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

David Noseworthy - CIBC Carl Kirst - BMO Capital Markets Robert Catellier - Macquarie Robert Kwan - RBC Capital Markets Matthew Akman - Scotia Bank Steven Paget - FirstEnergy

Thank you. Good morning, everyone.

Welcome to AltaGas' third quarter 2013 conference call. Speaking today are David Cornhill, Chairman and Chief Executive Officer, David Harris, Chief Operating Officer and Debbie Stein, Senior Vice President of 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.

Thank you, Jess. Good morning, everyone.

We had an exciting quarter with strong financial results and significant accomplishments on the growth front. This morning we reported normalized earnings of $0.21 per share, an increased to 62% over the third quarter of last year.

Our normalized EBITDA was up 61% at a $103.5 million compared to last year. Normalized funds from operations were $80.2 million or $0.68 per share compared to $53.3 million or $0.56 per share in the third quarter of 2012.

Our results on a trailing 12 month basis reflects significant shareholder value we have created with the acquisition of SEMCO as well as other assets we added recently. Our normalized trailing 12 month earnings per share is $1.47, an increase of almost 40%.

Our normalized trailing 12 month funds from operations per share increased by almost 40% compared to the same period ending in 2012. And we are close to $0.5 billion in EBITDA.

This shareholder value creation is a tremendous accomplishment and one in which the AltaGas team is very proud. We are looking forward to next year when Forrest Kerr and Volcano are in service.

With the significant progress on the Volcano project, we have moved up the in-service date to 2014 from 2015. We continue to expect Forrest Kerr to be in service in mid-2014 with the positive progress made on the NTL construction.

McLymont remains on track for a 2015 startup. David Harris will provide more detail on these project.

In the third quarter, all three business segments are performing extremely well. In the utility segment, with SEMCO now having contributed for full first year, we are pleased to report that has delivered above our expectations.

In the gas segment, field gathering and processing volumes were up by 18% and extraction liquids production increased by 25%. Producers are active in the liquids rich areas and we are able to take advantage of this activity as our facilities are performing well.

In power, we had our first full quarterly contribution from Blythe. As a result, power generating increased by 400 gigawatts in the quarter.

We are putting the pieces together in the quarter and that will support our growth strategy. The acquisition of third interest in Petrogas enhances our growth strategy in two ways.

Firstly Petrogas, as a leading North America integrated midstream company, brings a unique opportunity to optimize and expand our current midstream assets. It increases our ability move natural gas liquids and provides energy solutions for our customers.

With annual revenues of more than $2.7 billion and growing, we expect Petrogas to add $0.10 per share in 2015. Secondly, Petrogas has an extensive logistics network consisting of over 1,500 rail cars and 24 rail and truck terminals.

This provides key infrastructure as well as supply logistics and marketing expertise required to pursue LPG export opportunities. We are pleased that Idemitsu, our partner in our energy export business also acquired a one third interest in Petrogas.

The three of us combined bring significant size, scale and expertise to move our LPG export initiatives forward. On the LNG export initiatives, we continue to make good progress on many fronts.

The BC Environmental Assessment Office will begin a public consultation with respect to our PNG pipeline expansion on November 25. With the Transportation Reservation Agreements signed, we have started planning for 2014 environmental study.

The Transportation Reservation Agreements will carry us through the development stage up to the point we can make a final investment decision for the PNG pipeline expansion. We are making progress on preliminary engineering and design for the LNG facilities.

On October 29, we filed our application with the NEB to export LNG with Idemitsu. We are seeking approval to export 2.3 million tons of LNG per year.

Finally we continue to look at and evaluate various sites on both the LPG and LNG. This includes deploying Edward site we purchase about a year ago.

To conclude, we delivered 40% growth in earnings per share and cash flow per share on a trailing 12 month basis. With the projects we have under construction and the visible growth we have in front of us, we are well positioned to deliver on our goal of double-digit growth into the future.

We are executing our strategy. It is working and we have delivered significant value to our shareholders.

With one of the lowest dividend payouts as a percentage of funds from operations, our dividend is solid and we have considerable room to continue to grow our dividend. With this growth potential we have in our sight, we are focused on delivering capital appreciation to our shareholders.

The pieces are in place to deliver shareholder value through a balance of yield and growth. I will now pass the call on to David.

