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Capital Power’s (CPXWF) CEO Brian Vaasjo on Q4 2015 Results – Earnings Call Transcript

Capital Power Corporation ( OTC:CPXWF ) Q4 2015 Earnings Conference Call February 19, 2016 12:00 PM ET Operator Welcome to Capital Power’s Fourth Quarter 2015 Results Conference Call. At this time, all participants are in listen-only mode. Following the presentation, the conference call will be opened for questions. This conference call is being recorded today February 19, 2016. I will now turn the call over to Randy Mah, Senior Manager, Investor Relations. Please go ahead. Randy Mah Good morning and thank you for joining us today to review Capital Power’s fourth quarter and year end 2015 results, which were released yesterday. The financial results and the presentation slides for this conference call are posted on our Web site at capitalpower.com. We will start the call with opening comments from Brian Vaasjo, President and CEO; and Bryan DeNeve, Senior Vice President and CFO. After our opening remarks, we will open up the lines to take your questions. Before we start, I would like to remind listeners that certain statements about future events made on this conference call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results may differ materially from the company’s expectations due to various material risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information on Slide number 2. In today’s presentation, we will be referring to various non-GAAP financial measures as noted on Slide number 3. These measures are not defined financial measures according to GAAP and do not have standardized meanings described by GAAP, and therefore are unlikely to be comparable to similar measures used by other enterprises. Reconciliations of these non-GAAP financial measures can be found in the Management’s Discussion and Analysis for 2015. I’ll now turn the call over to Brian Vaasjo for his remarks starting on Slide number 4. Brian Vaasjo Thanks Randy. I will start off by reviewing our highlights for 2015. Capital Power delivered solid performance in 2015 with the company meeting or exceeding its annual operating and financial targets. This included achieving average plant availability of 95% compared to the 94% target. We also generated $400 million in funds from operations, which was at the upper end of the $365 million to $415 million target range. We also continued to strengthen our contracted cash flow with the addition of three new facilities in 2015 with 305 megawatts under long-term PPAs. The Shepard Energy Center, K2 wind and Beaufort Solar were all added to the fleet during the year on time, neither on or below budget. We increased the annual dividend by 7.4% and provided annual dividend growth guidance of 7% per year for the next three years out to 2018. Finally, through our share buyback program, we repurchased approximately 6 million common shares that represented approximately 7% of the outstanding shares at the beginning of 2015. Turning to Slide 5, I want to provide an update on the impact of the Alberta Climate Leadership Plan. We continue to wait for further details on the plan that was announced by the Alberta Government last November. One component of the Climate Leadership Plan is the accelerated phase of the coal facilities with replacement generation coming mostly from renewables. We are well-positioned to participate in this opportunity as you can see in the chart; Capital Power is a leading IPP developer in the Alberta market. With our construction expertise, we are well-positioned to develop and build renewables in natural gas fired facilities. Moving to Slide 6, the other aspect of the accelerated phase out of coal facility is how the government of Alberta will compensate companies that are impacted. The government has stated that they are committed to avoid unnecessary stranding capital into three companies fairly. Our continued understanding is that we will be fairly compensated for the yearly shutdowns of Genesee 1 and 2 and our 50% interest in Genesee 3 and Keephills 3. This belief is based on the government’s statement and their planned introduction of the carbon competitive regulation or carbon tax starting in 2018, which is expected to generate several billions in new government revenues. At this time, we are still awaiting the appointment of a facilitator, our understanding is that the Alberta Government is aiming to announce the facilitators name and mandate in the near future and will commence discussions with the affected coal companies at that time. We expect details regarding the timeline in terms of reference will be published once the facilitator is announced. For Capital Power, ensuring we receive fair compensation remains a top priority. Turning to Slide 7, I would like to provide an update on our Genesee 4 and 5 project. In 2015, limited construction activities took place due to the uncertainties stemming from the Climate Leadership Plan. We worked with the turbine manufacture and have deferred the original March 1, 2016, full notice to proceed deadline; this deadline has been deferred by up to 90 days from March 1. Further investments in the Alberta market including continuation of construction of Genesee 4 and 5 project will be considered one sufficient detail around the CLP is released and the company has assessed the impact on its existing Alberta assets. If Capital Power were to proceed with the Genesee 4 and 5 project with targeted completion as early as 2020, we need to have certainty with respect to the three critical issues. First, fair compensation from the Alberta Government for the projected accelerated closure of coal fired facilities. Second, clarity that implementation of the CLP will have no adverse impact on the Alberta electricity market design. And last, appropriate price signals from the energy-only market. On Slide 8 is a summary of our plant availability operating performance our plants for the fourth quarter of 2015 compared to the same period a year ago. We had outstanding operational performance in the fourth quarter with average plant availability of 99% compared to 94% in the fourth quarter of 2014. As you can see plant availability across the entire fleet was in the high 90s with the exception of our Southport facility, which is was at 93%. Turning to Slide 9, as you see in the chart, 2015 was consistent with past performance. Capital Power has a proven track record of high fleet availability, in the last five years we have achieved 93% average annual plan availability and we expect to continue the strong operational performance in 2016 where we are targeting plant availability of 94% or higher. I will now turn the call over to Bryan DeNeve. Bryan DeNeve Thanks Brian. Starting on Slide 10, I would like to review our fourth quarter financial performance. As Brian mentioned we had a strong quarter with 99% average plant availability and 23% increase in electricity generation compared to the fourth quarter of 2014. We generated $125 million in funds from operations representing the highest FFO in a quarter in three years. Normalized earnings per share was $0.42 compared to $0.20 a year ago. The average Alberta power price was $21 a megawatt hour in the fourth quarter compared to $30 a megawatt hour in the fourth quarter of 2014. Despite the 30% year-over-year decline, our trading desk captured a 162% higher realized average price of $55 a megawatt hour versus a spot price of $21 a megawatt hour. Moving to Slide 11, the strong performance from our trading desk has been evident over a longer period of time. The orange line in the chart represents Capital Power’s realized price for managing our exposure to commodity risk in reducing volatility. As you can see not only is there less volatility compared to the average spot price shown by the green line Capital Power’s average realized power price has exceeded the spot price by 25% on average in the past six years. So we continued to see consistent material value creation from our portfolio optimization activity. Turning to Slide 12, I will review our fourth quarter financial results compared to the fourth quarter of 2014. Revenues were $341 million down 21% from Q4 2014 primarily due to the unrealized changes in fair value of commodity derivatives and emission credits. Excluding mark-to-market changes plant revenues were up 11%. Adjusted EBITDA before unrealized changes in fair values was $133 million up 28% from the fourth quarter of 2014 result of higher generation across the fleet, the addition of Shepard in a full quarter from Macho Springs. Normalized earnings per share of $0.42 increased to 110% compared to $0.20 a year ago. As mentioned, we generated strong funds from operations of $125 million in the fourth quarter, which were up 23% year-over-year. Turning to Slide 13, I will cover our 2015 annual results compared to 2014. Overall, 2015 results showed year-over-year improvement across all financial measures. Revenues were $1.25 billion up 2% year-over-year primarily due to strong portfolio optimization results. Adjusted EBITDA before unrealized changes in fair values was $462 million up 19% from a year ago primarily due to higher contributions from the Alberta commercial plants and from Alberta contracted plants. Normalized earnings per share were $1.15 in 2015 up 60% compared to $0.72 in 2014. We generated $400 million in funds from operations in 2015, which is 10% improvement from 2014. I will conclude my comments with our financial outlook on Slide 14. For 2016, our FFO guidance of $380 million to $430 million is based on the Alberta baseload plants being 100% hedged at the start of the year at an average hedge prices in high $40 a megawatt hour range. This compares favorably to the average 2016 forward price of $35 a megawatt hour as at the end of 2015. Although our baseload position in 2016 is fully hedged, we have the ability to capture additional upside in power prices with our peaking in wind facilities. We will also see a full year of operations from Shepard, K2 wind and Beaufort Solar in 2016. For 2017, we are 38% hedged at an average hedge price in the low $50 a megawatt hour range. And for 2018, we are 9% hedged in the mid $60 a megawatt hour range. The forward prices for 2017 and 2018 at the end of 2015 were $40 and $51 a megawatt hour respectively. Overall, we are managing current lull of Alberta power prices with continued cash flow per share growth in 2016. I will now turn the call back to Brian Vaasjo. Brian Vaasjo Thanks Bryan. Starting on Slide 15, I will conclude my comments by reviewing our 2015 operational and financial performance versus targets and recap our 2016 targets. As mentioned our 95% plant availability performance in 2015 exceeded the 94% target. For 2016, our average plant availability target is 94%, which includes major plant outages at Genesee 2 and 3, Clover Bar Energy Center, Joffre and Shepard. Our sustaining CapEx was $62 million in 2015, which was slightly below the $65 million