Hello, this is the conference operator. Welcome to the TransAlta Corporation 2012 Fourth Quarter and Year End Results Conference Call. As a reminder, all participants are in a listen-only mode, and the conference is being recorded. After the presentation, there’ll be an opportunity to ask questions. To join the question queue, simply press star and one on your touch tone telephone. Should anyone need assistance during the conference call, you may signal an operator by pressing star and then zero on your touch tone telephone. At this time, I’d like to turn the conference over to Brent Ward, Director, Corporate Finance and Investor Relations. Please go ahead.

Thank you, Brock [ph], and good morning, everyone. I’m Brent Ward, Director of Corporate Finance and Investor Relations, welcome to TransAlta’s 2012 Fourth Quarter and Full Year Conference Call. With me today, are Dawn Farrell, President and Chief Executive Officer, Brett Gellner, Chief Financial Officer, John Kousinioris, Chief Legal and Compliance Officer, and Todd Stack, Vice President, and Treasurer. Earlier this morning, we released our fourth quarter and full year 2012 results. We hope you’ve had a chance to review them. For those of you who are not on our webcast, we have also posted our 2012 Q4 and full year presentation on our website under our Investors section, as we will be referring to the presentation during this call. Further information will be posted after the call. All information during this conference call is subject to the forward-looking qualification, which is detailed in today’s news release and incorporated in full for purposes of today’s call. The amounts referenced in this review are in Canadian currency, unless otherwise stated. The non-IFRS terminology used in this call, including comparable earnings, comparable EBITDA, growth margin, funds from operations and free cash flow is reconciled in the MD&A. Per share figures in the fourth quarter 2012 are based on an average of 255 million shares outstanding compared to 224 million shares in the fourth quarter of 2011. For the full year, the average number of shares outstanding for 2012 is 235 million, compared to 222 million shares in 2011. Please note, the financial information has been rounded to the nearest whole number. On today’s call, Dawn, and Brett will provide an overview of our operational and financial performance for the fourth quarter, and the full year, provide an update on recent events and activities, and before going to Q&A, Dawn will provide commentary on our outlook for 2013. With that, let me turn the call over to Dawn.

Thanks, Brent, and welcome everyone. Let me begin with 2012. With clearly a very busy year for TransAlta, a year of positioning TransAlta for growth through the decade. There was a lot to do, and I’m happy to report today, that most, if not all of the challenging issues are behind us. And 2013 will be a return to more normalized level of operation for TransAlta. The repositioning of the teams into a new business model for the company has established the right configuration and momentum required to really get underneath the type of growth we want to invest in which are projects then ensure our shareholders, we continue to expect and have confidence in the long-term stability of our cash flows and income for years to come. Let me walk you through the highlights from 2012 in more detail. We spent approximately 500 million of sustaining capital in 2012, which included the inclusion of the three-year investment program in our coal fleet, that will enable us to sustain high levels of availability and upgrade our capability. A plan we put into action at the end of 2009, and that is now complete. Over the year, the extensive major maintenance program meant that we completed in the year, six major planned outages in our operated coal fleet, three major planned outages in the gas fleet, and a number of smaller planned outages in the wind and hydro fleets. And of course, through also two major outages in our none operated coal plants. We did all of these timed work, and at the same time, we were able to achieve an overall fleet availability of 90%. This means that the operating teams that TransAlta had to perform exceptionally well, under fourth outage rates. Overall, the 90% availability continues to be well…

