Jess Nieukerk - Director of Finance and Communications David Cornhill - Chairman and CEO David Harris - Chief Operating Officer Debbie Stein - Senior Vice President, Finance and CFO John Lowe - Executive Vice President, Corporate Development

David Noseworthy - CIBC Rob Hope - Macquarie Carl Kirst - BMO Capital Markets Robert Catellier - GMP Securities Robert Kwan - RBC Capital Markets Steven Paget - FirstEnergy

Thank you, operator. Good morning, everyone.

Welcome to AltaGas’ third 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’ll have a question-and-answer session. Before we begin, I’d like to remind you that certain information presented today may include forward-looking statements.

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

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

Thank you, Jess. Good morning, everyone.

Before I talk about the quarter, I’d like to congratulate our team and all parties involved in achieving commercial operations at Forrest Kerr. I would like to especially thank the Tahltan First Nations.

It is their traditional territory where this landmark green project operates. The Tahltan have played a key role in the project success and we will continue to work closely with them as we provide clean energy to British Columbia for decades to come.

I believe Forrest Kerr project is the shining example of how working together. First Nations’ government and the private sector can create significant social value.

What’s important is that all parties received a fair share of the benefit, while taking care to minimize the long-term impacts on the environment. Reaching COD marks a significant completion of the largest project in AltaGas’ history.

I am very proud of this and there is more to come. Our team continues to work hard on Volcano, which has begun commissioning and will be on shortly and will deliver McLymont on stream in 2015.

Finally, I am very pleased to say that Forest Kerr is performing slightly above our expectations. It’s still early days, but it’s looking promising.

Today, we reported third quarter normalized earnings of $0.13 per share compared to $0.21 per share in Q3 of 2013. Normalized FFO of $79.9 million compared to $80.2 million last year.

EBITDA of $104.9 million compared to $103.5 million in the same quarter last year. Our third quarter results were negatively impacted by soft Alberta power prices and lower generation.

We continue to execute on our strategy. We are engaged in advanced discussions with producers in Northeast BC.

These discussions are providing them with a very competitive service offering from gas processing to providing access to higher net back markets for the production. We’re also active in providing very competitive options for producers’ LNG production.

We believe we can provide significant value to our customers through this integrated approach. For example, the 15 year strategic alliance with Painted Pony.

Our first infrastructure project under the alliance Townsend is a 198 million cubic feet a day shallow-cut plant. As Painted Pony continues to develop the area, we expect this to grow to about 0.5 Bcf per day.

We have made significant progress in reaching new markets with LPG. Through our Petrogas Ferndale facility, we have delivered product to Asian markets for the first time.

We expect to ramp up export volumes at Ferndale to approximate 30,000 barrels a day over the next few years. We also continue to target a site off BC Coast to export an additional 30,000 barrels.

I am pleased with the progress made on the Douglas Channel LNG export initiative. Yesterday the Supreme Court of British Columbia approved to Plan of Arrangement for filing and distributing to creditors.

Creditors are to review the Plan of Arrangement and there will be a vote on the plan. With a positive vote achieved in support of the Plan of Arrangement, it will proceed to be sanctioned by the Court and become effective thereafter, upon satisfying other conditions prescribed in the Plan of Arrangement including finalization of documents, transaction documents and approval of the PNG agreement from the British Columbia Utilities Commission.

This allows us to continue to pursue the project and brings us one step closer to executing LNG export of Canada’s West Coast. Ultimately, we see this project being the first LNG project in British Columbia to achieve shipments to Asia.

Now to comment on the LNG tax regime proposed by the BC government. At first glance, the new legislation gives us better certainty to move our projects forward to meet our customers’ requirements.

We will review the details further in the coming weeks. We would ask the federal government to fall BC’s leadership in providing fiscal certainty.

We are well positioned to deliver solid results into 2015. Our utility business continues to grow and we expect it will deliver strong results.

Our gas business is also expected to deliver strong results, despite two major plant turnarounds at our two largest processing facilities next year. The power business will benefit from the Northwest hydro projects.

