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

Linda Ezergailis – TD Securities David Galison – Canaccord Genuity Ben Pham – BMO Capital Markets Robert Kwan – RBC Capital Markets Patrick Kenny – National Bank Financial Steven Paget – Firstenergy Capital Winfried Fruehauf – W. Fruehauf Consulting

Thank you. Good morning, everyone.

Welcome to AltaGas's fourth quarter and year end 2015 conference call. Speaking today are David Cornhill, Chairman and Chief Executive Officer; David Harris, President and Chief Operating Officer; and Tim Watson, Executive Vice President 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.

As announced last year, I'm stepping down as CEO on April 15th of this year. I plan to remain as Chairman of the Board and remain very active in strategic development, capital allocation regarding major investments, financial strategies, and stakeholder relations.

In addition to the normal chairman's duties, I'll focus on insuring the corporate culture is maintained and enhanced. 2015 was a very challenging year.

We saw significant headwinds in Alberta power prices and frac spreads, and tailwinds in the weakening Canadian dollar. Even with these challenges, we saw EBITDA growth of 7% in 2015 over 2014.

To better understand our performance and strength of our business strategies, one should take out the impact of commodity and currency. If we hold both currency and commodity flat year-over-year, we would see the following performance: EBITDA up 15%, normalized net income up 15%, and earnings per share up 6%.

These numbers show the clear strength of our business and business strategies. We expect growth in 2016 at similar rates.

David Harris has reviewed the capital spending plans and has reduced the capital spending plans by over $100 million in 2016. This reduction in spending is not expected to negatively impact 2016 performance.

As a result of both lower Alberta power prices and the higher costs resulting in the Alberta government's change to carbon pricing, we have fully impaired the book value of our investment in our PPA. As a result of this change in law by the Alberta government, AltaGas is considering exercising our right to terminate the PPA.

The consortium, the Douglas Channel consortium has been unable to secure meaningful off-take agreements for the project. We have made significant progress in development and permitting of the project, and we believe the project could deliver LNG to Japan at very competitive prices.

However, without a meaningful off-take agreement, the consortium can no longer continue the development of the project. We will continue to work with the Haifa and support them in every way possible to realize our joint dream of seeing LNG development on the Douglas Channel.

The sale of a number of small FG&P plants to Tidewater is expected to close in early March. This sale allows AltaGas management to focus on optimizing our larger plants and developing larger scale opportunities as part of the Northeast BC strategy.

I will now pass the call over to David Harris for remarks on the company's performance and operations.

Thank you, David, and good morning everyone. Despite the commodity challenges of 2015, we were able to grow normalized EBITDA by 7% and deliver funds from operations comparable to 2014.

Normalized EBITDA for the year was $582 million compared to $546 million in 2014. Normalized FFO for the year was $470 million compared to $472 million in 2014.

Full year 2015 normalized operating income from operations segments was $392 million, down slightly compared to 2014. In 2015 we achieved $106 million in normalized operating income in our power segment, a 63% increase over 2014.

This was driven primarily from the addition of Forrest Kerr and Volcano Creek. These assets more than offset the significant decline we saw in Alberta power prices, which averaged just over $33 per megawatt hour for the year compared to almost $50 per megawatt hour in 2014.

We achieved $181 million in normalized operating income in our utility segment, a 9% increase over 2014. The growth in normalized operating income was driven by customer and rate based growth combined with favorable foreign exchange.

In our gas segment, we achieved $105 million in normalized operating income, down from $167 million in 2014. The lower operating income was driven by significant lower spot NGL frac pricing, which was down 75% from 2014, lower earnings from Petrogas, and third party pipeline curtailments.

We also had to plan major turnarounds in Harmattan and Younger in the second quarter of 2015. Fourth quarter normalized operating income from the operating segments was $118 million compared to $114 million for the fourth quarter of 2014.

In power, normalized operating income was $31 million, a 94% increase over Q4 2014. This was driven primarily as a result of strong results from Forrest Kerr and Volcano, the startup of McLymont and the gas fired assets acquired in the US combined with a stronger US dollar.

These gains were partially offset by the impact of the record low of $21 per megawatt average Alberta power prices. Utilities delivered normalized operating income in the fourth quarter of $60 million compared to $57 million in Q4 2014.