Okay, thanks, Dawn. Good morning everyone. So as this slide shows, and as Dawn indicated, the generation segment performed well this quarter and on a year to year, over year basis delivering 27 million more in gross margin, quarter-over-quarter, and 45 million year-over-year. The increase was from all three segments, really largely driven by our higher hydro volumes, lower unplanned outages and the capacity payments from Sundance 1 and 2. I should also note that these gross margins do not include the Solomon acquisition as its accounted for as a lease, but it does show up in our comparable EBITDA and FFO numbers. One of the key drivers of our gross margin improvements in the generation segment was our availability. As Dawn indicated, we achieved 90% for the fleet year, for the whole year even with the significant planned outages in the year. In addition to an improvement in our gross margins, we realize reductions in our OM&E [ph] cost. We targeted a 5% reduction for 2012, but actuals came in at 10% reduction or 52 million better. This was primarily due to driving efficiencies throughout the organization, but also lower compensation cost. Our comparable EBITDA, and FFO were also higher in the quarter relative to the same period last year. These increases were driven by improvements in the generation segment as I just talked about and also include the acquisition of Solomon and all of that more than offsets the lower trading results. Comparable EBITDA in the quarter was 310 million up 43 million, and FFO was 205 million, up 16 million from the same period last year. For the full year, both comparable EBITDA and FFO were down approximately 30 million each, due to the lower results from our trading segment. In terms of capital for the year, we spent 439 million in sustaining capital and 57 million on productivity initiatives which was in the range we have planned. Having finished our three-year intensive major maintenance program on the call fleet, we expect to return to a more normalized level of capitalized expenditures in the range of 295 million to 335 million per year in 2013, and targeting approximately 350 million per year on an average over an outage cycle. Our spend in 2013 on projects adding incremental EBITDA, is currently estimated to be in the range of 145 million to 170 million most of which is for the rebuild of Sundance 1 and 2. So to conclude, we’re well positioned to grow and support the balancesheet, we maintain access to the capital markets for debt, equity and preferred shares, and we continue to have approximately 70% participation rate in the dividend reinvestment plans. We have only one bond maturity in 2013 which is 300 million late in the year, and we continue to maintain strong liquidity with 755 million available as of December 31st. With that, I turn it back over to Dawn.

Thanks, Brett. Let me start with a quick update on two key events. First an update on the future contract. There continues to be a lot of work being done by Puget and the commission as they work towards solutions. TransAlta’s role is to support this process, and we do expect a favorable resolution by the end of March. Secondly, this past November, we made a decision to realign the company, to ensure focus on operations and growth and eliminate duplication and cost. This initiative is on track to achieve 25 million to 30 million a year in sustainable savings by the end of 2013. I’d like to move to our market update and our outlook for 2013. As we look ahead, we see the potential for slightly higher prices in the pacific northwest. The pacific northwest continues to be driven by slightly higher gas prices as we move though the beginning of 2013. Lower gas prices have improved by roughly 30% compared to 2012. This is a significant recovery and a positive sign. In Alberta, prices are expected to weaken as new capacity, including Sundance units 1 and 2 come on stream towards the end of this year. Despite that softness over the medium term, new plants will be required in Alberta before the end of the decade as a number of coal plants retire at the end of 2019. The market is still expected to continue to grow in the 2% to 3% range over this timeframe. The recent weakness we’ve seen in spot market prices in Alberta has highlighted the important of being prepared for any kind of power price environment. We are continuing to take steps to increase our level of contractedness across the fleet to support revenue certainties. We are 85% hedged for 2013, and…

Thank you, Dawn. So that we may rotate through callers, we will take one question and one follow-up from each caller before moving down the queue. We will answer questions from the investment community first and then open the call to the media. We will then respond to individual investors to please identify yourself when asking a question. I will remind you that we do not provide guidance and that we will answer any model related questions offline after the call. Brock [ph], we will now take questions, please?

Thank you. (Operator Instructions) The first question today comes from Juan Plessis of Canaccord Genuity. Please go ahead. Juan Plessis – Canaccord Genuity: Thank you very much. Dawn, with respect to targeted availability for 2013 of 89% to 90%, you’ve gone through a high plant maintenance here in 2012 and you met this target. But with lower plant outages going forward, wouldn’t you expect your availability to edge up a little bit?

Yes. I mean, I think that’s a great point and certainly, when you look at the results for last year you would expect that. But I think in terms of our planning, we continue to push in that 89% to 90% range and if there’s any upside that comes out of the air that’ll be great. But that’s where we’re setting our targets for the team.

And I would also just indicate that that is across the fleet and Centralia obviously is the one that unique in our dispatching on the Canadian coal side as we pointed out in investor wherein 90% to 91% in our guidance. Juan Plessis – Canaccord Genuity: Okay. Thanks for that. The $11 million of finance lease income for the quarter, that’s mostly due to the following contribution, can you break out the contribution from Solomon?

