Xcel Energy Inc. (NYSE:XEL)
Company Conference Call
December 1, 2011 9:00 am ET
Ben Fowke – Chairman, Chief Executive Officer, President
Kent Larson – Senior Vice President, Operations
Teresa Mogensen – Vice President, Transmission
Teresa Madden – Senior Vice President, Chief Financial Officer
David Sparby – Vice President, Group President
David Eves – President, Chief Executive Officer – PSCo
Riley Hill – President, Chief Executive Officer – SPS
Judy Poferl – President, Chief Executive Officer – NSP Minnesota
Mark Stoering – President (incoming), Chief Executive Officer – NSP Wisconsin
Leslie Rich – JP Morgan
Greg Reiss – Catapult Capital
Andy Levi – Caris & Company
Paul Fremont - Jefferies
Ali Agha – SunTrust
Jonathan Arnold – Deutsche Bank
Good morning and welcome to Xcel Energy’s Analyst Meeting. Appreciate everyone stopping by this morning and also those of you that are listening on the webcast. We have a number of people from Xcel here today that will be presenting. Ben Fowke, who is our Chairman, CEO, President; Kent Larson, Senior Vice President, Operations; Teresa Mogensen, Vice President, Transmission; Teresa Madden, Senior Vice President, CFO; and in addition Dave Sparby, who is Vice President and Group President is going to host a panel of our four operating companies. The four operating company CEOs and Presidents are David Eves, PSCo; Riley Hill, SPS; Mark Stoering, NSP-Wisconsin; Judy Poferl, NSP-Minnesota. In addition, we have Tim Wolf, who is one of our Board members here and we have several other members from the Xcel Energy team, including Scott Wilensky, Senior Vice President, General Counsel; George Tyson, Vice President and Treasurer; and Jack Nielsen and Cindy Hoffman from Investor Relations.
What we’re going to do is we’re going to have three formal presentations, then Dave is going to host a panel of the operating company presidents, and then what we’re going to do is have a short Q&A with the four operating company presidents. Then Teresa Madden will finish up with the final presentation and then we’ll have another Q&A session more in depth with the management team.
Just want to remind you that today’s comments will include certain forward-looking statements, as you can see on this screen. In addition, all these comments are filed with our SEC reporting documents, so please keep in mind some of these forward statements may not necessarily come to fruition.
With that, let me introduce Ben Fowke.
Thanks, Paul, and welcome everyone. Let me apologize for my more than normal nasally voice today – I’m suffering from a little bit of a cold. As Paul said, I think we’ve got a really good forum for you today to give you a real in-depth view of our operations and our strategy for transmission and our financial strategy that’s so important to delivering value to you. So let me get started, and I want to really focus on three key components of our success, and that’s stakeholder alignment combined with the constructive regulatory environment in addition to a very attractive pipeline of investment opportunities. You put all three of those elements together and you get a recipe for success, and for us that means a 10% total shareholder return to you, our investors. We’ve been delivering on that promise. I think you’ll see today that we’re positioned very well to continue to deliver on that proposition.
Let me break down some of the components starting with stakeholder alignment. You see here, these are the key things you really need to have good stakeholder alignment – reliable service, customer choice – and I know that sounds odd coming from a regulated utility, and there are certain parts of our franchise that we can’t give enough choice to, such as Boulder, but generally I think we do a very good job of that. Policy alignment is extremely important. We have that. We continue to execute well on our game plan and continue to provide value to our customers – that’s obviously important – and you can’t underestimate the importance of being proactive with safety.