This was driven by customer and rate based growth combined with favorable foreign exchange, and the early approval of SEMCO's main replacement program, slightly offset by warmer weather in Michigan and Alberta. Normalized operating income from our gas business for fourth quarter 2015 was $27 million compared to $41 million in Q4 2014.

This is down due to the significant lower commodity price environment, lower process volumes, and the impact of third-party pipeline curtailments, which continued into Q4. Echoed earnings from Petrogas was also down quarter-over-quarter.

Looking ahead to 2016, we have started the year with a very strong financial position and a strong outlook. We are uniquely positioned to deliver approximately 20% growth in normalized EBITDA based solely on our fully contract and unregulated assets.

We also expect approximately 15% growth in normalized FFO and approximately 10% growth in normalized FFO per share. The primary drivers behind this growth will be full year contributions from our newly acquired Tracy, Hanford and Henrietta facilities, a full year of McLymont and a partial year from our Townsend shallow-cut natural gas processing facility.

As David mentioned, we are very cognizant of the headwinds facing producers in our midstream business. We are focused on operational efficiencies, lowering cost to producers, and maintaining high availability, thereby helping producers.

To date we have not seen any material volume declines at our key gas processing facilities, but we recognize this is a potential under the current environment. To this end, we continue to make significant progress on our Northeast BC strategy through which we are also working to deliver higher value to our customers.

The Townsend facility is approximately 75% complete and is on track to be in service by mid-2016. With the current environment, and our in-house construction expertise, we expect to bring the facility in under budget.

We also completed a 25 kilometer gas gathering line, which are under a 20-year take-or-pay with Painted Pony, and we have started construction on two liquid egress lines and a truck terminal on the Alaska Highway. The liquids lines and truck terminal are expected to be completed in Q3 2016.

Our liquid separation facility near Fort St. John is also progressing.

We completed the front-end engineering and design study in January, and we continue to work through consultations with First Nations and key stakeholders to ultimately be able to achieve our permits and reach an FID decision later this year. Our Ridley terminal propane export site is no different.

We have moved into the engineering phase and are working closely with First Nations, government key stakeholders, and expect to reach FID later this year. We are very excited about Ridley as it brings together the full NG value chain and offering for producers in Western Canada, with a design capacity to ship approximately 40,000 barrels per day of propane, and with significant expansion potential, this truly can be a game changer for our industry.

Throughout the entire value chain on processing, liquid separation, storage, logistics and exports, we can offer producers lower construction costs, lower operating costs with higher reliability, and high NFX through new markets. As a result of our announcement in January on the Ridley export terminal, we have seen a significant step up in interest from producers for both Ridley and our Northeast BC liquid separation facility.

AltaGas will contract for the majority of the capacity for these facilities with credit worthy counterparties for multiple years in order to assure recovery of capital and operating costs prior to making our FID for these opportunities. Looking at power, as David indicated earlier, we are evaluating the impact of the new climate regulations on our Sundance PPA and considering exercising our right to terminate the PPA under change of law provisions within the PPA.

We are also looking at the potential opportunities to new generation that will be driven by the shutdown of coal in the province. AltaGas is well positioned to participate in both natural gas-fired generation and renewables in the province.

That said, we will wait for the government to provide more clarity on market structure and the true requests for replacement power. Moving over to our US power business, we continue to move discussions forward in the desert southwest with respect to extending our Blythe contract and off taker opportunities for Sonoran, the energy and balance market, and the move towards regional transmission operator all bode well for our development projects.

As utilities, non-utility generators and large generation new use continue to determine their future resource needs, we have seen increased interest from them as it relates to our expansion opportunities. As we start out 2016, we have a strong diversified base business coupled with a healthy balance sheet.

We will continue to drive operational and economic efficiencies across our enterprise. We also have a lot of exciting opportunities we want to bring to fruition, but as always, we will be disciplined in pursuing them.

I will now pass the call over to Tim.

Thank you, David. Good morning, everyone.

Financial discipline and effective risk management are fundamental cornerstones of the corporation's strategy. 2015 was a year which highlighted the full breadth and extent of our diversified business platform across all business units and geography, as well as the robust nature of our assets and the strength of our balance sheet.

To underscore this, 2015 normalized EBITDA was well balanced. Approximately 30% came from contracted power, 40% came from regulated utilities, and 30% came from largely contracted midstream business.