Thank you, David, and good morning, everyone. Operations across our three business segments was strong in the quarter.

Normalized operating income from our power business increased 72%, benefiting from higher Alberta power prices and a full quarter of Blythe. The Alberta power market averaged $83 per megawatt hour compared to $78 per megawatt hour in Q3 of 2012.

For the third quarter of 2013, AltaGas' Alberta power generation was 62% hedged at an average price of $70 per megawatt hour, compared to 59% hedged at approximately $67 per megawatt hour for the same period last year. Blythe contributed significantly to our power segment adding an approximately $12 million in EBITDA for the quarter, on track with our expectations and in line with the full-year profile of approximately $50 million in EBITDA.

Our utility business had another solid quarter. Normalized operating income was approximately $7.5 million, an increase of 36% over Q3 2012.

In the first full-year of ownership, SEMCO delivered approximately $138 million in EBITDA, which was ahead of our expectations. Our Canadian utilities also reported higher earnings driven by colder weather and rate base growth.

Given the seasonality, we expect strong results for our utilities in Q4, as we enter the winter heating season. On the gas business, we had a solid quarter driven by increased throughput from our new facilities.

Normalized operating income was up approximately 30% at $26.3 million despite lower realized frac spreads. In the quarter, pressure restrictions experienced on the NGTL system at our Harmattan co-stream facility were lifted.

In addition, we implemented modifications to allow processing at lower pressures, should NGTL system pressure constraints occur again in the future. Volumes at co-stream have been ramping up steadily since the end of the quarter, as operations complete final tuning associated with the modifications.

Our Q3 2013 total extractions volumes increased by over 9,000 barrels per day, primarily as a result of the addition of our co-stream facility at Harmattan and at deep-cut facility at Gordondale. We had higher throughput at our FG&P facilities in third quarter 2013, averaging 427 MMCF per day, well above the Q3 2012 throughput of 362 MMCF per day and higher than the first six months of 2013 which averaged 408 MMCF per day.

For the third quarter 2013, AltaGas hedged approximately 73% of frac exposed production at an average price of approximately $28 per barrel. This compares to approximately 83% hedged at approximately $35 per barrel in the same quarter last year.

The spot NGL frac spreads for Q3 2013 was approximately $29 per barrel compared to approximately $23 per barrel a year ago. Looking at the rest of 2013.

We expect strong results in our gas business. We expect volumes continue to increase at Gordondale.

And we expect to recover an increased amount of our contracted co-stream revenue at Harmattan. We also continue to see higher throughput at Younger and all other extraction facilities.

In Q4, we expect to produce approximately 6,900 barrels per day of C3 plus that is directly exposed to frac spread, of which 87% is hedged at an average price of approximately $28 per barrel before deducting extraction premiums. In power, we are approximately 59% hedged at $65 per megawatt hour for the fourth quarter.

In October prices of averaged $66 per megawatt hour month to-date and forward prices for November and December are currently trading around $57 and $62 per megawatt hour, respectfully. Let me conclude today with a quick update on our Northwest projects.

Construction on Forrest Kerr continues ahead of schedule and on budget. The total project is now approximately 90% complete.

The intake structure is complete. The generator assembly is ongoing and nine turbine centerlines are assembled, aligned and grouted in to position.

We are on track to be mechanically complete by the end of the year and we still expect to synch to the grid by May 2014. We continue to monitor the progress of the NTL and it remains on track for COD in May 2014.

At Volcano, we have made significant progress. And as David mentioned, we are moving the timeframe for completion from mid-2015 to 2014.

Excavations of the intake and diversion channel have been completed and the weir is scheduled be installed within the next 90 days. The powerhouse building structural steel has been erected and the powerhouse crane has been lifted into place.

The building is scheduled for completion in November. The penstock excavation is ongoing and is on track to be completed in first quarter 2014.

At McLymont, construction of the seven kilometer intake access road is 85% and is expected to be completed within the next 90 days. Excavation of the McLymont power portal has been completed and approximately 30% of the 2,800 meter power tunnel has been excavated.

Excavation of the powerhouse foundation is expected to commence in fourth quarter 2013 and the project is on track to be in service in mid-2015. That concludes my prepared remarks.

I will now pass the call over to Debbie.

Thank you, David and good morning, everyone. As David mentioned, we reported a strong third quarter with normalized net income applicable to common shares of $24.7 million or $0.21 per share compared to $12.3 million or $0.13 per share in third quarter last year.