So those are the keys to stakeholder alignment, and let’s look at some of the components of that in more detail. You know, energy and electricity is the sort of thing that we’ve grown accustomed to taking for granted until you don’t have it, and I know all of you here are mainly from the northeast and you’ve experienced what it’s like not to have electricity. There were some pretty severe storms in the northeast. We heard about it back in the Midwest, back in Colorado, back in Texas. But what you might have not known is we’ve had our own bout of severe weather. We also had a very severe snowstorm in the fall in Colorado – green leaves still on the trees – and we had a lot of power outages as well. Why you didn’t hear about it, though, is because we restored that power very quickly. If you go to the summer, we had a devastating tornado that hit north Minneapolis, and the destruction was just catastrophic but we recovered very quickly. If you look at our SAIDI scores here, those are very good top quartile scores, so what we’ve been doing over the years is putting money into our system, staying on top of the investment. We do very good proactive planning and I think we do some very innovative things too when storms happen so we get restoration back up. So reliable service – it’s sort of the ante, and I think we’ve been delivering that.
As I mentioned before, customer choice in a regulated utility, you don’t always think of those going hand in glove but we really do provide a lot of choice for our customers. Clearly they need to take their energy from us, but we can give them options within those parameters. The first option we give them is a lot of options to help them manage their bill. We have industry-leading demand side management programs. We estimate that over the years since the early 90s we’ve (inaudible) the need for about 3,000 megawatts of generation through those programs, so it’s been very successful. It’s really been a win-win for our customers.
We can also give our customers choice on what type of energy they have. We some of the industry-leading renewable programs with our Windsource program where customers can be even greener than we already are, and of course our Solar*Rewards program where we are serving about 10,000 customers with rooftop solar have been very popular. So you can give customers choice, and I think we’ve done a good job of that as well.
Now this next slide here is extremely important – aligning with your policy makers is crucial if you’re going to have good stakeholder alignment, and historically and currently our stakeholders—our policy makers want a cleaner energy product. And you can see by this slide here, we have achieved tremendous reductions in emissions, and we have more to come and we’ll talk more about that today. But this does put us in good standing with our policy makers and I think it’s been very proactive when you see what’s happening with the EPA today.
As a result of those efforts, you see us having a more balanced fuel mix. We’re still going to have coal but we’re going to also have gas, we’re going to have nuclear, we’re going to have a healthy blend of all the various energy types and not leaning on any one resource. And what you probably don’t see on this slide is that as we go through this transition, we’re not only getting cleaner, reducing emissions, but we’re modernizing our infrastructure and that’s very important because that feeds right back to that reliability piece that I mentioned earlier.
And of course, as we’re modernizing that infrastructure, we’re spending billions of dollars and we need to make sure that we execute those projects on time, on budget, and at a great price point for our customers. Kent Larson and Teresa Mogensen will give you some more specific details, but I have to tell you if you look at Comanche 3, the coal plant we built in Colorado – well, if you could build a coal plant in Colorado today, I guarantee you couldn’t build it at 1,600 Kw. We built it, it’s a super-critical new plant that allowed us to look at some of our older, less efficient plants and retire and repower those with cleaner, efficient, modern gas technology, so that has been a great price point for our customers. MERP, which was in Minnesota, you’ll hear more about that again. It got us ahead of the game for the EPA and we did it at prices that I don’t think you could replicate today.
Transmission – our customers want us to build transmission because they see that we do it cheaper and better than anybody else; and again, Teresa Mogensen will give you some more details about that.
People a lot of times talk about renewables being very expensive, and I think that’s quite true in other parts of the country; but if you look at our territories and you look at the slide here and you see what price point we’ve delivered wind at, it really is a reasonable hedge—energy hedge against gas prices. Sometimes it’s in the money, sometimes it’s out of the money; but at prices like that, it’s not breaking anybody’s pocketbook. So we’ve done a good job on bringing on renewables and bringing it on at a price that makes sense.
So that’s providing value, and you can see as a result of that despite what I believe is our head start to modernizing the infrastructure, getting ahead of the EPA rules, we have kept our prices reasonable, and that’s very important – again, customers all want you to do things but nobody really wants to pay for it. But if you can demonstrate that you do it well and your prices are competitive, I think you’re in a pretty good position.