To emphasize a point already heard this morning, our normalized EBITDA for full year 2015 did increase 7% to $582 million, compared to $546 million last year. For fiscal 2015, AltaGas reported normalized funds from operations of $470 million, or $3.41 per share, down slightly from $472 million, or $3.72 per share achieved in 2014.

Normalized FFO per share was down primarily due to lower distributions received from Petrogas, as well as higher current income tax expense. A dividend of $54 million was received from Petrogas in 2014, compared to $11 million in 2015.

Cash was in fact retained at Petrogas in 2015 to fund its capital program across various assets. Normalized net income for 2015 was $140 million, or $1.02 per share compared to $165 million, or $1.30 per share in 2014.

Normalized net income for the full year was lower due to lower operating income, primarily in the gas segment as you've already heard, as well as due to higher interest and income tax expense. On a US GAAP basis, we recorded net income applicable to common shares for full year 2015 of $10 million, or $0.07 per share.

Total normalizing adjustments for the year were $130 million on an after tax basis. The majority relates to provisions for certain assets and investments, including the investment in Painted Pony shares, the Sundance PPA, investments to yearend in the Douglas Channel project, certain wind development projects, the gas processing assets held for sale, and Inuvik Gas and Ikhil joint venture.

For the full year 2015, interest expense was $125 million compared to $111 million in 2014, primarily due to increased assets and service and higher interest costs and US denominated debt due to the stronger US dollar. Depreciation was $212 million in 2015, compared to $173 million in 2014.

This again was mainly due to new assets placed in the service as well as due to the strong US dollar. For full year 2015, income tax expense was $48 million compared to $19 million in 2014.

Income tax expense was higher due primarily to the increase in the Alberta corporate tax rate for 2015, and the charges to income that did not attract tax recoveries that I alluded to earlier. Net invested capital in 2015 was just over $1.5 billion.

This was primarily comprised of $27 million for maintenance and turnarounds, $597 million of growth capital balanced across all three business units, and approximately $882 million for the acquisition of the San Joaquin contracted gas-fired power assets in North California, formerly called GWF, acquired in late fourth quarter 2015. AltaGas's balance sheet is in a strong position and we are fully funded for 2016.

As at yearend 2015, debt to total capital was 48%, which is well below covenant levels, and also in line with or below historical levels. Cash on hand was approximately $293 million.

We also have approximately $1 billion available on our credit facilities, and a principle credit facility was extended to a December 2019 maturity. AltaGas has a multitude, or has a multiple set of sources for funding, ensuring that we are not overly relying on any one particular market.

2015 in fact was a great example of that with successful Canadian dollar and US dollar financings in term debt and common shares, as well as an attractive 5.25% preferred share offering complete in November, which raised $200 million. AltaGas currently expects to deliver overall normalized EBITDA growth of approximately 20% in 2016 compared to last year.

In 2016, we expect to benefit from a full year from the McLymont Creek hydroelectric facility, as well as the Tracy, Hanford and Henrietta natural gas generation facilities acquired in November 2015, plus a partial year from the onset of the Townsend facility. The utility segment is expected to report increased normalized EBITDA in 2016 driven by rate based and customer growth.

The overall forecasted growth in normalized EBITDA includes lower commodity hedge gains compared with 2015, as well as higher operating and administrative costs due to new assets placed in the service. Based on 2016 budget estimates, we expect approximately 40% of normalized EBITDA to come from contracted power, and 37% to come from regulated utilities.

Together these two businesses will represent approximately three-quarters of total 2016 EBITDA. The average term of our contracted power assets is 15 years.

The balance of 2016 expected EBITDA of 23% will come from midstream. Within midstream, approximately 96% of expected EBITDA is contracted.

Almost half is through take-or-pay arrangements with an average term of about 13 years. The balance is typically cost of service or fee for service arrangements.

Over 90% of AltaGas's customers in the midstream space, or overall, excuse me, overall in the company are investment grade. And within AltaGas's gas segment, approximately two-thirds have investment grade credit ratings, and no material allowances have been incurred and receivables are consistent with historical experiences.

AltGas's 2016 normalized EBITDA growth projections assume no near-term recovery in commodity prices. If commodity prices do recover, AltaGas is well positioned to deliver additional normalized EBITDA growth.