However, soft Alberta power markets will continue to be concern in 2015. We will continue to execute on our strategy and deliver significant long-term value to our shareholders.

I’ll now pass the call on to David Harris.

Thank you David and good morning everyone. In the third quarter, we once again benefited from strong operations and the diversity of our three business segments.

The impact from a weak power pricing environment in Alberta was partially offset by significant stronger performance in our gas segment. Normalized operating income from our gas business increase $12.7 million to $39 million compared to the same quarter 2013.

Our gas business benefited primarily from the acquisition of Petrogas and higher volumes processed. We continue to benefit significantly from the ramp-up in volumes in liquid-rich areas.

Total volumes processed increased by over 200 Mmcf per day to 1,447 Mmcf per day, compared to Q3 2013. This was driven by higher volumes at Gordondale and Blair Creek.

In addition, Co-Stream operated in accordance with contractual obligations and delivered returns in line with our expectations. For the third quarter of 2014, AltaGas had 63% of frac exposed production and average frac spread of $24 per barrel, this compares to 72% hedge to $28 per barrel in the same quarter last year.

Spot NGL frac spread for Q3 2014 was $21 per barrel compared to $29 per barrel a year ago. Normalized operating income from our power business was $19.4 million.

The average realized power price for the quarter was $74.51 per megawatt hour compared to $79.42 per megawatt hour for the same period last year. We hedged approximately 55% in Alberta during the third quarter at an average price of $67 per megawatt hour compared to 62% at $70 per megawatt hour a year ago.

Alberta power prices continue to be a headwind in the third quarter. They were more than 20% lower than what they were in Q3 2013.

We also had lower production from the Sundance facility than was available to be generated. We expect Alberta power prices remain under pressure for at least the next year.

The 800 megawatt Shepard power plant is already producing some power and the market is reflecting the expectations that it will be fully operational early next year. We expect that it will take some time for the market demand to absorb this new supply.

Third quarter is usually a quite quarter with the utilities. The segment continues to deliver solid results with operating income of $7.8 million comparable to Q3 2013, customer and rate base growth combined with cold weather were offset by higher expenses and depreciation.

Year-to-date, all three segments are performing well. Normalized operating income combined for the nine months ended September 30th is $383.9 million compared to $261.6 million for the same period in 2013.

Looking at the rest of 2014, we expect to produce approximately 7,800 barrels of C3 plus per day that is directly exposed to frac spread. Of that, approximately 80% is hedged at an average price of $26 per barrel.

In power, we are approximately 55% hedged to $62 per megawatt hour for the fourth quarter. In October prices of averaged $28 per megawatt hour month-to-date.

For 2015, we have hedged approximately 40% of our gas volumes associated with frac spread at an average price of approximately $27 per barrel. In power, we are approximately 20% hedged at an average price of approximately $63 per megawatt hour for the next year.

Let me provide an update on some of our projects under development. As David mentioned, we have completed all testing and commissioning at Forrest Kerr and provided a COD certificate to BC Hydro.

Q3 production was impacted by delaying NTL and service date, NTL constraints and extraordinarily high water levels on Iskut River that impacted commissioning in late September. As a precautionary measure, AltaGas removed Forest Kerr from service until commissioning checks could be completed and all units could be safely restarted.

Forrest Kerr returned to service on October 11th and reached COD October 21st. We have made significant progress at Volcano, which continues to pace two years ahead of schedule.

We have entered into the final commissioning stages. Commercial operations are expected to be achieved in the fourth quarter.

The McLymont Creek tunnel construction is 90% complete, the powerhouse foundation is complete with the powerhouse steel and crane being installed and installation of turbine is well underway. We have completed construction of the intake access road and expect to start intake construction in November.

McLymont remains on track to be in service in mid 2015. In the third quarter, we completed commercial underpinning of the Townsend facility and the project is now underway.

But this study has been initiated with [CB&I], which includes all technical information required for environmental permitting (inaudible) requires all the long lead equipment and a modularization study to optimize construction and schedule. At this site, clearing has been completed; logging has been completed, as well as the geotechnical work.