It’s predominantly mainly from there. We have a lease from a smaller plant so it’s most of it. Juan Plessis – Canaccord Genuity: So $9 million or $10 million is a good run rate the Solomon contribution?

That’s correct. Juan Plessis – Canaccord Genuity: Okay. Thank you.

The next question comes from Ben Pham of BMO Capital Markets. Ben Pham – BMO Capital Markets: Hi. Thanks and good morning. First question is on Centralia. I know it’s been years since you have moved to TBR there to [inaudible] the coal. Can you just give us a quick update on the contracting profile more in terms of just what the rails and the part of the river basin coal producers?

Sorry. I’m just not sure what’s your question in terms of how we’re contracting the coal or the rail or both? Ben Pham – BMO Capital Markets: Both.

Yes. I mean, we’ve completed changing the contracts for the rail to make the cost most competitive in terms of moving the PRB coal in. So that was then right at the end of the year. And then on the PRB coal, we continued to have a mix of terms with those different PRBs so far and as we look at the production profile for the plant over the next couple of years depending on what price is due, we can either lengthen some of those contracts so can stay in the spot market depending on what we think is happening with that coal. So that’s really how we’re approaching this. Ben Pham – BMO Capital Markets: So your decline in fuel cost for this cost, part of that is reflecting those new contracts on the rail side then?

And in part, a lower coal cost as well. So all delivered rail plus the coal commodity.

It was a combination of lower rail that have pulled cost but also just – you got to watch that depending on how much we actually run and how production there is will also affect that. Ben Pham – BMO Capital Markets: Okay. Thanks. And can I just speak one more on Centralia just in the context of the Puget Sound petition coming at the end of March. Are you in discussions of other Washington based utilities right now or is everything pretty much in a standby mode right now?

Are you talking about other potential customers? Ben Pham – BMO Capital Markets: Yes.

Yes, we are. Certainly, as people go through March and see how this contract does, I think that will make difference but more importantly, I think it’s supply and demand changes around in that region and prices change. That gives people quite a bit of incentive to look at how to contract over the longer term. Ben Pham – BMO Capital Markets: Okay, great. Thanks very much. Thank you everybody.

The next question comes from Mark Barnett of Morningstar Equity Research. Please, go ahead. Mark Barnett – Morningstar Equity Research: Hey, good morning, everyone. When you highlighted the delay in about a year for Sundance 7 given some units returning to service and where you demand. Does this delay or change from your thinking around projects you might have been looking to pursue with MidAmerican just to slow things down or do you see the opportunities set across broader Canada still providing enough opportunities there?

Yes. I mean, for sure the – right now, we’re in a period in Alberta where we have to work really hard with the customers to see what their intentions are around oil sands development. There’s been a press as all of you know and have probably been following on bidding oil out of Alberta. And that potentially could affect some of the plants of oil sand producers which will affect growth in Alberta. Alberta is always a funny place. I mean, there’s a lot of discussions but then people continue to want to build their facilities because they want to get in a few and get their cash and make their money. So right now, our teams are working very aggressively to look at what those opportunities could be. At this point, I don’t think I could say definitively one way or the other whether or not it delays those plans because there’s still a lot of work to do to evaluate that. But the MidAmerican and TransAlta teams continue to work both in Alberta and in British Columbia. And for the most part, we saw a lot of that kind of load coming on. Greenfields takes a while to develop. It takes a while to build and most of the gross that would come from Greenfield in those two regions is in that 2017 to 2020 timeframe. So we still see that timeframe as being valid but it could be delayed a little bit here and there depending on how producers adjust their plans given some of the current pipeline capacity for getting oil out of Alberta. Mark Barnett – Morningstar Equity Research: Just a quick follow-up on that. Would you still say that there are some projects in the generation queue in Alberta that maybe don’t make quite as much sense given where we’re standing today. I mean you mentioned, people obviously want to get their projects built. But you think that there is kind of a significant amount of catastrophe, not maybe not as well positioned as Sundance 7 that might – should we see a continued sag, maybe you might call it crisis in demand that might [inaudible] to drop out?