I mentioned safety. We just can’t underscore safety. Obviously in my mind, there’s two risks that I think about a lot – public policy and then safety is right behind that. So we’re all on track to meet the assessment guidelines for the Department of Transportation by the end of next year, and we have been replacing pipe that needs to come out of the ground in a formulaic fashion and we’re getting it done, and we’re getting it done with the support of regulators. We have deferral mechanisms and other supportive regulatory recovery mechanisms that allows us to do just that.
You operate safe, you operate reliable, you operate clean and you provide energy at a reasonable cost, which by the way I basically just said our mission statement. That translates to satisfied customers, and you can see despite a series of rate cases, which we all know nobody likes, our customer satisfaction remains high. And when you have satisfied customers, satisfied stakeholders, you can move onto the regulatory arena and you can start to advance the regulatory compact that you have. We have constructive regulation today. We have moved jurisdictions with historic test years to forward test years. I think we’ve pioneered introducing wider recovery mechanisms into the industry. We’re now talking about moving to multi-year rates and step-ins, et cetera, and there’s a reason for that – because despite all the advancements we have seen in the regulatory compact, we still don’t typically earn our authorized ROE. There’s reasons of that – slower sales growth, the amount of CAPEX we’re doing, and some of the cost pressures we’re all facing. So our goal is to earn our authorized ROE in all our states. I think we’ve made tremendous improvement at SPS. I mean, just a few years ago in this same room, we talked about quite candidly that if the ROEs and the recovery mechanisms at SPS didn’t improve, we’d have to start looking at strategic options. Well, we’ve made our customers allies. As a result, we’ve seen improvement at SPS and I believe we’re going to see more improvement going forward.
So some of the things we’re trying to do to reduce regulatory lag – step increases, you’re seeing that in the current rate cases that we’re filing today, the expansion of rider recovery. We’re going to seek interim rates here in Colorado – that will be the first time we’ve had that, and we’ve talked about and you’ll see us starting to reduce multi-year rate filings. And if we’re successful with that, I think it’s a big opportunity.
This slide shows you that for basically every 25 basis point improvement that we have in ROE, you’re looking at $0.045 a share, so that’s a big opportunity. We typically under-earn by on average about 100 basis points, and so you can see if we can close that gap completely, that would be $0.18. And I guess the other thing I will tell you, in an era where I think you are going to see pressure on authorized returns, even if those authorized returns slip a little bit over time, if we close that gap we can more than make up for it with what we actually earn. So there’s a tremendous opportunity for us and you have our full attention on closing that gap.
All right. So I think we have a constructive regulatory compact. I think we have the stakeholder alignment. Now you can look with confidence on what your organic opportunities to invest are, and we have opportunities to invest that typically aren’t being driven by sales. Sales, for us, will be a little flat like they are throughout the rest of the country, but we have a tremendous amount of work to do on reliability. Again, transmission is going to lead that, but it’s not just transmission; it’s distribution, it’s our gas infrastructure. We know that while we’re ahead of the EPA rules, we have more to do particularly in Texas. We’re starting to do what we need to do in Colorado, and that’s all about putting the necessary pollution control equipment on our coal plants, retiring the inefficient coal plants, repowering them – again, modernizing the infrastructure, making sure that we can continue to deliver value to our customers. I think we have a lot of optionality not only with transmission but potentially investments as we continue to meet the state RPS goals ahead of us.
This is the investment pipeline. I won’t belabor it; Teresa Madden will go into much more detail, but you can see it’s a healthy mix of generation, transmission, distribution, and it’s $13.4 billion. So that’s an increase over where we were this time last year, and it gives us a lot of strong organic rate-based growth.