Surveys environmental and our geological assessments are being performed on the gathering lines from Blair Creek and the sales line to Spectra. At the Blythe facility in California, we are anticipating upcoming of our fees by the end of the year.

We continue to work on the opportunities double the size of the existing facility. And we’re also looking at further opportunities to expand generation of [Brazil] over the long-term.

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

Thank you, David. Good morning everyone.

This morning we reported normalized and GAAP earnings of $16.6 million or $0.13 per share for the third quarter of 2014. This compares to $24.7 million or $0.21 per share in Q3 2013 on a normalized basis.

On a GAAP basis, net income applicable to common shares for the third quarter 2013 was $43.3 million or $0.36 per share. You may recall that in third quarter last year we recorded the one-time gain of $18.7 million resulting from the sale of the Pacific Trail’s pipeline sold by PNG in 2011 and the provision that was taken for some gas processing assets.

Normalized EBITDA for the third quarter 2014 was a $104.9 million slightly higher than the $103.5 million reported in third quarter 2013. Normalized funds from operations was $79.9 million or $0.63 per share compared to $80.2 million or $0.68 per share in the same period 2013.

Earnings were lower mostly due to the impact of lower earnings from our Alberta power assets, as well as the fact that we recorded amortization and interest related to Forrest Kerr in service of August 12th, although the plant was not running at full load during that period. In the third quarter we also had higher cost related to financing activities we completed in the quarter.

On a cash flow basis, however, we were slightly higher, strong results in gas and utilities offset the lower earnings in our power business. We also maintained our FFO quarter-over-quarter, although we had incremental interest from bringing Forrest Kerr into service, as well as the incremental cost to financing activity.

This was offset by lower cash taxes at PNG and our U.S. operations.

Our payout as a percentage of normalized FFO for the trailing 12 months ending September 30, 2014 remains within our range of 40% to 50% and 47%. Interest expense for third quarter 2014 was $28.6 million.

This was slightly higher than the same period last year, as a result of the higher average debt balance and lower capitalized interest. In third quarter 2014, we reported an income tax expense of $1.8 million compared to $7.5 million in the same quarter last year.

The lower income tax expense is a result of lower taxable earnings compared to the same period in 2013. Cash tax was lower due to the tax on capital gained related to the PTP in third quarter 2013 as well as lower cash tax at the U.S.

operations and at PNG. For the nine months ended September 30, 2014, normalized net income applicable to common shares was $117 million or $0.94 per share compared to a $116 million or $1.02 per share for the same period in 2013.

The lower earnings per share were primarily due to the higher share count as a result of common shares issued in 2013 as well as our recent equity offering to fund our ongoing construction projects. On a GAAP basis, net income applicable to common shares for the nine months ended September 30, 2014 was $85.4 million or $0.69 per share compared to a $128.2 million or a $1.12 per share for the same period 2013.

Year-to-date GAAP earnings in 2014 included an after-tax gain of $8.9 million from the sale of non-core assets, a non-cash after-tax provision of $28.7 million related to the assets we acquired with the Taylor NGL Limited Partnership transaction in 2008 and $8.1 million after tax provision related to a number of small hydro projects we expect to sell, and approximately $3 million after-tax provision related to mark-to-market accounting and cost related to the redemption of our MTNs earlier this year. GAAP earnings for the nine months ended September 2013 included significant one-time gain related to the PTP sale as well as the impact of lower taxes related to changes in tax rates related to preferred dividends, which was slightly offset by the provision we took for some gas processing assets.

Normalized EBITDA for the nine months ended September 30, 2014 was $391.6 million compared to $355.6 million for the same period in 2013 and normalized funds from operations was $315.6 million or $2.54 per share compared to $279.3 million or $2.45 per share in the same period 2013. On a year-to-date basis in 2014, FFO and EBITDA increased by 13% and 10% respectively.

Strong results in the gas and utilities offset the impact of lower earnings from our Alberta power assets and lower than expected earnings from Forrest Kerr. For the three and nine months ended September 30, 2014, net invested capital was $199.2 million and $433.6 million respectively.