target. We are targeting $65 million for 2016. Our plant operating and maintenance expense for 2015 came in at $192 million, which was in line with our target range of $192 million to $200 million. For 2016, we are targeting $200 million to $220 million for plant operating and maintenance expenses. And as previously mentioned, we achieved the upper end of our 2015 financial guidance by generating $400 million in funds from operations. For 2016, we are targeting FFO in the range of $380 million to $430 million. Turning to Slide 16, we have two development and construction growth targets in 2016, as mentioned the timing for full notice to proceed for Genesee 4 and 5 is contingent on clarity with respect to the impact of decisions from the Alberta Government’s Climate Leadership Plan and the appropriate price signals from the Alberta energy-only market. The second growth target is executing a PPA for a new development. The progress on our Bloom wind project is at the most advanced stage at this time. Bloom wind is 180 megawatt wind project in Kansas and construction is ready to go once an agreement can be executed. I will now turn the call back over to Randy. Randy Mah Thanks Brian. Mike, we are ready for the question-and-answer session. Question-and-Answer Session Operator All right. [Operator Instructions] All right. We do have a few questions. First one comes from Andrew Kuske from Credit Suisse. Please go ahead. Andrew Kuske Thank you. Good morning. I guess when you look in the quarter; you guys once again had a really good realization versus weak power markets in Alberta. So when you think ahead into 2016, and then beyond, do your strategies change just given the weakness in the power market. How do you maintain that kind of spread or at least really positive spread over the existing prices versus what you’ve realized historically? Brian Vaasjo So, when we look at 2017, as I mentioned, we are 30% — 38% hedged for that year. We have locked that in at prices that are higher than current forwards. Certainly as we move forward, we will continue to evaluate how forwards look relative to our own internal fundamental view of prices and make decisions on that basis. Certainly as we approach closer to 2017, we will be looking to increase that percentage hedged amount and work our way towards a higher hedge percentage. Andrew Kuske And then, maybe just an extension on that, what’s motivating customers, or your customer conversations to actually engage in power contracts right now at what we see in the forward curve levels versus just say staying open on spot? Brian Vaasjo I think that’s definitely one of the factors in the market right now. So the lull power prices and low volatility does provide a comfortable environment for customers. But as the market tightens and we see events occur such as unexpected outages, or more extreme weather events that will bring volatility back to the market and will drive higher percentage of customers looking to start the lock-in prices. Andrew Kuske Okay. That’s helpful. And then, maybe a broader question for Brian, if I may. Just as it relates to receiving compensation from the government, you practically — does there have to be some kind of agreement in principle at least between yourselves Canadian Utilities and TransAlta and three legacy coal owners in the province and size on the nature, or the form of the compensation model? Brian Vaasjo So Andrew very, very good question. As we look forward, there will certainly be elements, or process that are defined by the government and the arbitrators. So for example, they may define that they will meet with companies separately as opposed as a group. But our understanding is on the issue of compensation. They will be directly engaging list of the four coal companies and actually no other industry participants. So that’s quite positive. We would expect to be in common meetings. And I think we all of the coal companies do recognize that the more we are aligned on our views and our expectations and principles likely the more successful will be. So there are certainly efforts underway to — and they always has been efforts among the coal companies from time-to-time two work together on these issues. Andrew Kuske Okay. Thank you. Operator All right. Next we have a question from Robert Kwan from RBC Capital Markets. Please go ahead. Robert Kwan Good morning. Maybe I will just follow-up on that last answer Brian just around alignment kind of almost being necessary to push this forward at least a little bit faster. If I look at what you are saying around G4, G5, almost seems like you’re implying that the energy-only market works that you don’t see the need for major changes in market structure and I think it’s very similar to what you said in the past. But we are also hearing some very different things, or potentially different views from some of the other companies. So I’m just wondering if you can reconcile whether you guys are changing your view, or you think they maybe changing, how did you get this alignment going forward? Brian Vaasjo So maybe a way to sort of characterizing. And again, this is my personal view. Is there — is some skepticism in the market in general amongst some players and more broadly than just the coal folks and as we go through this process whether the other end there will be a viable energy-only market in Alberta. Our view is that with the appropriate decisions and policies established there will be. And what we’ve seen from the government so far in terms of indicating the directions that they are going, we do believe that will leave a very viable energy-only market. I think that the other companies, and again, this is my view, our — perhaps less skeptical or more skeptical that those principles will be enacted sort of as is and that the market will survive on the other side. So I don’t think it’s a — I don’t think it’s a view that others would not invest in the energy-only market. I think recently TransAlta has been making some announcements that aren’t premised on there being a different market. It’s just a different outlook as to whether or not the energy market — energy-only market will be as fundamentally sound as it has been over the last 15 years. In our view that will be. Again, if the — some way government follows through on what they established as the direction that they are going. Robert Kwan Understood. So are you willing to move to the more contracting position, or are you expecting if there is going to be alignment that people have to come to you or to come to where you are? Brian Vaasjo You mean that wanting a fully contracted market going forward? Robert Kwan Well, or even just a contracted market for new generation, some sort of hybrid market? Brian Vaasjo Well, there certainly is hybrid market so to speak on the renewable side. And we are — and again, given the direction that the government is going, we see that as being very complementary to the energy-only market. When it comes to decision on the building of natural gas plants, we would see that’s necessarily market does not contracted — I mean it can bilaterally among load and generators, but not becoming a contract market in a broad basis. And so that’s where we see that there is a difference, but — certainly on the contracted side, or on the renewable side, we do anticipate that will be a significant component that will be contracted. And we will participate in that happily. Robert Kwan Okay. If you just look at how this relates under G4 and G5, I guess, first, can you push the date back further is this good as it gets. And then, if there is kind of some clarity that it will be an energy-only market and that the market structure is largely unchanged. What type of price signals from that energy-only market are you looking — I assume you are not going to be looking at spot, but more so forward curve. Do you have a sense as to what levels and do you need to have enough term — like how much term given there is a lack of liquidity, are you going to meet to underpin that decision? Brian Vaasjo So when we look at that overall picture, there was a couple of questions there tied together. We do need to see the appropriate pricing, and of course, issues like compensation and so on being satisfactorily resolved. But assuming that’s all the case and we are looking at just the economics and a good energy-only market. I think all parties, forecast in the 20, 20-ish timeframe with the retirement of coal plants and even with low growth in the province that you will see power prices in that’s a $65 and up range. And where natural gas prices are today that’s appropriate price signals to move on forward on something like G4, G5. Robert Kwan Okay. So just needing to see something in the curve and that expectation versus actually needing to lock-in something for term? Brian Vaasjo Well, and just to remain you that half of our investment in G4, G5 is contracted — going to have contracted going into it. SO our merchant position is relatively small. Robert Kwan And then, can you push the turbine agreement back any further or is this it? Brian Vaasjo The way its — and as its — as we’ve discussed over the last couple of years, those contracts were put together to be very flexible. And what we are up against now, isn’t the flexibility of the contract because it certainly can get pushed out further. But you start running into logistical window problems and small push out in time now might result in the completion of the project being a year down the road. So that’s more — we are not against the contractual issue right now, it’s more logistical issue of delivering the project in a timely basis. Robert Kwan Okay. So basically you have to take the turbines, or make the decision by the beginning of June or you could be into mid-2017? Brian Vaasjo If you reached a point where you were going to actually miss the window on completion, you could defer it — defer the decision, but your completion would be deferred a significant amount of time. You’re talking about numbers of months as opposed to kind of months — for month or day for day as it exists now. Robert Kwan Okay. Got it. Thanks very much. Operator All right. Next question comes from Linda Ezergailis from TD Securities. Please go ahead. Linda Ezergailis Thank you. I just want to follow-up on questions around how you are looking and acting over the long-term. Given some of the uncertainty around market structure et cetera, are you going to hold-on and I realize there is not much liquidity in 2018. But, how comfortable are you hedging or adding to your position in an environment where you don’t even know what the structure or the rules are? Bryan DeNeve Well, I think when we look at what has been announced and I will reiterate what Brian said earlier. The recommendations that have been put forward to the government are all aligned and all worked towards maintaining the structure of the Alberta market as it has worked in the past. And as we move forward and made decisions on selling power