It's important to note also that approximately 50% of expected 2016 EBITDA will come from the US. This shows the extent of AltaGas's highly diversified business platform.

Some of this US dollar exposure is naturally offset by US dollar denominated depreciation, interest on US debt, as well as dividends on US dollar denominated preferred shares and US income tax expense. AltaGas continues to drive its strategy to grow its highly contracted clean power generation portfolio.

As of December 31st, 2015, approximately 62% and 21% of total generation capacity came from gas-fired and renewables respectively. While the Sundance PPA has been a great investment for AltaGas since acquiring it in 2001, it's no longer having a meaningful impact.

In 2016 no contribution is expected from the Sundance PPA. Furthermore, less than 1% of 2016 EBITDA, including our small cogen units, is expected to come from the Alberta power market.

As you can see, Alberta power prices are inconsequential in terms of 2016 financial performance for AltaGas. On February 2nd, 2016 AltaGas announced the sale of certain non-core natural gas gathering and processing assets located primarily in central and northcentral Alberta.

The sale is part of our overall strategy to focus on larger scale opportunities in the gas segment that support the overall northeast British Columbia strategy. The transaction is expected to close in the first quarter, as David mentioned.

These non-core assets represent less than 2% of expected 2016 normalized EBITDA for AltaGas. AltaGas currently expects normalized funds from operation to grow by approximately 15% in 2016, driven by the factors noted above for normalized EBITDA, partially offset by higher financing costs related to the new assets acquired, as well as new assets in service, and higher current tax expenses.

2016 depreciation will increase over 2015 levels to account for the McLymont and San Joaquin power assets and other additions to our infrastructure portfolio. An approximate level to expect for 2016 depreciation is $270 million in round numbers.

Our expected capital spend for the year is between $550 million and $650 million, which is predominately related to growth, including number one the completion of Townsend, which is backstopped by a 20-year take-or-pay arrangement. Number two, investment in regulated utilities.

And number three, our contracted Alton natural gas storage project. We also expect to start moving our Ridley Island propane export terminal forward beginning late this year, subject to FID, and will start to allocate capital for that.

Maintenance capital for our gas and power businesses in 2016 is expected to be less than $40 million. This total capital in 2016, along with future capital investments in the regulated utilities business, will result in approximately a 50% increase in AltaGas's EBITDA by 2020 relative to 2015 levels of $582 million.

Discretionary development capital beyond the 2016 amounts that I've just noted, would only serve to further increase future EBITDA growth further.

In terms of hedging for 2016, we expect to have anywhere between 2,000 and 3,000 barrels per day of extraction volumes exposed to frac spread. This represents less than 6% of total produced extraction volumes within AltaGas.

We don't have any frac hedges in place at this time, as David noted earlier I believe. Key sensitivities for 2016 include for every plus or minus $0.05 change in the Canadian/US foreign exchange rate, EBITDA impacts $14 million.

For every plus or minus $1.00 per barrel change in frac spread, EBITDA impact is about $1 million of EBITDA. For every plus or minus $1.00 per megawatt hour change in Alberta power price, the EBITDA impact is about $2 million.

And for every plus or minus 10% change in gas volumes, EBITDA impact is about – ranges from about $7 million to $11 million. Financial results from Petrogas are expected to be above 2015 levels.

In part this will be driven by continued strong performance at the Ferndale LPG facility, which AltaGas operates on the US west coast. Impacted sectors in 2015 for Petrogas included reduced activities that were impacted directly or indirectly by the upstream sector, including fee for service at terminals, demand for drilling fluids and trucking utilization.

We expect to see some stabilization on those fronts, as well as results from new investments and selective storage and terminal investments in both Canada and the US that Petrogas is invested in, as well as Ferndale increase shipments, as I mentioned previously. And I just want to put this a little bit in perspective in anticipation of maybe some questions on this.

You know historically speaking, Petrogas equity earnings have ranged from about 1% to 3% of total EBITDA for AltaGas. So to do some math for you, plus or minus $5 million of equity earnings swing factor in Petrogas itself has less than 1% impact on AltaGas's overall EBITDA.

Or let's put it differently, for Petrogas common dividends historically they've been about 5% of our total FFO. And again, to do some math for you, a plus or minus $5 million shift in those dividends represents about 1% of our total FFO.