For full year 2014, we expect our capital expenditures to be in the range of $500 million to $550 million. We expect capital expenditures in the range of $550 million to $650 million in 2015.

Our balance sheet remains strong with debt-to-total capitalization of 44%. On the financing side, we were busy in the third quarter.

In July, we successfully completed an $8 million share issuance for our Series G preferred shares for gross proceeds of $200 million. In August, we closed a 30 year $300 million MTN offering as well as completed a common share offering for gross proceeds of $460.

We are well positioned to fund our growth program in 2015 and beyond. Our average debt maturity is now just over eight years and continues to be very manageable.

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

Thank you, Debbie. Operator, we’ll now go to question-and-answer please.

Good morning.

Good morning.

Perhaps I could just start off on the topic of LNG and specifically, Douglas Channel. In your most recent -- in the most recent [model] report suggests that December 5th would be the suggested date for court sanctioning of the Plan of Arrangement.

And I was just wondering, from your perspective, is this a reasonable expectation in light of what we’ve experienced to-date for this process?

I’ll pass it on to John Lowe.

Hi David. Actually that core date was -- it’s now December 10th.

And I think that that’s a reasonable date to have all of the agreement escrowed, the creditors meeting vote. And then the one other aspect that we’ll need a third-party approval for BCUC approval for the amended gas transportation agreement.

And so that may stretch beyond the sanction order date, but the sanction would stand and that would be subject to only to that approval.

Okay. And then just in terms of -- so you have this approved plan of arrangement to consider.

Under that plan of arrangement, how much of Douglas Channel would AltaGas ultimately own?

Through the JV we’ll own about a third of it. The three partners Exmar, EDF and…

Okay. So, you are the third, which is then cut 50-50?

Yes.

Perfect, okay. And then just moving on, but a little bit related here, recently you’ve seen the First Nations Band, Burns Lake Band object to the PNG looping process or looping project EA process.

And I was just wondering what are the options available to the BC Environmental Assessment Office and AltaGas to address these concerns and how do you see this impacting timing?

It’s John Lowe again. Is it that Burns Lake issue related to another pipeline or is it PNG related?

It’s both PNG and TransCanada’s pipeline proposal.

Right. And I think that that’s -- from PNG standpoint, I think that’s something that we’ll be able to work through with the Environmental Assessment Office.

Okay. So you work, the AltaGas works through the environmental because it seems to me that they’re saying, hey, the land area that was considered under the EA process wasn’t big enough, considering the Supreme Court Williams’ decision, it needs to be redone, and so you’re of the opinion that you’ll be able to work through the EAO to come to an agreement that satisfies Burns Lake?

Yes.

Okay. Fair enough.

So, no material impact to your timelines?

I don’t believe so.

Okay. That’s helpful.

And then maybe just while we’re on the PNG, we’ve seen a number of LNG export facilities proposed in the past couple months, including Orca LNG and a revised Cedar LNG, and I was just wondering what you’re seeing in terms of demand for the PNG pipeline beyond your 635 Mmcf per day potential expansion?

I think that these projects are at the preliminary stage, we haven’t upsize the expansion at this stage, but we are talking to people.

All right. Those are my questions.

I’ll get back into queue. Thank you very much.

Thanks.

Good morning.

Good morning.

Maybe shifting to northeast BC and some gas processing opportunities, I know in the past you had talked about $1 billion of opportunities there. Maybe you could provide an update on how those opportunities are going beyond Townsend?

We’re in active discussions with the number of producers at this point. And when you add up the non-discussions, we talked about Bcf of processing capacity.

And we’re more in discussions with over a Bcf right now. So, won’t get them all, but I think a very positive dialogue with the number of producers and carrying out pre-FEED work as well and looking at other opportunities.

So, we feel very positive. Part of our being positive with the announcement was the court ruling yesterday approving a preliminary plan, it also provide us some additional attraction in the area.

Good. Good to hear.