forward, our belief is that that market structure will be allowed to continue to work as it has and we will make those decisions accordingly. I think in terms of the real key on the market structure is the timing of renewable procurements aligning with the timing of coal retirements. Everything we’ve heard from the government is that — that’s how it will proceed. So when we look for signals in the market when we see increasing prices adequate for a new build that sits in the 2020 timeframe that’s following 1000 megawatts retirement of coal. So we’ll be making our investment decisions and/or hedging decisions on that basis of the market design continuing to operate as it has. Linda Ezergailis Okay. Thank you. And just a follow-up question, it was good to see that wind is still on standby, can you give us a sense of what the timing might be for an agreement? Brian Vaasjo Linda — so we are actually as we speak we are working with — we are working on agreements like it’s not that we are not participating in an auction and we will see the results. We are actually moving on the commercial side of it. So I mean discussion and agreements can always fall apart for whatever a different kinds of reasons we are proceeding down the path of having something in the relatively near term. Linda Ezergailis Okay. That’s good to hear. And any updates on some of the other opportunities that you are looking at whether it would be in the U.S. or be BC or Saskatchewan? Brian Vaasjo Well, we continue to see opportunities this year in terms of, I will call the element portfolio in the U.S. and that’s likely one or optimistically maybe two given various PPA offerings in the states that we are operating in or potentially operating in. On the Canadian side certainly and depending on the details of the timing that the Alberta government comes out with we are preparing to have wind farm or wind farms bid into PPA process or actually erect process as early as one could be called. And that may well happen this year in terms of calling of a process and moving forward. So we see opportunities here in Alberta. Don’t really see many opportunities outside of that in Canada that are immediately on the horizon. Linda Ezergailis Okay. That’s helpful. So just another follow-up to that, when you think of capital allocation given that you have some pending investment possibilities, how do you think of share buybacks versus kind of keeping your powder dry for these opportunities? Brian Vaasjo So certainly as we have increased number of opportunities on the horizon, our preference is to allocate our capital to those growth opportunities over doing something like share buyback. So at this point in time that will be our priority for capital as we move forward and those opportunities materialize. Linda Ezergailis Thank you. Operator All right. Next we have a question from Paul Lechem from CIBC. Please go ahead. Paul Lechem Thank you. Good morning. Just revisiting some of the comments on Genesee 4 and 5, Brian just — it seems there’s a — to fully delay the notice to proceed on the turbine beyond the 90-day period. I’m just wondering why — why not wait — what are the downsides of waiting until the compensation discussions have been completed, that there is more clarity on the outcome? Is there a concern that competitive projects could jump in front of you in the queue, or I mean given — it seems like yours is most ready out of all of them. Is that a reality? I’m just trying to understand the timing decision of why not wait a longer period? Brian Vaasjo So Paul, one of the successes in the Alberta market is, generally speaking, the timing of new generation coming in even though it’s been driven by a market other than with the Shepard facility, which was driven by initially other economic considerations. The market has been well-served by-timely generation. As we see it in — when you have 900 megawatts of retirement taking place in 2019 that creates a significant hole and we see it as — it is appropriate for the industry to respond and to fill that hole. And so, that’s the primary element, is there’s a right time for generation — specific generation to come into the market. So, our view is that if we defer it a small time now on the front end, what it actually does is it moves the tail end schedule significantly again in terms of a number of months and you start running into a period of time in the province when — I’ll say the supply isn’t as it should be. Having said that, are we concerned about losing a position of being first in the market and so on, or losing what I call as the pole position? No. We think we’re very, very well positioned, and again, ready to pull the trigger at any point in time as opposed to then having to develop agreements and so on and start execution. So that’s not a concern and that’s certainly not a reason why we would pull the trigger on a project when we’re not comfortable. And some of the words that you were using was suggesting that we would pull the trigger when we were potentially not comfortable with compensation or the market going forward. That’s not the case. We need to be comfortable before we pull the trigger. So and if that means the project is deferred and if that means ultimately the project doesn’t get done because we “lose the pole position,” so be it. But, we’re not going to invest capital when we don’t feel comfortable in the investment environment. Paul Lechem That’s helpful. Thanks. Appreciate those comments. And just on the front end PPA, we have seen ENMAX return one of the PPA’s to the balancing pool. Just wondering your thought process, I mean you are 100% hedged in 2016, so I guess it’s not an issue for 2016, but beyond that what are your thoughts around the value of holding onto the Sundance PPA rather than returning it? What are going to be your decision points around that? Brian Vaasjo So, certainly any considerations around the Sundance PPA is subject to confidentiality provisions both in terms of the PPA and with our power syndicate partners. So we can’t comment at this point in time on anything specifically regarding the Sundance PPA. Obviously, we continue to valuate all of our existing assets and looking at ways to optimize around those assets. Paul Lechem Okay. Thanks Brian. Operator All right. Next we have a question from Jeremy Rosenfield from Industrial Alliance. Please go ahead. Jeremy Rosenfield Yes. Thanks. Let me just start by following up on that last line of questioning, without going into details on Sundance and that asset specifically, can you just sort of comment in terms of where you see power prices developing over the 2017 to 2020 timeframe relative to where the forward curve is right now and your sort of interpretation as to what prices might actually look like? Bryan DeNeve Our perspective is that the curve forward prices in Alberta are a fair reflection of expectations around where prices will settle. So certainly, at this point in time we think that is a reasonable representation. Jeremy Rosenfield Okay. And you did have some disclosure in the MD&A about payments on the Sundance PPA, somewhere between $100 million and $150 million over the term and I’m just curious, if that’s the total or the annual amount? You can get back to be me afterwards. That’s okay. Bryan DeNeve No, no. That’s fine. That reference is actual to the reference as the annual amount. Jeremy Rosenfield Annual. Perfect. That’s what I thought. Just with regard to the G4 and 5, in terms of the extension, just a little cleanup there, is there actually any cost on your part in terms of having to extend the supply with the window to find the supply agreement, or is it really a no-cost? Brian Vaasjo So just to be clear, the supply agreement is signed. We have an agreement in place and part of the provision is as we move the timeframe, there are escalation elements in that agreement. So it does cost to move the project out. Jeremy Rosenfield Okay. In terms of what that does on the — let’s say total potential return on the project, are you — is that immaterial? Brian Vaasjo The escalations are in line with kind of higher end of inflation type numbers. So it doesn’t for small periods of time it doesn’t have a material impact on the project. Jeremy Rosenfield Okay. And then maybe just one other — Brian Vaasjo But again, recognizing that’s a fairly large project. You could consider that the cost of moving it is in the millions of dollars, but again, it’s in hundreds of millions of dollars in terms of the nature of the project. Jeremy Rosenfield Sure. That’s what I was thinking. My question is really around if you look at the total return that you expect to achieve on a percent basis, let’s say we are talking about a basis points here or there. Brian Vaasjo Yes. Jeremy Rosenfield Right. Okay. And just to clean up in terms of the K2 wind project there was just some disclosure in terms of a return of capital in the quarter specifically and I wanted to just confirm that this was a specific to the fourth quarter and it’s not something that you expect to be receiving on a go-forward basis? Bryan DeNeve Yes. In terms of the portion related to the capital fees that would be just related to one time in Q4. Jeremy Rosenfield Okay. Perfect. Thank you. Those are my questions. Operator Right. And the last question we currently have in the queue comes from Ben Pham from BMO Capital Markets. Please go ahead. Ben Pham Thank you. One question from me. On your hedges for 2016, the 100%, and I wanted to ask, the last time you guys came into the year with that higher percentage of hedges, the following summer you were short on production and it did significantly impact your results. So knowing that have you done anything different this year when you look at what happened before just on the hedges, how you structured that? Are you pretty much assuming that there could be some potential risk but it’s worth it because you are protecting a downside? Brian Vaasjo I think that’s a fair characterization, Ben. So being fully hedged, yes, we do take on some higher operational risk. But given how well the fleet has been performing and we look at that risk relative to protecting against the downside in the low price environment, that’s a trade-off that we make. But certainly as we look forward given how strong the assets are operating, we see that as being a reasonable risk for us to take. Ben Pham Okay. Thank you. Operator All right. And we don’t seem to have any further questions in the queue at this time. Randy Mah Okay. If there are no more further questions we’ll conclude our call. Thank you, everyone for joining us today and for your interest in Capital Power. Have a good day. Operator Ladies and gentlemen, this concludes Capital Power’s fourth quarter 2015 conference call. Thank you for your participation and have a nice day. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. 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Public Service Enterprise’s (PEG) CEO Ralph Izzo on Q4 2015 Results – Earnings Call Transcript