So it's quite contained in terms of the impact, but we do see upside as markets stabilize. AltaGas, just to wrap up quickly, AltaGas seeks to optimize risk and reward, ensuring that our returns are commensurate with the level of risk assumed.

We do see many exciting opportunities for further growth across all three business lines. In midstream, the currently depressed commodity market conditions are accelerating a trend to producers seeking to conserve capital and monetize non-core assets.

AltaGas is well positioned to build or acquire gathering and processing infrastructure from or on behalf of producers. Due to the integrated nature of our gas gathering and processing assets, AltaGas is uniquely positioned to work with producers, providing services across the integrated value chain from wellhead to the coast and exports.

Within our power business we expect to have a smooth integration with our new California power assets. In addition, we're actively looking to extend certain PPAs and bring forward attractive brownfield development opportunities at our existing assets.

Within utilities, we expect continued rate-based and customer growth, and will target selected growth projects as well. So in conclusion, we have a strong balance sheet, conservative payout ratio, and good access to capital.

We are focused on maintaining our financial strength. We also have flexibility in our capital plans, and will be disciplined in the opportunities we pursue.

Let me turn it back to Jess.

Thank you, Tim. Operator, we will now take questions from the investment community.

Thank you. A question around your capital allocation decisions.

You've been selling some less core assets. I guess I've got a three-pronged question around that.

Do you see any other less core assets potentially that you could sell? And how do you think about that versus you know your dividend growth expectations and some of your other financing plans in terms of accessing the capital markets given some of the volatility that we've seen?

I'll start and I'm sure there might be other that want to chip in on that question. You know, let's start with the first part of that, because that's the one I remember.

Less core assets and any anticipation of doing further non-core dispositions. That's part and parcel with what we do year in, year out.

I mean it's a natural evaluation and assessment that we would undertake. And as you're probably well aware, Linda, even in 2014 we did about $70 million I think of non-core dispositions, so it's certainly something that isn't unique to 2015.

You know going forward, we'll continue to assess that. Our NP&P business is more streamlined today and will be once the Highwater deal closes.

And we're getting closer and closer to being down to just a core set of very important plants, but that's something we'll continue to evaluate. I think you were tying it a little bit to dividend growth and you know our board hasn't taken any decisions yet.

It's quite early in 2016 in terms of dividend plans, but we would expect that dividends will generally correlate with the underlying cash flow generation that the business produces.

Thank you. And can you just comment on capital market volatility and how that informs your financing plans and kind of what the plan A, B and C might be in terms of preferences?

Yeah, well you know as I said, I think what we are in fact, if you look at our sources and uses, and I believe it's probably in slides too, we are fully funded. We really do have a very minimal amount of capital that exceeds the internally generated cash flow in our business in 2016 based on our formal 2016 budget.

We have been nimble in terms of our ability to access capital markets, and again 2015, as I said earlier, has been a great example of that across various products that we've gone to capital markets on. We continue to believe we have strong access to the capital markets.

This week alone you've seen pretty strong response to other peers in our sector. And if you look at our cost of capital on the debt side, it's extremely competitive with our peers, and so we remain quite confident on that.

Okay, thank you. And a follow-up question on Douglas Channel.

Is there anything that could potentially reinvigorate the project down the road? And have you guys dropped your import tax dispute with the federal government or is that still underway?

Hi, Linda, it's John Lowe. On the duty issue, we did receive a favorable decision from the CBSA and the duty is zero, which is the good news.

The bad news is, is the market is quite unfavorable. As for reinvigorating the project, it is open to individual consortium members to pursue the project.

As David said, that's something that we are interested in pursuing. Where that goes to right now, I can't tell you though.

Okay. And just kind of a final question on your partnership with Idemitsu, is there anything else you guys are pursuing with them at this point related to pet/chem or anything like that or is it substantially at this point more the LPG side of the equation?

There's nothing on the pet/chem side with Idemitsu, and it's really more on the liquids and the LNG side.

Great. Thank you.

Good morning, everyone. Just had a quick question on the Douglas Channel off take agreement.

Was the difficulty in securing an off take you know more to do with pricing or the term structure, or just overall lack of participants? Just wondering if you could give a bit more color on that.

Well I think it's both. It's pricing and the surplus quantities of LNG on the market right now.