You know what; I never speak for what other people are working on. All I know is that our teams continue to believe that capacity will be needed by the end of the decade. But we think the most important criteria for investing in capacity in Alberta is cost structure. And we’re spending almost all of our time looking at the cost structure in Alberta. As you know, Alberta can be a very expensive place to build. It has a cost structure for most construction projects as well above anywhere else because of some of the tight supply considerations for labor. So what we look at at TransAlta is just how can we make sure that our plant is the lowest cost in the stack. We’ll have the highest availability. We’ll be dispatched the most and that’s the only thing you do if you want to compete in the market here. Mark Barnett – Morningstar Equity Research: Thanks.

The next question comes from Linda Ezergailis of TD Securities. Please, go ahead. Linda Ezergailis – TD Securities: Thank you. Dawn, you mentioned your confidence in Puget Sound appeal or revisiting of that contract with the regulator to be successful. What would be the basis for that? Is there any discussions or regulatory filings or back and forth that you translate to? And would you expect any sort of amendments to what Puget Sound is proposing for the regulator to be fired [ph]?

Yes. Linda, just the confidence is that the dispute between Puget and the regulators isn’t about the actual contract or the terms and conditions of the contract or the levels, price scene [ph] or the sort of the contract over all I think is positive. There was some concern that if we didn’t make a bit of an amendment to the contract that we could shut the plant down, supplied from the market and had the effect of not having people work there. So we made an amendment to make sure that that was not the case because it was never TransAlta’s interest or case that we wanted to find a way to get a contract for our coal side [ph] to make a shutdown of supply for the market. So that was dealt with. Really, what I see is that the issues are more on a broader – on the conditionality that the regulators put in the contract on Puget just weren’t acceptable. There was a line of history there of how that’s worked for Puget and the regulator. And what I see is them both working very positively to resolve that in the contracts of field where all regulatory relationship there and absolutely no indication that it will mean anything for the contract that we have with them. So I’m confidence in – I’ve seen good progress in that relationship and that it’s not about the Centralia contract, it’s about a broader regulatory relationship. Linda Ezergailis – TD Securities: That’s very helpful. Now with respect to in the other discussions you’re having with the utilities, I mean, different utilities have different needs but they have the same regulator. Would you expect, maybe pricing a little bit aside or included in this question, similar attributes in any other contracts that you signed with other utilities or with would there be a big variance based on the utilities’ needs?

Well, I would say that any other utility that was regulated by the Washington regulator would have to expect sort of a similar treatment if they went for a contract in terms of the equity kicker. But there are in that region – remember that region also has a number of non-profits. They’re called the PUDs, and they are not regulated by the Washington regulators. So they wouldn’t participate in an equity kicker but they also have fairly significant loads and they have to be looking at their contracting going forward. And their next best alternative is natural gas. So those contracts, I think are more just going to be what’s the best price that we could negotiate between us. And then there is also some potential – it means there are discussions with some of the out of state companies that are regulated by both Washington and other states. So they’re very individual discussions. There is no common theme that I could say it’s going to look like this. And it really depends on whether or not people will in the end use what’s called Centralia transition call in their portfolios as they move between now and 2025. I mean, the reality is that plant is more competitive than most resources in that region on a long-term basis. So it’s a good opportunity for them to add to their portfolios and keep their overall prices to customers down. Linda Ezergailis – TD Securities: Great context. Thank you.

The next question comes from Andrew Kuske of Credit Suisse. Please, go ahead. Andrew Kuske – Credit Suisse: Thank you. Good morning. If you could just give us a bit more color around OM&A cost and really what you’ve been doing to tackle them and to get them more under control with a more positive outlook out into the future?