On a GAAP basis, net income applicable to common shares for third quarter 2013 was $43.3 million or $0.36 per share compared to $8 million or $0.08 per share for third quarter 2012. For the nine months ended September 30, 2013, normalized net income was $115.9 million or $1.02 per share compared to $62.9 million or $0.69 per share for the same period in 2012 or a 48% increase on a per share basis.

On a GAAP basis, net income applicable to common shares for the nine months ended September 30 2013, was $128.2 million or $1.12 per share compared to $75.1 million or $0.82 per share for the same period in 2012. Results were driven by strong performance from all three of our business segments.

Together they reported a 58% increase in normalized operating income, achieving $71.4 million in Q3 2013 compared to $45.1 million in third quarter last year. For the nine months ending September 30, 2013 the three segments reported normalized operating income of $261.6 million compared to $159.7 million for the first nine months of last year or a 64% increase year-over-year.

Operating income has been normalized for the $37.5 million pre-tax gain on the sale of the PTP pipeline and the provisions taken of approximately $19 million on certain non-core gas and utility assets which we plan to sell. As we have mentioned in the past, we have been looking to dispose off some of our smaller non-core assets and we are now in active discussions with potential buyers for these assets.

We also normalized operating income for the joint venture development cost incurred in moving the energy export initiative forward. Operating results were driven primarily by higher throughput in gas segment, higher power generated and higher power prices realized in Alberta and the addition of the U.S.

utilities added in August 2012, as well as the rate base growth in our Canadian utilities. Interest expense for the quarter was $25.2 million for the first nine months of 2013 - and for the first nine months of 2013 was $75 million, my apologies.

This is higher than same period last year as a result of higher debt balances from the addition of new assets, partially offset by lower interest rates in 2013 compared to 2012. In third quarter 2013, we reported an income tax expense of $7.5 million compared to income tax expense of $5.1 million in the same quarter last year.

On a year-to-date basis, we reported income tax expense of $25.6 million compared to $27.6 million for the nine months ended September 30, 2012. We expect our effective tax rate for the full-year 2013 to be approximately 25%.

For the three and nine months ended September 30, 2013 net invested capital was $161.3 million and $941.3 million respectively, the majority of which was related to the acquisition of Blythe and the construction of the Northwest projects. We now expect our full-year capital expenditures to be approximately $1.4 million given the addition of Petrogas.

For 2014, we expect our capital expenditures to be approximately $400 million. Our balance sheet remains strong with a debt-to-total-capitalization of 54.7%.

Our payout, as a percentage of normalized FFO, for the trailing 12 months ending September 30, 2013 remains conservative at 41% which is at the lower end of our target range of 40% to 50%. Our debt maturity remains very manageable and we will continue to ensure we have ample liquidity, balance our long-term and short-term financings as well as floating in fixed rate debt in order to execute a financing strategy that supports our business strategy.

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

Thank you, Debbie. Operator, I will now turn the call over to you for questions, please.

Hi. Maybe I would just a quick question on your LNG.

Your discussions with your market participants to develop sales agreements, what structure of contract are they looking for, in terms of a Japan Crude Cocktail like contract versus a deploying arrangement and how does this comport with the JV's preferences?

At this point, I think it is premature to comment, but clearly all types of structures are under negotiating discussions with customers at this time. But what we want to ensure is a long-term relationship that works here for both parties over the long-term.

Okay, and then slightly different on the Western transmission. You talked about the TRAs will take you through to the end of the development phase.

When do you expect the development phase to be completed?

With respect to the preFEED stuff that we are doing. David, this is David Harris.

Probably as we get towards the end of this year and within the first month, two months of 2014.

Yes, I am talking PNG.

On the expansion of the looping of the line?

That's right. Yes.

The development phase is probably by June of next year. The development phase should be done.

Okay, perfect. Thank you for that.

And then maybe just a quick couple of question on the LPG. I think originally we were expecting to have feasibility all tied up by the end of this year.

Can you give us a little bit more color in terms of when in 2014 you expect your LPG visibility to tie up?

Well, we do expect the preFEED on LPG in by November, about the middle to the end of November timeframe. And then there is always some additional analysis going back-and-forth.