And then just on the gas segment, you had mentioned about two-thirds of your customers are investment grade. So the remaining third, is there a concentration of customers there or is it pretty spread out?

And maybe, you know, what percentage of EBITDA do you expect them to be? And also maybe if there's any credit enhancements that you're taking with them.

I'll start I guess. So first of all I guess we do have built into our contracts various levers which enable us to be flexible in terms of different market environments.

And we do actively, proactively take steps under the terms of those contracts as required. We have a broadly diversified book of gas producers that we deal with, and as I indicated earlier, that split is indicative of that between investment grade and non-investment grade.

We haven't disclosed by EBITDA because those are sensitive terms for the contracts that each producer signs up to, so we're not positioned to get into that level of detail. But you know we do have a broadly balanced and diversified book.

We are not overly reliant on one single producer across any of our gas midstream asset base.

Okay. And then maybe just a housekeeping question.

Do you have an estimate of how much dividends you're expecting from Petrogas in 2016? I know historically you said that you were looking for $30 million to $40 million on an annualized basis, but just kind of looking at this year what you're looking for.

We don't have a specific number yet. I'll say a couple things, and I'm sure others might want to join in on this.

But you know if you look historically at what Petrogas has paid out in dividends, and take it over several years not just a single year, you know the dividends have broadly speaking represent about close to a 100% payout of earnings. So we don't expect that to diverge going forward.

We, as I said earlier, we do expect financial results in 2016 to be improved over 2015, but to be frank they're just wrapping up their fiscal yearend. We need to sit down with them and go through the next 12 months of their fiscal year to fully understand what they're formally going to be planning.

Also I guess in terms of the dividend, it's fair to say that we continue to have discussions with the three owners, or between the three owners in Petrogas, to make sure we're in full alignment, and that's been alluded to in our previous quarterly calls, and there's still some discussions to cover off there.

Thank you very much.

Good morning, everybody. I wanted to talk about your EBITDA guidance a bit more for 2016.

And I'm wondering what commodity price assumptions are you using with Alberta power and frac spreads.

I'll turn around and I'll start with the Alberta power prices and frac spreads question. On Alberta power, we expect, you know for the year on average, it will probably average somewhere in the high 20s to maybe on a good day to low 30s.

And frac spreads, as it relates to right now, we don't see that much of a movement. It's doing just over almost $4.50 right now and we think the year may close just under $6.00, somewhere around $5.80.

Okay, so I mean as it spots about what you're seeing right now, $15.00 or so, there's probably about $30 million or so potential downside?

No, because that's - you know, we don't have anything hedged going forward on the frac side, so and we're pretty much at the bottom with respect to where we see the markets going. So if anything, if there's any movement up, it will be a slightly uptick.

Sorry, I meant more the Alberta power side, with Tim's comments about the $2 million in sensitivity.

Yeah, I mean we're - our expectations are, in terms of Alberta power price, are in and around where the current market is. And I said earlier, we're not expecting any significant rebounds in that market in 2016.

As per our normal practice, we do implement hedging from time to time in that business line, and this year's no different.

Okay. And I'm just wondering, and not to pick on something that's such a small part of your business, 1% or so, but can't that technically become negative to your guys?

Or do you feel that you've hedged enough for 2016 that you can cap the downside on just the recent spot pricing we've seen in the marketplace?

Well we're uniquely positioned to some extent because, as you're well aware, we have other business lines, you know commercial for example, customers in industrial, customers and that allows us to have more flexibility and frankly be more nimble in terms of how we set up hedges to protect the power cash flows. So we - and again, that's no different than what you see in the previous years where we actually have had quite impressive results in terms of the actual hedges that we've been able to affect well above market.

So you know we don't see anything different in terms of that, and obviously we're watching the Alberta power market generally. We, like you, are well aware via the new climate change rules being proposed, and are assessing what that means longer term for us.

Okay, and if I may, just on the top of the currency USD, are you assuming what you - what was at your investor day or are you picking up the recent strength, particularly with the GWF guidance you had before?

No, we're - to be absolutely truthful, I forget what we actually said on investor day. It seems like a long time ago.

But we'd be a little more conservative than where the market is currently. We don't move our expectations up and down given the volatility we see in that market place, so we're a little more conservative than where the current and recent FX rates have been.