Operator Ladies and gentlemen, thank you for standing by. My name is Brent and I’m your event operator today. I would like to welcome everyone to today’s conference, Public Service Enterprise Group’s Fourth Quarter 2015 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded today, Friday, February 19, 2016, and will be available for telephone replay beginning at 2 o’ clock PM Eastern today until 11:30 PM Eastern on February 26, 2016. It will also be available as an audio webcast on PSEG’s corporate website at www.pseg.com. I would now like to turn the conference over to Kathleen Lally. Please go ahead. Kathleen Lally Thank you, Brent. Good morning, everyone. Thank you for participating in our earnings call this morning. As you are aware, we released fourth quarter and full year 2015 earnings results earlier this morning. The release and attachments, as mentioned, are posted on our website, www.pseg.com, under the Investors section. We also posted a series of slides that detail operating results by company for the quarter. Our 10-K for the period ended December 31, 2015, is expected to be filed shortly. I won’t go through the full disclaimer statement or the comments we have on the difference between operating earnings and GAAP results, but I do ask that you all read those comments, contained in our slides and on our website. The disclaimer statement regards forward-looking statements detailing the number of risks and uncertainties that could cause actual results to differ materially from forward-looking statements made therein. And although we may elect to update forward-looking statements from time-to-time, we specifically disclaim any obligation to do so even if our estimates change, unless of course required by applicable securities laws. We also provide commentary with regard to the difference between operating earnings and net income reported in accordance with Generally Accepted Accounting Principles in the United States. PSEG believes that the non-GAAP financial measure of operating earnings provides a consistent and comparable measure of performance to help shareholders understand trends. I’m now going to turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group and joining Ralph on the call is Dan Creeg, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions. Given the interest in the call, we ask that you limit yourself to one question and one follow up. Thank you. Ralph Izzo Thank you, Kathleen and thanks everyone for joining us today. This morning, we reported operating earnings for the full year 2015 and I’m pleased to report that it was a year of significant accomplishments. As you saw this morning, we reported operating earnings for the fourth quarter of $0.50 per share, versus $0.49 per share earned in the fourth quarter of 2014, despite the unseasonably mild weather this past December. Results for the full year were $2.91 per share or 5% greater than 2014’s operating earnings of $2.76 per share. This was at the upper half of our guidance of $2.85 to $2.95 per share and it was also higher than the midpoint of our original guidance of $2.85 per share. Our results reflect the benefits of excellent performance and robust organic growth, which offset the impact of low energy prices on earnings. We’ve continued to successfully deploy our strong free cash flow into customer oriented investment programs that have supported growth. 2015’s operating earnings represented a third year of growth in earnings. Now, let me just mention a few of the year’s highlights. PSE&G was named Electric Light & Power’s Utility of the Year and was named the most reliable utility in the mid-Atlantic for the 14th consecutive year. But we’re not resting on those laurels. PSE&G invested approximately $2.7 billion during 2015 on programs to further enhance the system’s resiliency and its reliability. During the year, PSE&G placed into service key backbone transmission lines, such as the Susquehanna-Roseland line as well as the Mickleton-Gloucester-Camden line, which are designed to meet the needs of customers today and well into the future. PSE&G invested over $550 million on programs under its $1.2 billion Energy Strong initiative. These programs are designed to strengthen and protect the electric and gas distribution system from the impacts of extreme weather. During the year, PSE&G also received approval from the New Jersey Board of Public Utilities to invest an additional $95 million in its award winning energy efficiency programs and to continue the work begun under Energy Strong, replacing aging cast iron natural gas pipes. The $905 million gas system modernization program represents the 14th multi-year investment program approved by the BPU since PSE&G’s last base rate case and this speaks to the state’s support of infrastructure investment that meets the needs of customers. PSE&G’s investment program, supportive revenue recovery mechanisms and tight control of O&M expenses have provided growth in PSE&G’s operating earnings of approximately 13% per year for the five year period ended 2015. During this period, PSE&G’s rate base expanded at a rate of 11% per year and importantly, we’ve been able to support this growth as customer builds have declined. But 2015 was not just a year of PSE&G accomplishments. PSEG Power’s strong operating performance supported earnings in line with guidance for the full year, despite very difficult market conditions. The nuclear fleet operated at a capacity factor of greater than 90% for the year and accounted for 54% of the fleet’s output. Power’s gas fired combustion turbine fleet set a new record for output. This improves on the prior record established in 2014. The fleet’s performance is benefiting from investments that have improved its efficiency, increased its capacity and provided greater access to low cost gas supply. The flexibility and diversity of Power’s fleet have allowed us to provide approximately $500 million of positive free cash flow in 2015, even during soft energy market conditions. Power also plans to invest $2 billion over the next 3 to 4 years to add approximately 1,800 megawatts of new, efficient combined cycle gas fired turbine capacity. The Keys Energy station which is located in Southwestern MAAC will extend Power’s footprint in this core PJM market, a new efficient unit at the Sewaren station in New Jersey will replace old, inefficient steam capacity. And after clearing the most recent capacity auction in New England, Power will construct a new 485 megawatt combined cycle unit at its existing Bridgeport Harbor station site, giving us an enviable and growing position in both energy and capacity markets in Southwestern Connecticut. The addition of these units will transform Power’s generation mix as its ownership of efficient reliable gas-fired capacity will grow to exceed 5,000 megawatts in 2019. At that time, the combined cycle gas turbine fleet will surpass the size of Power’s ownership in nuclear capacity and secure Power’s position as a low cost generator with modern, flexible, clean assets that remain capable of meeting the demands for reliability in today’s markets. Power also grew its investment in contracted solar energy. In 2015, Power added two projects representing an investment of approximately $75 million in utility scale grid connected solar energy. And earlier this year, Power announced that it will invest an additional $150 million in three projects that bring its portfolio of solar projects to 240 megawatts DC of clean renewable energy. All projects in this portfolio are under long-term contracts with credit worthy customers. So as you can see, we continue to explore opportunities to expand and optimize Power’s fleet, although I will add that we do not see any new generation build in the foreseeable future, although you never say never, but we don’t plan any at this point in time. Our balance sheet continues to provide us with a competitive advantage to finance our capital programs without the need to access the equity markets. We ended 2015 with strong credit metrics and the extension of bonus depreciation through 2019 is expected to provide enterprise with an additional $1.7 billion of cash during this period. Our investment program calls for a 21% increase in capital spending to $11.5 billion for the three years ended 2018 from capital invested during the three year period ended 2015. Approximately 72% of that amount or 8.3 billion over this timeframe will be invested by PSE&G on transmission and distribution infrastructure programs that customers will require for reliability. This level of investment is expected to yield growth in PSE&G’s rate base for the three years ended 2018 of 10% per year, even after taking into account the impact of bonus depreciation on rate base. The remaining approximate 27% or $3.2 billion of expected capital investments will be made at Power. The majority of Power’s investments will be devoted to expanding its position in new, efficient, clean gas-fired generating capacity as I mentioned already, all of which, Keys, Sewaren and Bridgeport Harbor are expected to exceed our long standing and unchanged financial returns expectations. With our strong balance sheet, we remain in a position to increase our capital investment across the company. We have a robust pipeline of opportunities and plan on providing you with an update of our 5-year outlook for capital spending at our annual financial conference on March 11. In total, the investment programs at PSE&G and Power are focused on meeting customer needs and market requirements, with an energy platform that is reliable, efficient and clean. The strategy we implemented has yielded growth for our shareholders as we have met the needs of our customers. The continued successful deployment of strong free cash flow into customer oriented regulated investment programs is expected to support 14% growth in utility’s earnings to 60% of enterprise’s 2016 operating earnings as the results for the full year are forecast at $2.80 to $3 per share. Our guidance for 2016 takes into account the impact on demand from the continuation of unseasonably mild weather conditions in January and early February. The Board of Directors’ recent decision to increase the common dividend by 5.1% to the indicative annual level of $1.64 per share is an expression of our confidence in our outlook, the continued growth of our regulated business and an acknowledgement of our strong financial position. We see the potential for consistent and sustainable growth from the dividend as an important means of returning cash to our shareholders. Of course, none of our success would be possible without the contribution made by PSEG’s dedicated workforce. I look forward to discussing our investment outlook in greater detail with you at our March 11 annual financial conference. But for now, I’ll turn the call over to Dan for more details on our operating results and we’ll be available to answer your questions after his remarks. Dan Creeg Thank you, Ralph and