So we will probably be in position to have some lockdown numbers as we get towards the end of the year, as we had indicated to the first month, maybe month and a half of '14. David Noseworthy - CIBC And then is it FID that you expect to make in 2014?

That would be a potential. Yes.

Okay, and then just on your Petrogas acquisition. How should we think about your sensitivity and exposure to NGL prices and oil prices subsequent to the acquisition?

Not significantly changed when we look at the business. It's a lot of straight margin business.

And we don't see a lot but it does enhance, we expect to see better net back on our actual volume production of LNG than we have traditionally received. So we do see an uplift in our existing business.

Excellent, and the last question on Petrogas. Does the acquisition contemplate any kind of ROFR for the three owners now?

Yes.

Thank you very much. Those were my questions.

Thank you. Good morning, everybody, and I apologize.

If I could go back to the timeframe that David was talking about, just to make sure I have got this. So with respect to the LPG preFEED concludes or is that when everything with the LPG would potentially come together and we could make an FID at that point?

I just want to make sure I have got the right stats here.

Yes, more the latter. When you have got a preFEED and it is always to a fairly large volume of work that has taken place.

So the preFEED is on track as we previously projected it to be in, in November. And then you obviously run through the details and go through the design, commercial terms and the like.

By the time you work through that, we anticipate that being or concluding by the end of the year into the very beginning of Q1 of 2014.

Excellent, and then with respect then to LNG. My last notes, where we kind of had the FEED concluding in early 2014.

Is that still the case?

That is correct.

Okay.

And just to clarify, that is preFEED. Right?

PreFEED.

You have preFEED and then once you get your arms around the details and the numbers, then you move into a FEED phase. The preFEED for LNG is on track.

Okay. Is it safe then to say, that since we haven't officially concluded preFEED with either that cost estimates at this point?

Care to hazard a guess?

No. That is premature.

I mean these are very large complex projects and it wouldn't be wise for us to try and get any number at this point.

I understand completely. Then maybe just a last question, also going to Petrogas as well and understanding that, this is a lot of straight margin business.

Can you tell me with respect to the $2.7 billion, for instance, of their revenue, has that been a relatively stable amount over the last, either one year or two years? Or maybe a better way to ask it is, of the $0.10 accretions, are there any major market assumptions that we can follow externally to gauge if that $0.10 can move up or move down, as we move forward?

I wouldn't, say from margin, I would say that revenues have been growing with the business consistently and on track. A number development projects that they are working on, that will continue to growth.

I guess that margin is the health of the production of liquids and in North America and demand is probably the best that overall indicator. No direct pricing, in terms of commodity would be a very good indicator, I would say.

Okay. So basically just volume?

Industry volume flow?

Yes.

Okay. Thank you.

Just a couple questions here on the asset sale. Can you identify the dry gas assets that are, and utility assets that might be expected to be sold?

And I am thinking about how much operating capacity and the operating areas that might be contemplated here.

We are probably reducing just under 20% of our facilities and average capacity is less than 10 million a day. So the small facilities and for shareholders who have been around a long time, we are ending this Highway 41 strategy that we started the company on along the Alberta-Saskatchewan border.

So those are the assets that we are looking at disposing off and consolidating at. So no impact on volume to speak of or we expect at the end of the day probably a positive cash flow from that.

Okay. There is not going to be any additional CapEx associated with site reclamation or anything of that nature?

We have fully provided for that.

Okay.

These are all essentially sweet small facilities getting outted.

Right. So there's not a big liability anyway.

Just with respect to the LNG. As you move forward there, I am wondering if in the company's thinking about the strategy, if it would undertake just the positioning on the liquefaction plant or if it would undertake a position in the actual marketing of the output from that facility and take any sort of market exposure on the LNG?

We wouldn't do anything on LNG that would materially change our risk profile. So that's a given, in terms of a strategy and how we are structuring it.

So I guess that's the best answer to your question.

Okay. Thank you.

Hi, good morning. Just on NTL.

Are you committing material resources to help BC Hydro out? And as you near completion of Forrest Kerr, can you direct any of your resources or incremental resources to help the NTL construction?

No, not at this time. We are always willing to support BC Hydro.

They have been doing a very nice job along with their contract about. We have seen a significant amount of progress over the last two to three months.

They have come a long way. They are actually almost complete with their foundations as well as their structures and should be in very good shape by the end of this year getting ready to move into more advanced stringing of the line.