If you put all that together now – that investment pipeline, constructive regulatory compact, stakeholder alignment – you’re looking at solid returns. We have delivered value just about any way you can cut it. We have delivered value above what our peer group has done, above what the broad EEI index has done on both a five-year, three-year, and one-year basis. In fact, the only place where we’re lagging a little bit is year-to-date this year. So for you in the room, I think that means bye-bye-bye, but I’ll let you make that decision. But we’ve done it. If you look at how we’ve done it historically, it’s been the dividend yield combined with that 5 to 7% EPS growth. If you look at how we’re going to do it in the future, I think we’re in great shape to continue to deliver in ’12 and ’13. We’re in great shape to deliver it in ’14 and beyond. I do think, depending on how macro economic conditions sort out and the other things we all read about and focus on every day, that if you see EPS growth slow a little bit, we’re going to have plenty of opportunity to do more with the dividend. So we have a lot of ways to reward you and give you that 10% total return, and we’ve positioned ourselves for that.
So I think we’re positioned very well and I’m going to turn it over to today’s speakers, but I wanted to give you some insight into how I view the organization. You’re going to hear from Kent Larson first, and as part of my tenure as CEO, I moved electric and gas distribution in addition to generation and transmission under Kent, and the reason why I did that is because I think we need to continue to drive the operational excellence model through standardization, through process improvement, through productivity improvement, and demonstrate to our customers that we do things efficiently and we’re going to continue to do that. In addition, we’re no different from any other utility out there in that we have an aging workforce, half of whom are probably going to retire within the next decade. That’s an opportunity and it’s a challenge, and I think Kent is well positioned to make sure that we turn it into an opportunity.
Within Kent’s group, you’re going to hear from Teresa Mogensen. She runs our transmission group. Transmission is an incredible investment opportunity for us. You’ve heard us talking about it for a number of years. We’re now at the position where we’re going to start harvesting all the good work that we’ve done by actually building the lines, and she has some spiffy, nifty videos to show you, too, which I think you’ll enjoy. And then I’m going to have Dave Sparby, and Dave as you know was CFO. I asked Dave again when I became CEO to lead the operating utility group, and what I wanted the operating utility group to do is get that authorized ROE and really focus on the overall picture with an emphasis on the top line. The top line for us means regulatory, media, public affairs. So you’ll hear from the four opco presidents with Dave; and then finally, as Paul mentioned, Teresa Madden, who just took over for Dave as CFO, will give you the details on our financial strategy, which again is very supportive of that 10% total return.
So with that, I will turn it over to Kent and I think you’ll enjoy his presentation. Thank you.
Thanks, Ben, and good morning. I appreciate the opportunity to be with you here today to talk a little bit about our operations. Today, I’ll talk a little bit about our infrastructure modernization and how it provides flexibility and value for our customers and shareholders, our capital investment successes, our environmental plans for the future, and some key projects.
If you take a look at our business, it presents challenges from time to time. Today I’m going to show you a video of a project that we had in downtown Minneapolis. How many people have been to our headquarters in downtown Minneapolis? How many people know that we’ve got a massive substation right underneath the plaza there that serves about 70% of our downtown area? Probably some of you do, some of you don’t. I want to show you a video now of a project that we had this last summer. It’s a fast speed video. We had to change out one of our four major transformers down in that area and had a lot of challenges associated with it. We actually did very well.
You can see here in the video the substation is on the bottom side. There is light rail right to the north of it there that you can see. We’re actually bringing in a crane right at this time, setting it up, getting it ready to pick it up and move the transformer out of there. We’re moving some concrete slabs on top of the transformer out of the way there so we can actually go in and pick up a 65-ton transformer and move it out of the way. We’re actually getting hold of a new transformer right here and putting it in place. That new transformer, when you get it down to the bottom had two inches of room to spare on each side of it, so it was a very tight fit. We ended up moving this in, getting it set up. Our goal was to be in and out of their in 64 hours so that we could get the light rail system back up and running. We actually made it in 32 hours, so we made it in half the time. You can see, 32 hours later we had the system up and running again. It was a pretty amazing feat.