I mean, I think the key thing is we’ve been quietly undertaking quite an investment in IT infrastructure over the last couple of years so that we can get a lot more of our systems and processes managed through some really good enterprise systems that allows us to take on a lot of the administrative burden on our teams. And so just different things like we’ve now got a way to look at all of our projects in one systems, project management systems. We’ve got a best in class human resources system that’s taking tons of time out of the work that managers and people have to do here at TransAlta. We’re doing a number of things on the finance side to ensure that we’ve got simple recording, consistent reporting. We’ve got dashboards in place so that we’re not asking our people to spend a lot of their time trying to find information and report it to us. We’re actually able to get now out of our IT systems. There’s no difference than any other company is the undertaking, having sort of source of data and one set of computer system that help our management see it. So when we finally got a lot of that stuff coming across the line, and then really thought about how we wanted to restructure the company to get the right kind of focus. When you’ve got all of that together, it meant that we actually didn’t need as many people to do the administrative side of the business. We, of course, always need to frontline people in terms of people to operate and maintain the plants and things like that. But at the end of the day, we found those efficiencies and it did lead to some exits at the end of the year. And we don’t expect that to be some sort of – or you shouldn’t see that as a cost-cutting exercise and those costs will sneak back in there. Actually, a fundamental structural change that we’ve been able to implement just deliver our lower cost structure for the number of assets that we’ve had. We also have had our real push to push accountability out into the fields for P&L, and make sure that all of our resources for running our plants are in the fields which allowed us to really slim down our corporate offices here in Calgary. And it does mean more jobs out at the plant but we think those jobs will give us better availability, lower cost, the right levels of sustaining capital and it’s just been an ongoing push that we’ve had. Andrew Kuske – Credit Suisse: Is there any quantification of improved availability at the plant level that you’ve got really from streamlining your operations and just availability overall, and then also really preventative issues of seeing things happen before they happen or having a protective view?

Yes. So let me talk about that in two ways. So first of all, you can see evidence already in 2012 with the forced outages rate being down that getting the plant engineering staff built up and really making sure that the plants have what they need has helped them reduce their forced outages. One of the initiatives that we put in place in 2009 as part of our three year plan was that we installed the very trick set of processes in our industry for what’s called work management. And really, it’s been on the predictive side of maintenance instead of the reactive side of maintenance. We completed almost all of that work across our fleet towards the beginning of 2012 and it’s really taken hold now as we’ve gone through 2012. And what that particular program does is that it really allows our teams out in the plant to be much more thoughtful and much planned about their routine maintenance and to make sure that their price having that maintenance around availability issues. And so we’re starting to see some of the payoff of that both in terms of availability. And of course, as everybody knows you spend – on reactive maintenance, you spend three to six times more than you do on preventative maintenance. So as we go forward, we’re hoping to see that will see more cost efficiency in that program as we go forward. Andrew Kuske – Credit Suisse: Okay. That’s very helpful. Thank you.

The next question comes from Robert Kwan of RBC. Please, go ahead. Robert Kwan – RBC: Good morning. Just on the Alberta contracts, the price ranges up about 5 bucks [inaudible] not just hedging percentage up to 85%. I’m just wondering how you’re thinking about that level and how you’re feeling with respect to that 90% target kind of where do you want to be this year. And then with you moving the range up on relatively low volume, I know you probably don’t want to get into a lot of details around the variability or specific quarters. But is there a lot of variability in the hedge profile from quarter to quarter?

Yes, Robert, I mean, there can be because as you know in this market, quarters trade different in terms of liquidity and positions are different depending on outage schedules and all that. So there can be variability in our hedge program. We provide as you know more cost a year. Clearly, our goal as we indicated and have indicated is to increase that portion of contractedness both within the year and even as we look further out. There will always be a portion of our fleet which probably stays a little more open just because of the nature of the volumes like our wind as a good example of that. But certainly, we’re actively looking for opportunities at the right time to lock in some prices for locking in cash flows.

Robert is your question about whether or not we hedge using quarterly hedge prices or annual hedge prices because I think – Robert Kwan – RBC: I guess – sorry, go ahead, Dawn.

Can you have – Robert Kwan – RBC: If there’s color on that that’s great but just more so – you talked about the forward curve being lower than where you’re hedged. So if you’ve moved the hedges up yet achieved higher pricing, one take would be that you hedge up more in some of the stronger priced quarters.