good morning, everyone. As Ralph said, PSEG reported operating earnings for the fourth quarter of $0.50 per share versus $0.49 per share for the fourth quarter of 2014. Our earnings in the quarter brought operating earnings for the full year to $2.91 per share or 5.4% greater than 2014’s operating earnings of $2.76 per share and at the upper half of our guidance of $2.85 to $2.95 per share. And on slide 4, we provide you with a reconciliation of operating earnings to net income for the quarter. We’ve also provided you with information on slide 10 regarding the contribution to operating earnings by business for the quarter and slides 11 and 13 contain waterfall charts that take you through the net changes in quarter-over-quarter and year-over-year changes in operating earnings by major business and I’ll review each company in more detail starting with PSE&G. PSE&G reported operating earnings for the fourth quarter of 2015 of $0.31 per share compared to $0.32 per share for the fourth quarter of 2014 and that’s shown on slide 15. PSE&G’s full year 2015 operating earnings were $787 million or $1.55 per share compared with operating earnings of $725 million or $1.43 per share for 2014, reflecting a growth of 8.6%. PSE&G’s earnings for the fourth quarter benefited from a return on its expanded capital program, which partially offset the impact of earnings from unseasonably mild weather conditions and an increase in operating expenses. PSE&G’s return on an expanded investment and transmission and distribution programs increased quarter-over-quarter earnings by $0.03 per share. Mild weather conditions relative to normal and relative to last year reduced electric sales and lowered earnings comparisons by a penny per share. Recovery of gas revenue under the weather normalization clause offset the impact on earnings of the abnormally warm weather on sales of gas. And higher expenses including pension and other items reduced quarter-over-quarter earnings comparisons by $0.03 per share. Economic conditions in the service area continued to improve. On a weather normalized basis, gas deliveries are estimated to have increased 2.1% in the quarter and 2.2% for the year. Demand continues to benefit from an improving economy and also from the impact of lower commodity prices on customer’s bills. Electric sales on a weather normalized basis are estimated to have increased by 0.8% and 0.5% for the fourth quarter and for the year respectively. The estimated year-over-year growth on electric sales is more representative of our long term expectations for growth. PSE&G implemented a $146 million increase in transmission revenue, under the company’s transmission formula rate for 2016 on January 1. PSE&G’s investment in transmission grew to $5.7 billion at the end of 2015 or 43% of the company’s consolidated rate base of $13.4 billion at year end. As you know, transmission revenues are adjusted each year to reflect an update of data that was estimated in the transmission formula rate filing. The adjustment for 2016 which we will file in mid-2017 will include the impact of the extension of bonus depreciation which was executed after our transmission formula rate filing. This adjustment will reduce transmission revenue as filed by about $27 million. But we will accrue that for accounting purposes in anticipation of the reduction in revenue as we report our 2016 results. We are forecasting growth in PSE&G’s operating earnings for 2016 to a range of $875 million to $925 million. And forecast reflects the benefits of continued growth in PSE&G’s rate base and a decline in pension expense. Turning to Power, as shown on slide 19, Power reported operating earnings for the fourth quarter of $0.19 per share compared to $0.18 per share a year ago. Results for the quarter brought Power’s full-year operating earnings to $653 million or $1.29 per share compared to 2014’s operating earnings of $642 million or $1.27 per share. Power’s adjusted EBITDA for the quarter in the year amounted to $235 million and $1.563 million, respectively, which compares to adjusted EBITDA for the fourth quarter of 2014 of $271 million and adjusted EBITDA for the full year of 2014 of $1.588 million. The earnings release as well as the earnings slides on pages 11 and 13 provide you with a detailed analysis of the impact on Power’s operating earnings quarter-over-quarter and year-over-year from changes in revenue and cost and we have also provided more detail on generation for the quarter and for the year on slides 21 and 22. Power’s operating earnings in the fourth quarter reflect the impact of strong hedging and tight control on operating expenses which offset an anticipated decline in capacity revenue and the impact of unseasonably warm weather on wholesale energy prices. The decline in capacity revenues associated with the May 2015 retirement of High Electric Demand Day or HEDD peaking capacity in PJM reduced quarter-over-quarter earnings comparisons by $0.04 per share. An increase in the average price received on energy hedges coupled with the decline in fuel costs more than offset the impact on earnings from a reduction in gas sales. And these two items together netted to a quarter-over-quarter improvement in earnings of $0.02 per share. Power’s O&M expense for the quarter was unchanged relative to year ago levels. An increase in depreciation expense and other miscellaneous items was more than offset by the absence of a charge in the year ago quarter resulting in a net improvement in quarterly earnings comparisons of $0.03 per share. Turning to Power’s operations, Power’s outputs during the quarter was in line with the year ago levels. For the year, output increased 2% to 55.2 terawatt hours and the level of production achieved by the fleet in 2015 represented the second highest level of output in the fleet’s history as a merchant generator. Growth was supported by improvements in the fleet’s availability and efficiency. The nuclear fleet operated at an average capacity factor of 90.4% for the year producing 30 terawatt hours or 54% of total generation. Efficient commodity cycle gas turbine capacity was rewarded in the market with an increase in dispatch levels. And Power’s DCG fleet set a generation record during the year at each of the Lyndon Station and Bethlehem Energy Center set individual records. Output from the commodity cycle fleet grew 11% to $18.4 terawatt hours or 33% of total output during the year. Power market demand for our coal units reduced output from those stations to 5.8 terawatt hours in the year or 11% of output. And lastly, the fleet’s peaking capacity produced just under 1 terawatt hours or 2% of output for the year. Power’s gas-fired commodity cycle fleet continuous to benefit from its access to lower priced gas supplies in the Marcellus region and for the year gas from the Marcellus supplied 75% of the fuel requirements for the PJM gas-fired assets. This supply [indiscernible] and implied by market pricing and allowed Power to enjoy fuel cost savings in the fourth quarter similar to the levels that enjoyed in the year-ago quarter despite weak energy prices. And for the full year, Power enjoyed positive spreads relative to the market. The year-over-year realized spot spreads in 2015 were lower than what was realized in 2014 given the decline in energy prices. Overall, Power’s gross margin improved slightly to $38.83 per megawatt hour in fourth quarter versus $37.40 per megawatt hour in year ago and for the year Power’s gross margin amounted to $42.25 per megawatt hour versus the $42.41 per megawatt hour last year. And slide 24 provides detail on Power’s gross margins for the quarter and for the year. Power is expecting output for 2016 to remain unchanged at 54 to 56 terawatt hours. Following the completion of the basic generation service or BGS auction in New Jersey earlier this month, Power has 100% of its 2016 base load generation hedged. Approximately 70% to 75% of Power’s anticipated total production is hedged on an average price of $51 per megawatt hour and Power has hedged approximately 45% to 55% of its forecast generation in 2017 of 54 to 56 terawatt hours at an average price of $50 per megawatt hour. Looking forward to 2018, Power’s forecasting improvement in output to 59 to 61 terawatt hours with the commercial startup in mid-2018 of Keys and Sewaren stations that Ralph mentioned earlier. Approximately 15% to 20% of 2018’s output is hedged at an average price of $54 per megawatt hour and Power assumes BGS volumes will continue to represent approximately 11 to 12 terawatt hours of deliveries and this number is very consistent with the 11.5 terawatt hours of deliveries we saw in 2015 under the BGS contracts. Our average hedge position at this point in time represents a slightly smaller percentage of output hedged versus what you saw a year ago and at that time, Power was able to take advantage of market prices influenced by the colder-than-normal weather conditions of last winter. Average hedge pricing includes the impact of recently concluded DGS auction and the auction for the three-year period beginning in June 1, 2016 ending May 31, 2019 was priced at $96.38 per megawatt hour in the PS zone. This contract for one-third of the load will replace in 2013 contract for $92.18 per megawatt hour which expires on May 31, 2016. And we do remind you from time to time that the items included in the average hedge price which influenced Power’s revenue but don’t support Power’s gross margin. Our average hedge price for 2016 of $51 per megawatt hour reflects an increase in the cost of elements such as transmission and renewables associated with serving our full requirements hedge obligations. And based on our current hedge position for 2016, each $2 change in spot spreads would impact earnings by about $0.04 per share. Power’s operating earnings for 2016 are forecasted at a range of $490 million to $540 million. That forecast includes an adjusted EBIT DA of $1.320 million to $1.4 billion. Forecast reflects a year-over-year decline in capacity revenues associated with the May 2015 retirement of the HEDD peaking capacity. Operating earnings for the year will also be influenced by the re-contracting of hedges at lower average price and a decline in gas sales. And most of the decline in Power’s operating earnings forecast for the full year 2016 is expected to be experienced in the early part of 2016. With respect to our enterprise and other, we reported operating earnings in the fourth quarter of $4 million which compares to a loss in operating earnings of 44 million or $0.01 per share for the fourth quarter of 2014. And results for the quarter brought full year 2015 operating earnings to $36 million or $0.07 per share compared with 2014’s operating earnings of $33 million or $0.06 per share. The difference in quarter-over-quarter operating earnings reflects the absence of prior year tax adjustments as well as other parent related expenses in 2015. For the year, PSEG Long Island’s earnings contributions of $0.02 