Okay, great. That's all.

Thanks, everybody.

Good morning. Just was wondering, some of the commentary you've had around the Fort St.

John liquids project and then LPG, and specifically that you'd be looking to contract for a majority of the capacity prior to FID that sounds a little different than what you said on prior calls. I'm just wondering why might have changed.

I'll field that, Robert. I mean I think on prior calls we talked about maybe a certain percentage of what we contract.

What was see is, as a result of the announcement on ITI that we did in January, there's certainly a heightened interest from producers. So it's certainly opened up the door a little bit more for probably a predominance of contracting with respect to ITI and that just daisy chains down as the producers understand the full value chain to them for opportunity with diversification and markets.

So as the opportunities present itself, we'll take advantage of that to secure a greater amount to recover our capital and operating cost.

Got it. So is it really margins to function that you've seen increased interest and so that your expectation is that you will have the contract signed or put differently if you still are not able to get people to put pen to paper is the old thought in place that you would still go to an FID without material contracting?

No. I mean I think what we're seeing right now is there is such a heightened interest in the conversations we're into we're fairly confident we'll be 50% and north of 50% before we move into contracting.

And that's not a surprise, it's just once we made that announcement, now you're starting to see the picture of reality come into play for the producers.

Got it. Okay.

If I could move to funding. You're talking about being able to fund almost entirely within internal, and if there's any extra little bit you've got the liquidity and the credit lines.

I'm just wondering, how does that plan play into specifically S&P and the negative outlook that they have on the credit rating?

Well I think the funding, the sources and uses are just one aspect of how you think about our overall balance sheet, and so sources and uses is probably one of the first things I'll look at. But I think we have to be cognizant of all the factors.

We have to obviously know where our covenants are, which are well above where we're at currently. We have to be cognizant of the issues that S&P and DBRS, our two primary rating agencies, talk to us about.

And you know suffice to say that from an S&P perspective, we actively are having dialogue with them. We have a pretty good sense for where to go with them on that.

And as we get into 2016 and beyond, we'll be doing more things in that regard.

So I guess, maybe if I can ask it just a little differently, but the plan that you're kind of sending out here of funding out of the DRIP and internal cash flow, maybe a little bit on the credit lines, in terms of the sessions you've had with S&P, is that enough to get them off the negative watch? Or is - you know is the anticipation that you might have to do something else if we don't see a rebound in the commodity prices, and specifically as well if you did acquisitions, you know would you be able to avoid kind of over-equitizing the funding?

Well I mean, as you know, Robert, our business is very dynamic. You know we have three different business lines and they move in different ways, and we proactively manage them.

So you know I think when we think about new investments, we very much think about ensuring that they do contribute, move up the key metric that S&P is focused on, which is funds from operations to debt. And you know we looked at, in our projections and our budgeting, we looked to increase that ratio over time through various measures.

We have lots of levers we can pull in that regard, both from normal day-to-day investments from optimizing your own business, taking costs out, as David talked about earlier, and looking at new opportunities that would positively impact that as well.

Got it. And maybe if I can just ask one last question just on the Tidewater shares and your approach, how you're thinking about it.

I guess if we map back to the Painted Pony investment, I think at the time it was billed as being, maybe in a different way than how we normally think about it, but it was billed as being strategic. I'm just wondering how you're approaching Tidewater.

Is it the same way or is this really just what you needed to do to get the deal done?

This is David Cornhill. Hello.

I would say it's strategic [indiscernible] at this time and they're a great team and we support them, want to support them going forward to realize their vision.

Understood. So I guess is, David, the right way to think about it of, look, you know if you become a much larger company, these are fairly small facilities that really wasn't worth maybe [indiscernible] AltaGas level?

It's taking AltaGas back 15 years.

Essentially right. So you're taking the plants that aren't really material to you and basically offloading it onto a different team that can spend a little bit more time working them.

Is that -

And create more value for them.

Right. Okay.

Great, thank you.

Good morning, guys. On the counterpart of your risk breakdown within gas, do you include Encana in your investment grade bucket?

And if so, roughly what does the two-thirds percentage drop to if you exclude Encana?

Yeah, I mean we do, and the reason we do at this stage, although we actively monitor this day in, day out, is because they do have two investment grade ratings out of three at this moment, but that's dynamic and obviously we'll continue to track that. If you take them out - I don't have precise numbers, but I think directionally you could assume that it would make our overall midstream portfolio above 50% still investment grade.