Yes. Just to be clear, the prices, the hedges that we’ve put on in that $60 to $65 range were already put on and they’re done. They’re behind us. And so they protect that portion of the cash flow. As we go into the year, the team has a target that they are trying to achieve. And they have different levels of predictions that they have for each quarter so they’ll have times where they think that prices might be higher and it helps them hedge the rest of the year. And of course, we can’t disclose that but that’s really how they approach it. And as you know in Alberta, you can be smarter than smart and think you can see where the quarters are going to have different pricing and then really you don’t know because there’s all sorts of factors that changes once you get there. But certainly, the way the teams are set up, they look for opportunities to take advantage of pricing and opportunities as they come in the quarter. Robert Kwan – RBC: Sure. Okay. And just my last question is as you looked more at the federal coal regs and specifically, the substitution of flexibility clauses, is there any other color that you’ve had? I know there was some notion that you could borrow partial years from some of the newer units and try to bring them back. Do you have any kind of additional thoughts on that in that ability?

I don’t have any additional thoughts on that. I think we’re still – it’s a complicated algorithm for us to look at where the plants are in terms of their life cycle and in terms of the investments that need to be made to take them to 48.5 years. There’s a lot of pretty sophisticated asset management that we need to do to figure out whether or not you’re better off to run those plant 45 years and another is 50. We know we have the flexibility to do that but the engineering work is much complicated. So we wanted to take in that as we go through the year. We also have to in the end, come up with an equivalency arrangement with the Alberta government on that. So we need to be doing those discussions in parallel. I think it’s probably something more that we could update you at our discussions with you in November next year. Robert Kwan – RBC: Okay. That’s great. Thanks a lot.

The next question comes Philson Yim of Luminus Management. Please, go ahead. Philson Yim – Luminus Management: Hi. Just to follow-up on Robert’s question. If they didn’t look like the hedge levels increase that much since November analyst day. So could we assume that the new hedges over price were much higher to bring that average price up? Much higher than with those prices would indicate?

Yes. Again, we thought some improvement in 2013 when we’re late in the year, Philson. So you can assume that we’re just giving you the average and an indication of what the forward market is for the balance of the year, which is – I mean, that 50 to 55 range. Philson Yim – Luminus Management: Got it. So was it more customers taking their own view about where prices would end up for the year versus just looking at the forward curve and what that indicates.

Yes. And again, as Robert was I think getting at, we don’t just hedge for annual. It is very much a quarterly activity. And as you closer, you can even go into the months depending how far out it is. But we don’t provide that detail for competitive reasons.

Yes. I mean, you have to go back and there’s some good works that’s been done studying the forward curve versus what actually happens. We have various [inaudible] on that. You can do hedging in the forward markets; you can do it with customers. We look at all of those different mechanisms. But in Alberta, the forward curve can move quite a lot around in the quarter. Philson Yim – Luminus Management: Got it. And then so, beyond 2013, can we use or carry this average price forward for now?

Well, we haven’t provided that level of detail yet, Philson. But certainly, as Dawn indicated the forward market from our perspective is not the best indicator when we showed this at investor day. So we’re going to actively look for – we were actively out there as we talked about with our CNI business in terms of entering into two, three, four-year contracts and working with others to see if we can get longer. So prices would be probably not as high as what we’re seeing, so slightly lower just because the curve is down a bit more. But we haven’t updated that to the market, I think.

Yes. I think, Philson, the work that Juan has done at Canaccord is some of the best work I’ve seen on how to think about the operated markets. We showed that in investor day and he’s done a lot of work on that so he’d be someone that you could talk to. Philson Yim – Luminus Management: Got it. Thank you.

(Operator Instructions) The next question comes from Paul Lechem of CIBC. Please, go ahead. Paul Lechem – CIBC: Thank you. Good morning. Just with relation to your CE Gen plants, you had another loss in the quarter there, a bit larger this time. Can you talk about what actions you’re taking to try and bring those plants back into profitable level?

Yes. I mean, the team down there is working very hard with the local utilities to recontract those plants. As you know, in that market place, some of those contracts are also related to gas pricing and so it’s a similar kind of story to Centralia where plants have had some gas price indexing affecting their pricing or seeing lower profitability and the challenges to try to move away from short-term pricing into more long-term type pricing arrangements with the local utilities that have as you know targets for medium renewable and ever increasing targets in the California market. So that is where we’re undertaking the same kind of work there as we have been in the Centralia plant and have been for a while. Paul Lechem – CIBC: When do you expect those plants to start showing results from all these efforts?