per share was in line with expectation. And looking forward to 2016, operating earnings for PSEG Enterprise and Other are forecasted at $16 million. Next I want to provide an update on our pension. At the beginning of 2016, PSEG has elected to measure service and interest costs for pension and other postretirement benefits by applying the specific spot rates along the yield curve to the plants liability cash flows rather than the prior use of a single weighted average rate. We believe the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plant’s liability cash flows to the corresponding spot rates on the yield curve. The change does not affect the measurement of the plant obligations and we estimate this change will reduce 2016 pension and OPEB expense by approximately $34 million and $13 million, respectively net of amounts capitalized from what would have been without this change. On a year-over-year basis, the pension expense is expected to decline, pension and OPEB expense is expected to decline by $25 million from 2015’s level of expense. We ended 2015 with 91% of our pension obligations funded and minimum need for cash funding of obligations over the next several years. With respect to financial condition, it remained strong. We closed 2015 with $394 million of cash on hand and debt representing 43% of our consolidated capital position and debt at Power representing 27% of our capital base. PSEG’s capital program for the three years ended 2018 is currently expected to approximate $11.5 billion. This represents a 21% increase over the level of capital invested over the prior three year period as PSE&G and Power focused on modernizing their infrastructure to meet the needs of today’s marketplace. We have ample capacity to finance our current capital program. In addition, we estimate that the change in bonus depreciation as Ralph mentioned will provide an additional $1.7 billion of cash through 2019 with most of this cash received over the three year’s ending 2018. And of this amount, $1.2 billion of the cash will be at PSE&G and $500 million will be at Power. And as mentioned, our forecast for double-digit growth in PSE&G’s rate base through 2018 does take into account the impact of bonus depreciation on the rate base. We plan to provide an updated five year view of the capital spending at the Annual Conference on March 11. So regarding to earnings for 2016 in $2.80 to $3 per share in line with our 2015 operating results as forecast growth at PSE&G offsets the impact of lower energy prices on Power’s operating earnings. The company remains on solid footing and we continue to focus on operational excellence, we remain disciplined in our approach to investment strategy and maintain our financial strength. Common dividend was recently increased 5.1% to the indicative annual level of $1.64 per share and we believe we can provide shareholders with consistent and sustainable growth in the dividend going forward. And with that, we are ready to answer your questions. Question-and-Answer Session Operator [Operator instructions] Your first question comes from the line of Jonathan Arnold with Deutsche Bank. Please go ahead. Jonathan Arnold Good morning, guys. Ralph Izzo Hey, Jonathan. Jonathan Arnold A couple of questions on the change in pension accounting methodology, could you just give – is this designed to bring you more into line with standard practice or something – can you just give us some perspective around what drove that change? Ralph Izzo Yeah, I think it will probably increasingly look more like standard practice. In applying an interest rate we have normally done a weighted average rate which is across all of the cash flows and some recent determination has been made that in looking at the yield curve and the timing of your actually payments and the timing of the interest by virtue of shape of the yield curve be more accurate method was to apply the near-term interest rates to the near-term cash flows and the longer term interest rates to the longer term cash flows. So we’ve been looking at this for a while and in addition to being a more accurate method I think you will start to see this more and more in others. Jonathan Arnold Your sense is that others have not – who you haven’t adopted this it yet, but you think that will go that way, is that what you’re saying? Ralph Izzo Yeah, so our intel from talking to our advisors is we’re probably somewhere between 30%, 40%, 50%, so companies are pursuing and a bunch of the others are investigating the same. We’ve seen some of this from other leases that we’ve seen from others as well. Jonathan Arnold Okay. And can you give us a sense, is the change we’re seeing in 2016 something that would all else equal will just persist into 2017 just a change of basis one piece? And then secondly, can you parse out the impact to the utility versus power? Ralph Izzo Yeah, on the second piece, it’s about half and half is the general way to think about it. And with the yield curve that rises over time, you will see a moderation of the benefit of this method over time, but remaining positive, based upon all the current assumptions in place through the balance of the five year plan period. It remains positive, but declines over time. Jonathan Arnold Okay. And can I just add one other topic, Enterprises, the uptick in 2016 is that mostly the Long Island contract? Ralph Izzo That was correct, Jon. Some of you heard. Jonathan Arnold Yeah, we missed the answer. Great. Thank you. Operator Your next question comes from the line of Keith Stanley with Wolfe Research. Please go ahead. Keith Stanley Hi, good morning. The $11.5 billion of CapEx over 2016 to 2018, if you take 72% of that at the utility, it seems like utility CapEx for 2016 to 2018 is about maybe I don’t know, $750 million higher than what you showed in a chart at EEI. Can you just confirm if I’m reading that right and if so in what areas are you investing more money now over the next three years? Ralph Izzo So Keith, the answer is you’re correct and we will detail not only that, but the full five years on March 11, but it’s the same areas we have been. It’s largely transmission related, and there is an element of Energy Strong in there as well, but we will give you the details of that as well as any new initiatives that we plan to pursue in the five-year time horizon on March 11. Keith Stanley Okay. And one other one, just what ROE are you assuming at the distribution business that PSE&G in 2016 and what ROE did you earn at distribution last year? Dan Creeg So you remember, ROEs are a blend of an allowed base, ROE of 10.3, and then myriad 14 to be exact of various programs that we have had approved since then, that range from 9.75 to 10.3, but with a couple of them also the beneficiary, I think that’s the tax credit in some of the solar programs. So we are earning on a longer term, but you have to do the – some of the parts so to speak of each of those programs. Keith Stanley So netting out some of those programs you earned 10.3 on call it core distribution last year, and I mean, are you just assuming that you’re earning precisely your allowed return and that’s what you’re saying you earned last year? Dan Creeg So on the core distribution, yes, the 10.3, and on Energy Strong, we are going to earn the 9.75 and on solar for all, we are going to earn 10, and on energy efficiency, we are going earn 9.75 and so that’s what I am trying to point out, and because of to varying degrees contemporaneous nature of the returns we do stick to those, we do accomplish those objectives. Keith Stanley Okay, thank you. Operator Your next question comes from the line of Julien Dumoulin-Smith with UBS. Please go ahead. Julien Dumoulin-Smith Hi, good morning, can you hear me? Ralph Izzo Yes, Julien. Julien Dumoulin-Smith Excellent. So I wanted to go back a little bit to the latest BGS Auction, and ask you, if you can elaborate a little bit on what exactly drove the year-over-year results? And perhaps at least our perception of a reduction in the risk premium, can you elaborate kind of what the dynamics you saw? Ralph Izzo Yes, I mean, some of the bigger pieces, Julien, I think are fairly transparent from what you can see from a market perspective. I think we saw a little bit of a decline in the energy prices, which is kind of where you spot as a baseline for the auction. And then probably the couple of other areas where you’ve seen the biggest change is against that decline, as you have seen a bump on the transmission side and you have seen a bump related to some of the green costs that are involved. So you can track the green cost here in New Jersey, [indiscernible] and you can track the transmission fact, I think the BPU even sends out some of the transmission cost that ultimately get embedded in. and then finally, the last big piece, which is also fairly transparent is the capacity piece and those auctions take place in advance of by virtue of their three-year forward market and the BGS three-year forward market. They place in advance of the BGS auction. So those are your biggest movers. And there is other pieces obviously in there, there is ancillary, and different components, but those are the biggest pieces that you see related to the changes. Julien Dumoulin-Smith But just coming back, clearly some of those big changes move in year-over-year, but at least from our calculations, it seems that even adjusting for that there might have been a little bit less of a premium there, just curious. Ralph Izzo I mean, we don’t really talk necessarily about what kind of a premium you would see in the product, but I think you can – most of those pieces are transparent enough that you can build out and see what the elements of them are and I think, on balance, you’re seeing a bit of a decline on the energy side, and you’re seeing a bit of a roll up coming off in the other direction related to both transmission agreement. Julien Dumoulin-Smith Got it. Fair enough. Maybe going back to the last question a little bit more about the utility regulatory, how are you thinking about trackers in a post-great case scenario as you think about rolling at least the legacy programs in the base rate et cetera? Can you kind of talk about perhaps what the subsequent role might look like? Ralph Izzo Sure. While we are pleased with the success we have had, Julien over these past several years with these programs, we have been talking to the staff about – in particular the gas program, which clearly has a multi-decade run that it would need to do all of the work that the system requires of it, I am talking about replacing the cast iron, that we would like to break away from this incremental approach and into more of a longstanding approach. For no other reason that it would be beneficial to develop the infrastructure, primarily people, that one needs to sustain these programs, right. So right now, the way we run the programs is we work for contractors and we bring in the folks that are needed and we enter into this conversation six