead.

Matthew Akman – Scotiabank

Hi, good morning. I noticed that construction has – you’ve said has started on Alton storage. And I’m just wondering if you’ve fully developed the fee model there yet. Is it all contracted back to Heritage Gas or could there be third parties? Will it be in rate base or out of rate base? And I guess related is do you guys have construction cost risk? Thanks.

David Harris

Okay, I’ll answer that. It’s going to be a combination of a couple of things. There will be some contracted volumes to Heritage. We’ll be looking for third parties and we have very minimal construction risk on the project.

Matthew Akman – Scotiabank

And it will not be in rate base. Is that right, David?

David Harris

No, it will not be in rate base.

Matthew Akman – Scotiabank

Okay. But I guess the contract back to Heritage has to be approved by the regulator?

David Harris

That is correct.

Matthew Akman – Scotiabank

So you feel comfortable sufficiently that the terms of that will be approved so that you could start construction in advance?

David Harris

Yes, we do.

Matthew Akman – Scotiabank

Okay.

David W. Cornhill

The regulator has approved the use of storage. They haven’t approved the actual terms of the agreement.

Matthew Akman – Scotiabank

Yes, okay. I did notice they had approved it in principle. On utilities, if I could just switch there, there’s a comment in the quarter about higher expenses impacting earnings to some extent as a result of growth. So I’m just wondering whether that means that you guys are looking toward some kind of rate case or how you’re looking at recovering those. Presumably, that has to do with maybe SEMCO?

Deborah S. Stein

Yes, it does, and so we are filing a rate base in Alaska. We are expecting sometime in the near future. And at SEMCO, we are – or in Michigan, we are looking at the timing of that rate case to see how you balance the incremental cost and capital that you’re putting in with your regulatory risk. So that’s being worked on, and so there is no requirement at any given point in time to file in Michigan. So we decide when that filing happens.

Matthew Akman – Scotiabank

Okay. So you’re still considering that? Is there…

Deborah S. Stein

Sorry, Matthew. On the issue of the OpEx, some of it was seasonal and we expect that we’ll get that back in the second half of the year. But not all of it is OpEx that won’t recover.

Matthew Akman – Scotiabank

Okay, thanks. Just the last question on utility. I know there is a little bit of friction in Alaska on the rates increases related to commodity. I’m just wondering if you could provide your perspective on that, maybe where you see that going, and any learnings?

David W. Cornhill

I think it’s settling down. It’s a timing issue as it relates to gas cost recovery. And I think, as the team up there works collaboratively with the public on education, we’ve seen this things settle down tremendously over the last week. We’re not worried about any significant issues going forward.

Matthew Akman – Scotiabank

Good. Thanks, guys. Those are my questions.

Operator

Thank you. The following question is from Dominique Barker of CIBC Asset Management. Please go ahead.

Dominique Barker – CIBC Global Asset Management

Hi. I’m not sure if this has been covered, but I just wanted to get a comment from you with the Apache news that they are exiting LNG and Canada, if there is any impact on AltaGas. And then if there’s any interest in, say, the Pacific Trail pipeline? Thanks.

David Harris

No impact and not much.

Dominique Barker – CIBC Global Asset Management

Okay. Thanks.

Operator

Thank you. The following question is from David Noseworthy of CIBC. Please go ahead.

David Noseworthy – CIBC World Markets

Hi. Just a couple of questions on the regional LNG. Can you just describe just what are the major decision factors for potential off-takers and kind of when you expect to have those baseload off-taker agreements in place?

David Harris

I think it comes down to price competitiveness in the marketplace is probably the biggest driver and that’s driven by the capital cost of the project and we would anticipate to have final cost wrapped up probably, say, within the next month or so. And then hopefully shortly thereafter moving into commercial terms for off-take with the off-takers we’re in discussions with.

David Noseworthy – CIBC World Markets

Okay. And then with regards to the letter of intent signed with the B.C. government around this regional LNG opportunity, how do you see any subsequent agreement impacting, I guess, your capital costs or off-take agreements, or are they kind of separate in your mind? How are the two related?

David Harris

Yes, I would think they are separate and we would not see any material impact at this point.

David Noseworthy – CIBC World Markets

Okay. What exactly is that agreement going to do for you?

David Harris

Provides more regulatory certainty for us.

David Noseworthy – CIBC World Markets

Okay. Around taxes as well or just approvals?

David Harris

Just approvals and cost recovery.

David Noseworthy – CIBC World Markets

Okay. And then just last – and maybe this is in the MD&A and if I missed that, I apologize, but can you provide more detail around the $28.7 million provision related to the former Taylor assets?

Deborah S. Stein

That was what we booked in Q1, David, with respect to the EDS and JFP pipelines. Nova informed us that they were going to exercise their options to take that back.

David Noseworthy – CIBC World Markets

Got it. Thank you.

Operator

Thank you. There are no further questions registered at this time. I’d like to turn the meeting back over to Mr. Nieukerk.

Jess Nieukerk

Thank you, operator. That concludes our AltaGas’ second quarter 2014 conference call. We are available for any follow-up question that you may have. Thank you for joining us today.

Operator

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

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