It got just over hundred kilometers of the line strung already in the Northern section. But we work closely with them.

We talk with them on a weekly basis and anytime we can support each other, which we have on occasion, we have done so.

Great. Thanks, David.

And then this is probably again for you. Just on Volcano.

You have moved the timeline up to 2014. Just any more granularity as to when in 2014 you have accelerated the in-service?

I would say, maybe consistent in and around the same timeframe of Forest Kerr, give or take a few months either side of that.

Okay, so that mid-2014 date? Okay.

And so what's allowed you to basically accelerate it by pretty close to 12 months?

There are a couple of things. We have been pacing well ahead of schedule on Forrest Kerr.

So again, we are going to free up and allocates some resources and take advantage of synergies of three projects growing together. Mother nature is always good to have on your side.

So mother nature has cooperated quite well with us over the last year and a half. We have seen a very low winter up front.

I guess, this is the time of the year usually you can get a lot of snow. We haven't seen that.

The soil conditions have been great. The other thing too to keep in mind for yourself and the folks on phone.

Volcano is significantly different than the other two projects. Right?

We are not doing any tunneling for Volcano. This is a penstock design that we just dig a trench and we actually bury it.

So the construction aspects of it are much less complex and simpler. And so is the same for the powerhouse.

Okay. Last question here, just on Petrogas and optionality.

A lot of the focus of conversations has been on how Petrogas can improve your NGL netbacks and then the LPG opportunity. You know, we have had some discussions recently just about how you like to look for upside optionality in assets.

And I am wondering, can you just talk about the potential to deploy capital intro Petrogas' core business? What type of projects and what geography?

,Clearly we are looking at deploying just one in the fall with looking at Fort Saskatchewan storage cavern there, in a joint venture with ATCO. Those type of things as well as additional storage capability in Midwest, U.S.

are just a couple of examples.

Okay. That's great.

Thank you very much.

Hi. Staying with Petrogas opportunities.

Are there any big capital projects or meaningful capital projects underway at Petrogas on infrastructure currently?

None of significance currently under construction, but there are some - one planned mainly around storage facilities. Most probably this is more significant and is currently contemplated.

Had they announced a partnership with ATCO?

There is a press release, some time in August, I believe, ATCO press release, that I believe, maybe in July. So it was in summertime.

Okay. Thank you.

Still on Petrogas. I am just wondering about your accretion guidance on the $0.10.

I don't know if you can break that down at all roughly between how much is from the Petrogas business standalone versus how much is the uptick on value of AltaGas' existing NGL production.

Its all Petrogas.

So is there potential then, David, for the accretion to be really higher than $0.10?

Well, we will clearly be pushing to David Harris for the accretion to the higher.

But is it not, given that if that's all just Petrogas standalone, you guys have said pretty clearly that it helps with NGL marketing?

Yes, and we haven't - the question is the quantum and we just didn't want to get too far ahead of ourselves on accretion.

Okay, and my last question is on accretion. Debbie, is the accretion assuming, I think there was $100 million of equity out of $440 million total acquisition cost?

That is the assumption.

Okay. Thank you very much.

Those are my questions.

Good morning and thank you. Just on Petrogas.

How much of Petrogas' volumes will be coming from AltaGas' production versus the NGL production of others?

They move about 100,000 barrels a day of liquids. So, we would be less than 10% of the current, and they currently move a lot of our production already.

Is any single customer of Petrogas larger than 10% of the total?

If it is, it's one of the majors. But they are not overly concentrated.

And has any customer changed their dealings with Petrogas, given that AltaGas is involved? For example, does Petrogas ship any competitor volumes?

Or have companies that have relationships with AltaGas joined more closely with Petrogas?

Not that I am aware of at this point, but we joint venture with a number of our, I am not sure, competitors or co-investors in energy infrastructure. So not that I am aware of.

We are talking about some additional opportunities on both sides. So I don't think it is material in that.

Finally, could you discuss the possibility of expanded volumes at Gordondale or the possibility of another Gordondale-type investment in the Peace River arch area?

We are constantly looking at new investments and currently getting close to hopefully filling Gordondale. We have built the flexibility to sale of that facility and would do that if producer demanded that.

Well, thank you. Those are my questions.

Thank you, operator. That concludes AltaGas' third quarter conference call.

I would like to thank everybody for joining us today and I am available for any follow-up questions after the call.