months before the program expires. But will we need more, I am not quite sure. Well, we have to wait for the BPU, so when can you find out, I will get back to you since possible, and that’s not the way we typically run a 110-year old company. We like to have training programs, bring people in as an apprentice and have them climb the technical ladder and have a nice long career and that’s a much more efficient way to use customer rates. So I think that program in particular could be a template for the type of ongoing things we want to do, we were close second to that. As you may recall, Energy Strong, we had put forth the ten-year plan that got approved for three years. And some of the cleaner technologies, whether solar or energy efficiency that will be needed to meet the state’s own renewable portfolio standard or what eventually becomes of CPP and whatever carnation takes, reincarnation that takes, I think will lend themselves to more programmatic and longstanding programs that we can anticipate and rationally equip ourselves to execute. So those conversations are going on with the Board staff now and to their credit, their responses well, you should have confidence, you have come in 14 times and 14 times we said yes and that’s true. So the question is how much of an investment risk are you willing to make in equipment and training programs and people, when the yes, it’s pretty much assured but has different forms, half the programs, half the duration and maybe three quarters of the run rate. So it’s a very constructive dialog right now to be continued. Julien Dumoulin-Smith Great. Thank you so much, guys. Operator Your next question comes from the line Praful Mehta with Citigroup. Please go ahead. Praful Mehta Hi, guys. Morning. My question firstly you guys sit in a very interesting spot where you own all three assets, coal, gas and nuclear and it’s interesting the trends you highlight with gas capacity factors increasing, coal reducing. My question is, how are you thinking about asset life of these three classes of assets given the market conditions you see now? And what does that mean in terms of leverage levels that you’re comfortable with for the Power business? Ralph Izzo So one of the things that’s equally important to the fuel diversity of our assets is the technology diversity and performance features of our assets. So obviously, gas we have some combined cycle gas turbines, which once upon a time, we called load following, which we are looking more and more like base load. But we also have a pretty robust and healthy peaking fleet. And similar in our coal assets, we have Keystone kind of which are rightfully described as base load and candidly Hudson, Mercer, and Bridgeport stations have become more peaking with Hudson and Mercer having the additional flexibility to be able to run on gas. So it’s not just a question of fuel diversity, it’s what part in the dispatch queue, the asset can play and whether it starts, stops features and in that respect our diversity serves us well. Now, you probably picked up that we would anticipate retiring the Bridgeport Harbor coal unit in five years provided that we are successful executing the permits for the new 500 minus combined cycle units at Bridgeport Harbor, which we don’t anticipate any difficulties in doing so given the community benefits agreement we have achieved with some important stakeholder groups in Bridgeport. And I will let Dan finish up on the leverage of power, but once again, our base FFO to debt expectations are 30% and we will give you more details when we see in March, but we were well over that prior to bonus depreciation, and with bonus depreciation that number has gotten even bigger. But Dan, you may want say anything? Dan Creeg Yes, I mean, the only thing I would add is obviously from the credit perspective, power’s FFO to debts are well above the 30% threshold that we have with the rating agencies to hold our existing rating. So that’s not something that we get concerned about at all. We have an awful lot of financial strength there. But I think as you do look forward, we will see a shift in the fleet and maybe be that’s kind of what your question is getting at. We have got three new efficient combined cycle plants and if you look backwards, I said in my remarks that we have some of our HEDD units, those were older peaking units that were retired for environmental purposes and they are going to be replaced by new efficient combined cycle clean gas units. So the fleet really will take out a different look into the future and we will be more efficient and we will have a better profile and be more competitive in the market. Praful Mehta Got you. So as you see that fleet profile changing, are you seeing leverage levels kind of match that in terms of increasing given the quality of the new gas fleet that you’re kind of bringing on? Dan Creeg I think we will see some leverage increase by virtue of the spend that will have, but I think we will remain well above where we need to from the rating agency perspective. That capacity at Power is extremely strong and is expected to remain that way, and bonus depreciation helps on that side too. We have – on the Power side of the business, we have the benefits of bonus depreciation without the detriments of any rate base reduction. Praful Mehta Yes, absolutely, got it. And just secondly is a more philosophical question. As you think about the fate of Power with the consolidated business, is there at any point a view that this business needs to be a stand-alone entity or do you kind of see this more as part of the consolidated business in the next two, three year timeframe as well. Ralph Izzo So as I have said before, I do see over time, you’re not going to get me to pick a time frame now. I see these businesses separating, the strategic flexibility of both would be enhanced by doing that. Some of the tactical benefits is keeping them together right now, which is the financial synergy – financial complement that Power provides to utility, we have talked about power’s new plants, but for the past five years and for the next five years, it looks like the utility will be out-spending Power almost 3 to 1 and Power is a great source of equity for that with its funds from operation. Secondly, the complement and utility provide on the customer bill is a huge advantage to us. And the support cost synergies that exists with two companies are big advantage to us as well. But as Power grows in New England, as it grows in New York State and other places, it will need to use its own FFO for investment opportunities and that free cash flow that remains to help the utility will be decreased. There will be more customers that it will be serving outside of the utilities territory so, that complementary nature will decrease. And as they both grow, the corporate overhead vital functions that corporate support groups provide, will be a smaller piece of the overall operating budget. So I think over time, the tactical benefits of staying together decrease, and the strategic advantages of separating will increase. But we’re not there today. So, yet again – continue. Praful Mehta Okay. That’s really helpful. And I know you’re not talking timing, but I guess the benchmark or at least the milestones as we look for is, those three factors in terms of that strategic benefits as that I guess reduces in terms of the fit then the probability or likelihood of some timing of separation kind of increases. Is that a fair assessment? Ralph Izzo Yes, so qualified yes to that. I mean, there is not magic date, there are a host of parameters one looks at, what are the market dynamics, what’s the composition of the shareholder base, are there other triggering events that could accelerate ones point of view of where the tactical benefits are now greatly reduced. So I don’t mean to be long-winded on it, but you ask a very complicated question albeit wrapped in some trout of simplicity that the Board of Directors looks at on a regular basis and so I am just giving you kind of a general point of view on that. But it’s fraught [ph] detailed analysis on a pretty regular basis. Praful Mehta Got you. Very helpful, thank you so much. Operator Your next question comes from the line of Michael Lapides with Goldman Sachs. Please go ahead. Michael Lapides Hey, guys, congrats on a good year. A couple of questions and these may be for Dan because some of them are kind of a little bit down in the weeds or in the nitty-gritty. Can you talk to us about the earnings or EBITDA contribution that maybe Power gets from things like trading or doing some of the optimization as part of the LIPA deal? And can you talk to us about the overall earnings Power you expect to get over time from the broader LIPA O&M services contract? Ralph Izzo Even though Dan can answer it, Michael I just want to point out that I try to pay attention to these things. Michael Lapides I totally understood Ralph. Ralph Izzo So, Power’s trading group is about a $0.01 a share for LIPA and all-in LIPA is grow to about $0.07 or $0.08, so I think the share will probably be closer to the $0.05 and then stepping up $0.07 or $0.08, $0.05 or $0.06 this year, close to $0.07 or $0.08 next year. But Dan go ahead and tell him I’m wrong if I am. Dan Creeg [indiscernible] right order of magnitude. Ralph Izzo Order of magnitude. Dan Creeg It will be $0.07 next year across the enterprise but there is just a small piece of that caught $0.01 or so that’s at the Power side of the business where that’s coming from. Michael Lapides Got it. And do you get a significant margin from things like ancillary revenues or ancillary services in PJM or ISO-New England. Just trying to think about the components not just within BGS but within your broader margin in Power? Dan Creeg I don’t have an ancillary number in front of me Michael, I don’t know that we’ve kind of provided the breakdown of all the different components of how Power makes money and far and away the biggest pieces are your capacity margin and your energy margin. There is a host of different elements that we work our way through as we manage a portfolio as a whole. I mean if you’re kind of talking somewhere in the bucket of a $0.05 a share or something like that on the ancillaries that’s probably in order of magnitude number. But we haven’t broken out a lot of the pieces beyond – the biggest pieces which I think gets folks most of the way home if you look at your capacity margins, we’re very transparent about that Math and provide that within the investor relations decks that we end up on together and the same with respect to energy side of the business. Michael Lapides Got it. And finally when we think about the combined cycle fleet at Power I mean you’ve seen a significant uptick in terms of how much they can run. Just curious from a physical standpoint, what do you think – I guess I’ll use the word maximum output level like how high do think they can physically run from a capacity factor standpoint versus where they been