Maybe just switching over to LPG, then, it looks like Ferndale is ramping up. Do you have an updated FID for your potential BC facility?

Not at this time.

All right, thank you.

Thanks.

Thank you. Good morning, everybody.

Maybe just, actually, a couple of follow ups to David and Bob’s questions, but maybe first on the LNG side. So, if you all think you can work through the EA process there, should we still be thinking about possible FID for Triton and PNG looping call it late 2015?

I think everything in BC has been pushed back. We haven’t revised our -- I would say that if you look at distributions, there is almost zero earlier and most of the distributions are later with the complexity of the regulatory framework now I guess in terms of the court ruling in August.

Okay. That’s helpful, David.

And when we think -- maybe then kind of going back up to the BC as far as the midstream and you mentioned sort of now kind of in discussions for over 1 Bcf a day of potential processing capacity. And I think we spoke earlier about now that kind of the first term sheet, if you will, for Painted Pony has been done, it might be easier to replicate this.

And what I wonder is that will potential other parties or shippers, as far as being able to replicate this want to see more history perhaps, with how the PPY goes forward, or do you think that it could be replicated perhaps sooner rather than later, i.e. some of your discussions about the 1 Bcf a day is more perhaps front burner rather than back burner; any color there?

I’d say it’s front burner. Lots of interest in the producer community with the structure of the Painted Pony long-term strategic alliance and being able to provide producers with access to Asian markets whether through LPG or LNG early stage with our Douglas Channel is of significant interest to our customers.

So, I would say they are more front burner than back burner but when you look at construction times and that were coming into ‘15 a couple of years, so ‘17 timelines at the earliest with some of those in terms of accessing stuff on the stream.

Okay, thank you. And then maybe just sort of lastly, this is more a third quarter related.

Looking in the Alberta power market, the volumes were a little bit lighter than what we were expecting. And then I kind of understand that you all don’t have control over the dispatch here.

But I’m just trying to kind of get a better sense of, were there specific factors impacting the third quarter and if you have an outlook for what volumes, generation volumes might be for the fourth quarter in 2015, if you could share any color around that as well.

I think with respect to dispatchability, as you’re aware TransCanada handles dispatch for us. We are in discussions with them about whether we should each handle our own dispatch.

That’s what we’ve got at this point. And at this stage, we would probably expect maybe dispatch to be a little bit stronger as we get into ‘15.

But as I said, we’ll turnaround and take a tighter look at that as we get to the end of the year and the beginning of ‘15 especially depending on what actual influence it has on the market.

Understood. I appreciate that, David.

Thanks, guys.

Thank you.

Good morning, and thank you, and congratulations on Forrest Kerr.

Thank you. It’s been four full years.

I’m just going to follow up on the questions with respect to Alberta power and the dispatch. It would seem on the face of it with TransCanada handling the dispatch function and their broader portfolio bidding considerations, there might be a bit of a conflict of interest there.

So, how are you addressing that, or is that otherwise addressed in the operating agreement and do you have some sort of influence that can mitigate that moral hazard?

The influence is our ability to take control of our own dispatch and that’s where we’re possibly heading down. We’re in discussions, as I said, with TransCanada now to talk about each one of us just handling our own dispatch.

So you have contractual ability to recall the dispatch function?

We do.

Okay. And then just with respect to LNG, can you just confirm that if the Plan of Arrangement for Douglas Channel as it currently stands that’s ultimately approved, does it provide definitive access to a site for LNG, for Triton LNG?

Yes it does.

Okay. And then sort of a broad open-ended question here, but if you put aside the other complexities that go along with LNG projects, it sounds like you view the Douglas Channel and the Triton LNG project as economically viable in light of the recent BC policy announcements on emissions and tax?

Yes.

So then, in light of that, what are you hoping the federal government will do to promote LNG in BC?

I think they could provide some relaxation on the or probably certainty, but some capital cost allowances certainty. And there are some other fiscal, I think changes that they could make to recognize the benefit that Canada is going to realize in the decade to come from LNG exports.

Okay. And are those the same considerations that go into your regional LNG strategy, or is there anything different there?