Okay, great. Thanks.

And then just a follow-up on the Tidewater deal. Can you talk a bit more about the strategy going forward?

Are you looking for Tidewater to become more of a drop down vehicle for other non-core assets? Or, David, I believe you alluded to you know you're willing to invest alongside Tidewater in some of their larger scale opportunities as well, whether it be natural gas egress in the province or you know their propane export initiatives on the west coast as well.

It's strategic. And I think we see them as a talented team and we're in constant dialogue on opportunities.

So you know we have 19%. They're an independent company.

We'll support them where we can, but they are independent going forward. If we think there's some things that we have that they could realize better value, we'll do it and it's just a respectful relationship.

Okay. And then just lastly, staying on the west coast but on the LNG front, so can you just confirm if the Triton project is also on the back burner and any potential expansion of the PNG pipeline as well?

Yeah, I'll go ahead and start and then John Lowe cam add in if he wants. But yeah, it's certainly on the back burner, slow burn, and we'll just see how the markets develop here in the coming years and if they bounce back appropriately

I think just want to add one thing. Our team has learned a lot and has a very smart, good understanding of the LNG market and ability, what it takes to deliver floating LNG facilities off the west coast.

And I think that expertise is not going to be lost within the company and gives us a huge head start, you know more powerful, a more attractive LNG market which will come sometime.

All right. Thank you very much.

That's all I had.

Thank you, and good morning. Please correct me if I'm wrong, but as I understand it you've bought some power plants that do depend on post-PPA revenues to pay back their investments.

Are you looking at taking on more exposure to this by buying more US power plants?

I'll jump in and answer that. I think what we'll be looking to do right now, Steven, is harvest the value from the existing asset base that we have, and our focus will be on expanding our existing contracting assets and bringing to fruition our expansion capability to a brownfield very, very low cost opportunity compared to a greenfield as relates to expansion capabilities at Blythe.

And that's where you'll see our focus over the coming year.

Thank you, David. Could one of you please comment on the global LPG market?

Do you believe that consumers, Japan and Korea, and other Asian markets, will be able to soak up the increased supply from North America and the Middle East and elsewhere? And do you believe in particular that the proposed Ridley export terminal will cannibalize some LPG volumes coming out of the Gulf, or will it increase overall North American exports to Asia?

Let me answer that question in reverse please, Steven. I'll start with Ridley.

Ridley should have no bearing whatsoever on cannibalizing liquids as it relates to the Gulf for the simple reason the producers alone in western Canada are thirsting for an exit. So we certainly expect that the propane liquids that will go out of Ridley will be associated with western Canadian based producers.

From a global scale, really with what we're looking at Ridley, it's really a very, very small percentage of the global liquids that's shipped on the open ocean at any given point of time. And then most of the stuff out of the west coast is going down into Central and South America, there's product that's also lifted into Europe.

So right now we're not seeing or anything that would suggest we'd see a negative headwind to exporting liquids off of Ridley. And that's just from a global perspective like that.

It's certainly fluid, but you know it's also a fairly robust market.

Thank you, David. Goodbye and good luck to both Mr.

David Cornhill and Debbie Stein.

Thank you.

Thanks,

Thank you. Regarding the $114 million of post-tax provisions, what are the amounts pertaining to the investment in Painted Pony, ASTC power partnership and the meet so partnership?

Yeah, so I think, Winfried, we have not publicly broken those individual items out. We've presented it in aggregate.

Each of them is different in terms of the nature of them and not one single one makes up that total that you see in the MD&A.

Regarding Douglas Channel, has that been written down to zero, your investment?

Yes, it has.

Or is there still a residual amount that hasn't been provided for?

No, it's been fully written down.

And I've got one more question, if I may, pertaining to foreign exchange. In the fourth quarter, and also for the year 2015, what was the net income benefit from favorable foreign exchange rates?

I'll probably, to give you the best number that we have, we'll probably need to circle back with you. Winfried, we can call you directly if that's helpful.

Certainly. Thank you.

Thank you.

Thank you, operator. And thank you everybody for joining us for our Q4 and full year 2015 results.

We are available after the call here for any follow-up questions. Thank you.