running for the last 12 to 24 months? Dan Creeg I don’t think that there is a physical limit to what they can do; I mean they are ultimately going to be off-line for maintenance just like any other facility would but there is nothing that snaps those plants from running as long as they are called. And it’s not a refueling outage like you would see at a nuclear plant where you would have to shut the unit down to refuel it but periodically there is major maintenance that goes on at these facilities were the unit needs to be worked on but I think we’ll have the advantage as well within the units that we have of having a kind of clean and new unit that won’t have that effect over a period of time when it starts up. Ralph Izzo And don’t Michael, we’ve also had a couple of significant improvement programs on our combined cycles we’ve improved the gas path which has actually allowed us to stretch out the major maintenance cycles and modestly improve the heat rates. And I’ll double check the numbers, we’ll certainly show them in March but I think our forced outrage rates have dropped even while our capacity factors have gone up, which is always a great sign and that just means we are taking better care of the machines. So they’re running at about 65%, 66% capacity factor now. You never want to promise 100% on any mechanical device but I have not picked up from any of our team that worried about us over taxing these units. Michael Lapides Got it. And then last one, Ralph, just a little curious, your thoughts on the impact if any of the Ohio PPA contracts and what that means for that competitive market dynamics and design in PJM? Ralph Izzo So it depends on how that’s structured right, I mean, you’re clearly – there was situation in New Jersey under what we call the LCAPP law there, their statute mandate is that winners of those contracts bid at zero and clear the auction and that was a just an egregious attempt to crush artificially capacity prices in the region. So we are participating in an industry group in Ohio to make sure that whatever is agreed upon doesn’t artificially move the market in a way that disadvantage participants who don’t have the protection of these contracts. I’d like to think that Ohio has been a long-standing supporter of competitive markets and whatever gets structured out there gets structured in that way. But what I’d like to think that we’re going to carefully monitor what actually is decided to maximize the chances that is indeed what happens. Michael Lapides Got it. Thanks, Ralph, thanks, Dan. Much appreciated, guys. Operator Your next question comes from the line of Gregg Orrill with Barclays. Please go ahead. Gregg Orrill Thank you. I was wondering if you could revisit the topic of bonus depreciation. I think you said that $1.3 billion at PSE&G and $1.7 billion overall was that 2015 to ’18, first of all? Dan Creeg The $1.7 billion total is $1.2 billion to the utility and $500 million to Power. And that runs you out through ‘19. Most of the cash comes in through ‘18. Gregg Orrill Okay. So part of that you were – at the utility you were going to be accruing into the next case, is that generally the way you are going to deal with the bonus depreciation accounting at the utility? Dan Creeg Yeah, I think the way to think about it Gregg is that to the extent of transmission the impact of that will come through on a contemporaneous basis. So we will while bonus was approved after we filed our formula rate for the 2016 year, we know that it’s there and we’ll accrue that from an accounting perspective and we’ll do that true-up in future filings. But as we go forward you’ll see that true-up every year with respect to the transmission piece of the bonus. Similarly, with elements related to Energy Strong, with elements related to GSMP, all the clause-related updates will take place as we file those contemporaneous and near contemporaneous filings. And then the balance of what’s left which really sits with the base amount or PSE&G that will await the next rate case. Operator Your next question comes from the line of Travis Miller with Morningstar. Please go ahead. Travis Miller Hi, thank you. I was wondering if you guys look across your entire CapEx program both Power and PSE&G, what parts of that make you most nervous? And either nervous that you would not meet the budget that you’ve set out or nervous that you wouldn’t meet either the allowed returns or the hurdle rates that you’ve set out for those projects? Ralph Izzo If we’re nervous about anything Travis, we make sure we take action to fix it so we don’t stay nervous but I know you know that. I guess I’d say the biggest things that we pay attention to are regulatory and environmental mandates that don’t add to the return expectations of our shareholders and quite candidly on occasion don’t really benefit customers commensurate with the costs that need to be put into it. But other than that, as you well know, we show up at a lot of places to make acquisitions and to expand our asset base and invariably lose. So I don’t think anyone would ever accuse us of being bullish or undisciplined in how we spend our money. And the good news is that most of that environmental spending is behind us. So we talked a lot about hey we’re building three combined cycle units and let’s make sure we have the team in place to manage those because they’re not all within a city block of each other we’ve got one in Maryland, one in New Jersey, one in Connecticut and I probably spent an hour and half yesterday with our head of fossil talking about what his needs are and how we can make sure that those are met. So, I say in general, its mandates that don’t produce the customer or shareholder benefit that the regulator thinks they do. Fortunately most of those are behind us and to the extent that if we didn’t respond to the expanded construction program in Power, I would be nervous about that but we are responding and I guess the proof that I put forth for you on that is we have quadrupled in the past five years that transmission program and we’ve delivered those projects on schedule and on budget. So –. Travis Miller Okay, that’s great and then more you mention the word retail in the past and just wondering if you could update if that’s still in the Lexicon strategy? Ralph Izzo Yeah, it’s still it is. But it remains in the Lexicon as a defensive move to help us make sure we can be more effective in managing our basis risk and key is going to go a long way to that and it’s not a retail place so there are things we can do other than retail. But we are disciplined and cautious as you know I’m not a big fan of the retail business, I think everybody falls in love with it in the declining price environment that’s typically when you can make a lot of money in retail, it’s when prices rise and people are caught short for whatever reason that life isn’t quite so pleasant. So we would look at it purely as a small part of our output truly for defensive purposes managing basis risk and we’re still looking at that and working on it. Operator Your next question comes from the line of Stephen Byrd with Morgan Stanley. Please go ahead. Stephen Byrd I’m wondering if you could lay out what the year-end rate base was for transmission and then for the utility overall? Ralph Izzo I don’t have that number – transmission was 40 something, 13.4 [ph] is the number we provided for the utility and I think 43% of that was transmission. Stephen Byrd Got it, thanks very much. And you’ve been – on solely you’ve been continuing to grow there, how do you see sort of the overall market opportunity there, ability to achieve further growth in solar? Ralph Izzo So, Stephen we’ve seen as I think you’re aware we’ve carved out for ourselves kind of a modest sized portfolio really it’s the 250 megawatts DC I think consisted 14 or 15 projects. So these things range in size like 5 megawatts to 50 megawatts and many more closer to 5 than to 50. And we have very rigid return expectations they’re also supported by 25 to 30 year PPAs and they meet those return expectations. So, generally those returns are not available in some of the larger projects and we’ve developed a couple of partners who are really good about bringing those opportunities that they know we can execute on. So they’re willing to work with us. I do see that continuing to grow, it’s mostly driven by state RPSs and I don’t think we have baked in a number in terms of what size that will be. So when we talk about our capital program there isn’t a dollar of those projects in there yet. If I look back over the past three or four years, we’ve been pretty consistently doing anywhere from $100 million to $200 million of those projects. Kathleen Lally I was going to say I think that brings us to the end. I’m going to turn the call back over to Ralph at this time. Ralph Izzo Thanks Kathleen. So, looking forward to see you all hopefully in two weeks but really I hope there are three key points to take away from what Dan and I talked about today. First of all, we are genuinely excited about Power’s positioning. We’ve long had low cost nuclear and we’ve had a pretty good highly efficient combined cycle fleet but in three years, we’re going to have just an outstanding highly efficient combined cycle fleet. And all of our assets are going to be well positioned and I mean well positioned in the broader sense of the word there will be near load, they’ll be clean, they’ll be diversified fleet. And we’ll continue to look at opportunities to improve upon that fleet but you really should recognize that we’ve talked for a long time now about these three new units and I don’t foresee any circumstances at present that would suggest any additional new build on the horizon for us. Second point is the utility growth continues and we averaged 13% growth over the last five years and if you just take our ‘15 results and the midpoint of the utility guidance for ‘16, we’re going to grow at 14%. And yet utility bills will go down yet again this year because of the expiration of some charges. So the utility will represent 60% of earnings at the midpoint and it’s doing stuff that is very important to customers and will just continue marching along that path. So we had a good year is the final point and I think you’ll find that when we get together on March 11 that the next five years look even better. So looking forward to explaining that further when we see you in New York. Thanks everyone. Operator Ladies and gentlemen that does conclude your conference call for today. You may now disconnect and thank you for participating. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited. 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Ameren (AEE) Q4 2015 Results – Earnings Call Webcast

The following audio is from a conference call that will begin on February 19, 2016 at 10:00 AM ET. The audio will stream live while the call is active, and can be replayed upon its completion. If you would like to view a transcript of this call, please click here.