I think for regional LNG, we’re not particularly looking for anything for the federal government.

Okay, thank you. Those were my questions.

Good morning.

Good morning.

If I can start with the discussions you’re having with the gas producers for new infrastructure, and it’s still pretty early with the way oil prices have dropped. I’m just wondering, though, have you noticed a change in tone with the discussions with the potential customers just as they’re reviewing their drilling budgets?

Not significantly at this point with respect to people that we’re talking to. Just as a general feel, I don’t think it’s Calgary too hard at this point, but we’re monitoring that looking at options.

But we haven’t seen a change in mood at this point, but everyone will be going into this next quarter and next quarter, firming up their drilling budgets.

Thanks, David. And I guess just kind of your thoughts then, is your sense, then, that it’s just too early to get that read or do you feel that they’re not overly concerned given we haven’t necessarily broken into the 70s?

Well, I think from a gas perspective, we’re up from where we’re lowest. Liquids pricing will be see how it firms up this fall.

I think we could see some constraints. But when you talk to a lot of the producers, their breakeven is sub $2.

And when we take a long-term view, they think that they will continue. You might see it marginally slowing.

But at this point, we haven’t seen a significant change in view especially in that area.

Okay. That’s great.

Just turning to your outlook for Alberta power pricing going into 2015, certainly I’m sensing a more cautious tone just given what we’ve seen in the market. I’m wondering if you’re able to give a sense as to your view on prices and volatility, even if on price instead of a point number.

If you’ve got one, that’s great, but even just compared to where the forward curve is right now, now that it’s sitting a little under $50?

Yes. I think Robert, when we look forward into 2015, we’re seeing from a forward perspective, $48, $49.

I would expect you will see less volatility in the next couple of years and the reason for that primarily is just Shepard coming on. You now have got about 15,800 megawatts of installed capacity.

And difficult peaks for the winter peak we’ve seen Alberta has run 11,000 and in the summer, it’s about 10.7. So you’re reserve margins are in that 30% and 32% range respectively.

Our growth rate within Alberta was about 250 to 350 megawatts a year. So, it’s going to take about maybe two and two and a half years for the market to observe Shepard.

So, we’d expect less volatility over the next couple of years and when you look at the poll, you don’t see prices start bringing back above 50 and 52 range until you get to the 2017 timeframe.

So are you seeing value in the curve then versus your outlook for next year?

Right now I’d say it’s at par.

Okay. Okay.

Maybe just a last question here. It was a small number, but I’m kind of more looking at the outlook.

You had some transaction costs for potential acquisitions, and I’m just wondering is that thing that’s ongoing or has that opportunity past? And kind of more looking forward, what is your thought on the various M&A opportunities?

What does the opportunity set look like geographies, technology that type of thing?

It’s just a small M&A activity on the power side, nothing grandiose. The transaction costs were I would say fairly immaterial.

Was it kind of a one-off or like just how are you seeing the M&A opportunities as you go forward here?

With respect to any significant M&A, we’ll have our plate full at this point. So, it wouldn’t be on the back burner, but it’s still on the stove I guess to put it.

We’ll always be aware of what’s going on, but what we see an opportunity to build out integrated opportunity in Northeast BC both on the gas processing side providing opportunity for producers to get their liquids to Asian markets. We don’t see -- that’s on the front burner for us and M&A is on the back burner, but still on the stove.

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

Good morning and thank you.

Good morning.

Just on the capitalization at Townsend, are you spending some of the $325 million to $350 million in capital on assets that could be used for additional expansions or does some of the capital include gathering systems?

Actually all of the above Steven. We’re in a process right now of optimizing the design.

All right, so to answer your question, all of the above.

So Phase II might have a lower dollar per Mcf capacity ratio?

That’s a fair assessment.

Thank you, David. Could someone please comment on the market for LNG produced by the Dawson Creek project, how much is sort of secured?

Is there any take or pay, or is it open up a station and see who arrives?