Where do we – Paul Lechem – CIBC: When should we expect in 2013 to see these plants come back or at least break even?

Yes. I mean, we will update you as those contracts occur and then provide you with that information. In addition to that, we constantly look at are there – like we do in Alberta and the Pacific Northwest, opportunities to hedge shorter term and lock into some value. So it’s an active program in terms of long term and shorter them activity.

So Paul, we do have resources focused on that with both in target set to get that kind of work done in 2013. But as you know it’s also required [inaudible] you can close the contracts. So they’re working hard and hopefully, we can get the California Utilities to close on those plants. Paul Lechem – CIBC: Okay. Thank you.

The next question comes Jeremy Rosenfield of Desjardins Capital Markets. Please, go ahead. Jeremy Rosenfield – Desjardins Capital Markets: Yes, thanks, and good morning everybody. Just a few questions just more from a strategic perspective. There’s that one line in the presentation that mentions the opportunity to acquire, win the assets in the Western US. And I’m wondering here if you’re looking at more on a single asset basis or something on a portfolio basis. And then also, to follow on, do you have the sort of nominal dollar amount that you’re considering and does that relate at all to the drift [ph] in terms of the size of equity that you’d be looking to deploy.

Yes. I mean, all I can really say there is there’s a lot of assets that are potentially trading in the markets there. There is groups of assets, there’s individual assets, it’s from a variety of players and I would say that our team has been the deal [ph] also everything that’s for sale in that market and looking at it and evaluating it, and thinking about how we would do that to add value for our existing shareholders. And a lot of competition for sure for those kinds of asset coming from a variety of places, so for us, it’s about making sure that A, we have a competitive advantage against the competition, and B, that we can get the returns that will be accretive to our shareholders. So in terms of how we finance it, and all that stuff resolved, we look at that on a deal by deal basis, it’s part of our competitive positioning, and I really can’t say much more other than lots of volume, and if we can find a way to be more competitive and added [ph] people and provide accretive return and we’re hoping to expand our business there this year. Jeremy Rosenfield – Desjardins Capital Markets: Okay, great. And previously, you’ve kind of elaborated on the potential for creating some value within your own renewable power portfolio. I’m wondering if that’s been advanced at all and if there’s any updates on that?

Yes, I think it kind of all works together. We’re looking at, as we’re thinking about how to expand that business, thinking about how to – what the mechanism will be to both expand that business and unleash that value so that we see it more clearly, are top of mind for the finance team and they’re working on a variety of different kinds of structures to think about how to do that. Jeremy Rosenfield – Desjardins Capital Markets: Okay. And maybe just one last question. In terms of planned outages for the coming year, obviously much lower in terms of major maintenance for the coming year than last year, but can you elaborate on which units, specifically have major maintenance outages in the coming year?

Yes. So we’ve got two of our wholly owned 4 and 6, and then there’s two partially owned, Sarnia [ph] always does an outage in the year and it’s K3. Jeremy Rosenfield – Desjardins Capital Markets: Okay, great. Thanks a lot.

This concludes the analysts Q&A portion of today’s call, we will now take questions from members of the media. (Operator Instructions) The first media question today comes from Jeff Lewis, of the Financial Post. Please go ahead. Jeff Lewis – Financial Post: Hi there. Just looking for some additional comments on LNG in BC. You’ve previously identified that there’s up to 4,000 megawatts needed to run those facilities after 2018. I’m just wondering how are you approaching those opportunities following the MidAmerican partnership given some of the issues in BC around transmission and government direction on natural gas versus using other power sources to run those facilities?

Yes, I mean it’s a fairly, very interesting opportunity for Canada, and I think as we work in British Columbia, we certainly see a lot of enthusiasm there with BC Hydro and the government to figure out how to make sure that anybody who try to locate LNG plant can have a competitive source of power. And they’re competing for sure, in British Columbia with LNG plants that are also very competitive from Australia. So it’s really a competition as the Canadians and the Aussies. And so what we’re doing is we’re working, the best way to work with, is to work with the actual direct customers, because they’re the ones that need the assurance that they can bring in low cost supply. And so we’re working with them, we’re working with BC Hydro to see where behind the sense needs might be versus where they can supply from the grid. There’s lots of grid benefits that if you do it behind the fence plant, and you tied into the grid, you can create additional benefits for British Columbia, and for the LNG customers. And then also of course, in British Columbia, if you really want to get projects done, you have to be cognizant of the work that needs to be done with the first stations [ph]. And so we’ve been working there as well. So we work with first stations [ph], we work with the government, we work with BD Hydro and we work with behind the fence suppliers. If the behind the fence guys use glycerides [ph], there’s less of a requirement for power, but there’s still a significant requirement. Some of them are thinking about going to electric guys which is much stronger on the environmental front, and so that requires more behind the fence power. And it’s really akin go the business that we do in western Australia with the minors. In the western Australian market, there’s not enough grid to supply those mines, and so we tend to work with those miners behind the fence to find a power supply that gives in their reliability, and then where we can, we try to have make [ph] it into the grid to get additional benefits. So the kind of work we do in western Australia is exactly the kind of work we’re doing in BC, but they have to go, and the good news is, because of the sort of, we got a long history of doing behind the fence work in gas [ph] generation over the last 15 years with large customers, mining customers, oil and gas customers. And MidAmerican also has that history and between the two of us who’s got the right balancesheet would be in those discussions. So that’s how we’re approaching it. Jeff Lewis – Financial Post: Okay. And so have you talked to any of the export proponents?

We talk to lots of people. Jeff Lewis – Financial Post: Okay. Thank you.

The next question comes from Jeremy van Loon of Bloomberg News. Please go ahead. Jeremy van Loon – Bloomberg News: I’m just wondering if you could talk a little bit about the medium to kind of long-term outlook in terms of sort of the power mix here in Alberta, vis-à-vis natural gas and perhaps wind. I mean, how do you see pricing evolving on natural gas? Are you sort of expecting to continue to see these low stable prices, or at what point do you start to sort of introduce some diversity into the network here?

Well Alberta already has quite a bit of wind in the market place. It’s probably kind of unknown fact about Alberta which we need to get out more because people don’t recognize that we’re I think 700 megawatts of wind in a 10,000 megawatt market. So we’re seeing the wind come in. In terms of the question around natural gas pricing, you all know that the consensus is emerging that prices could stay low. We are seeing some of the forecasters are starting to have an upward view on gas prices. I have no idea what gas prices are going to do, and if I did know that, I probably wouldn’t be in this job. So I think the key thing there is trying to figure out even a range of potential pricing outcomes what will happen in the Alberta market. For sure, if gas prices stay in that, really gas, are barely competitive with one another with gas prices during the $4.55 [ph] range, because the capital cost of wind have been coming down, and that project is still fairly expensive because they’re expensive to build here in Alberta. The challenge in the Alberta market is that when the wind blows, the prices are depressed, and wind is very hard to hedge. And those are the kinds of things that have to change here in Alberta if there is going to be more wind. So as we look forward, we do think the mix will be more gas and wind to launch in either regions, but there will need to be some structural changes in two ways in the Alberta market, and you simply cannot have wind depressing its own prices, or you cannot make an economic return. So that has to be fixed in the market. And as well, to bring on large scale gas plants that cost $1.5 billion, there has to be a long term pricing mechanism because rational investors will not take the risk on that kind of capital without having the capacity payments covered in some way. Jeremy van Loon – Bloomberg News: Are you seeing any movement in terms of provincial regulations that might sort of help to address some of those issues?

I think there’s certainly, the ISO [ph] has been doing some work to figure out that needs to be done on the wind side, so there could be something this year and next year on that. We don’t know. We’re hoping to see some movement there. And I think there is a recognition overall in the market to bring on new capacity, the capital has to be protected in some way. Really, those conversations have not really started yet. There’s enough power for a couple of years, so we have time to get that done. Jeremy van Loon – Bloomberg News: Okay. Thanks.

There are no further questions. I’ll hand the call back over to Mr. Ward for any closing comments.

Thank you, everyone. Just to reiterate, if there’s any follow up questions, we’re available after the call to handle them and throughout the day, and the week. But this concludes the call. Thank you.

Ladies and gentlemen, this concludes today’s conference call. You may now disconnect your lines. Thank you for participating. And have a pleasant day.