It will be based on by long-term contracts; we will allow some spot portions as well, because to serve frac requirements in the area and drilling rigs, we think it’s a good market to serve when transportation is quite attractive. So, it’ll be a combination of long-term commitments to take base volumes and leave a portion of it to supply the local spot market.

Okay, thank you, David. You had expected PNG revenue requirement decision in the third quarter; any news there?

No, none at this time Steven.

Thank you. Those are my questions.

I have just a couple of clean-up questions here. First, just regards to your Ferndale export facility; you mentioned an attention to ramp up capacity of 30,000 barrels per day over the coming years.

What are the capital costs related to ramping up the capacity to 30,000 barrels per day?

When there will be equity accounted for, so they won’t show directly, but maybe David can provide some color.

Yes, it depends on what we end up actually doing. But I think a fair range is maybe somewhere between the 80 million to 120 million range.

Okay, that’s helpful. And then with regards to your Painted Pony strategic alliance, Painted Pony has on their investor deck a need for a fractionator and another gas plant come Q1 2017.

If they are still on track for their needs, when does that then need to be confirmed up with AltaGas to deliver that?

We’re -- as I said, we’re looking to provide integrated solutions. So, we’re well down on a number of those fronts to meet those needs.

Okay. So in terms of the timing of an announcement…

You’re going to have to wait until Christmas.

All right, fair enough. Thank you very much.

Those are my questions.

Thank you. I lost my creative thought after the Christmas comment.

Debbie, just very quickly, and I apologize if you mentioned this in your prepared remarks, but you mentioned the -- I believe the growth capital for 2015 in the $500 million to $550 million range, and I wanted to -- I don’t know if you guys can call out projects or not, but I didn’t know if specifically the Blythe twinning was in there. And then just sort of more broadly, with what the current plan is, do you see any equity needs, or did the funding essentially this summer, take care of that?

So the number that I gave for 2015 Carl was $550 million to $650 million.

$550 million to $650 million?

Yes. It includes a small amount of dollars to get us ready for Blythe, but not any major capital expenditures.

Those RFPs don’t come out until later this year. So until we know that we have contract in hand, we won’t be committing a significant amount of dollars.

But there is a fair bit of short money that we’re spending at that facility to make sure that we stay on top of the opportunity. And in terms of funding, I think when we look at the $550 million to $650 million, the majority of that is getting tows and across the finish line for late ‘15, it’s finishing up McLymont; not a lot of money in there for Volcano, Volcano will be pretty much done in 2014.

And then there is -- we budget at this point about $100 million to $150 million on the utility side. So those are kind of the three buckets to think about when we look at the current guidance of the $550 million to the $650 million.

Excellent. And as far as potential equity needs between the summer and the drip that should be fine or…?

Yes, we are in pretty good shape; from a liquidity point of view, we’ve got lots it. We’re sitting with about $460 million of cash at the end of third quarter.

And we’ve got lots of room on the balance sheet. So I think from a funding point of view over the next 12 months to 18 months with the projects that we have in the pipeline, we’re well funded.

Great. Thanks everyone.

Thank you.

Thank you.

Thank you. Just a question on power and sensitivity.

In 2014, it was $1 per megawatt means a $0.01 per share change in earnings. Should we be looking at the same sensitivity for 2015?

Steven, I don’t have the exact EPS number but here is how I would look at that. Unhedged, it’s about a $2 million to op income.

And I believe we’re about close to 20% hedged for 2015. So, you can take op income of -- 80% of the 2 million will be about 1.6 million at an op income level.

So that is probably just over a penny at this point in time. But you noticed that throughout the year, we continued to add hedges.

So over the course of time, that sensitivity goes down as we add more hedges.

Thank you, Debbie. That’s very useful.

And the hedges will continue -- you’ll continue adding hedges at a similar pace?

Yes.

That’s correct, Steven. We’ll pick our spots accordingly.

Thank you, David. Those are my questions.

Thank you, operator. Thank you everybody for joining AltaGas’ third quarter 2014 conference call.

We look forward to seeing you at Investor Day and we’re also available today for any follow-up questions. Thank you.