You know, Ben talks to us about improving productivity all the time and this is a video he likes really, really well. He says we’ve got to do our work like that, and finally one day I went to him and I said, now Ben, you know that’s a high-speed video, that’s not actually how fast we went! He said well, that’s how fast I want you to go all the time. He has some pretty high expectations for us overall.
What I want to talk about here is you look at major decisions you make in a corporation. A lot of those, you don’t know for sure how good they are until later on. If you take a look at the MERP project in particular, that started in 2004. We went in and repowered High Bridge and Riverside in natural gas. We installed state-of-the-art environmental equipment on King and we increased the output by about 500 megawatts. The overall cost was a billion. It was done at an extremely good price point, and I’m going to show you here some of our environmental requirements we have going forward, and this project positioned us extremely well of that going forward at a very good price.
In Colorado, as Ben mentioned, we brought Comanche 3 online last year. It’s 822 megawatts of super-critical coal, very clean coal. It was originally designed for 750 but came in about 10% higher than expected. We also upgraded the environmental controls on Comanche 1 and 2 when we were working on this project, and the overall costs came in extremely well. But the huge thing about this project – it was a major enabler for Clean Air, Clean Jobs. It set us up very well for that, and I’ll talk more about that in a minute.
And then down in Texas, if you think about operations we had a lot of challenges in Texas this last year, probably more than we’ve had almost anywhere for a long time. In February, we had the major cold snap down in Texas where temperatures got down to minus-5 in Amarillo. That’s pretty much unheard of there. It hasn’t been that cold for a long time. SPS was one of the few utilities in the Texas area that didn’t have rolling blackouts during this cold spell, and there’s reasons. We actually kept our plants up and running. One of the advantages of being a major utility that spreads across the country, we know how to operate plants in cold weather. We actually started up our plants before it got too cold so we had them running when it got cold. We went out and saw the cold snap coming, so people went out and bought every heater they could find within a 50 mile radius and strategically located them throughout the plant so we didn’t have freezing in our plant, and on the day when it was the coldest and there wasn’t gas available to run our plants, we actually called up to St. Paul, Minnesota where there’s a liquefied natural gas plant that we own and we shipped gas all the way from St. Paul down to Texas – it took about four hours – so we could keep our plants up and running. The next day we shipped it in from Colorado, and we kept our plants running.
The other thing that was a major contributor to this was about 18 months ago, we made the decision to move Jones 3 up one year. We only had 12 months to get this plant in service. There had been strong load growth in the area and we actually had this plant up and running for the heat of last summer and it was a major contributor to help us serve the load down in that area. It came in at a great price point of about two-thirds the market prices.
Now what I want to do is give you a quick overview of each one of the opcos. This is something new this year. I know environmental rules are absolutely critical to us, and we wanted to help you understand what the impacts are. I’ll explain this first chart to you. If you take a look at the right, all the major plants in the NSP system are shown there. If you go across the top of the screen there, that’s all the environmental rules that could impact us in that, and then we’ve labeled those. The reddish-pink color is issued rules; the blue is proposed; and the purple is anticipated, and then on the far right we show what the costs are to actually meet all of the issues, proposed and anticipated rules, so all three of those. You can see in the NSP system, we only have to spend about $40 million over the next five years to meet that. Had we not done MERP, this picture would be substantially different. If you look between ’17 and ’20, we’ll spend about another 400 million, primarily at Sherco.
Now I’d like to talk about a few of our projects that we have going on in the NSP system. If you look at our nuclear plants, they’re a great asset for our customers. They provide, cheap, reliable, clean energy for our customers overall. At our three units in Minnesota, we’ve actually relicensed all three of those so they all have a 20-year life extension on them. At Monticello, we’re in the process of a power upgrade, about 71 megawatts. We expect that to be completed in 2013. And at Prairie Island, we’ll be changing out the Unit 2 steam generator. As you might remember, we’ve already done the Unit 1 steam generator and we are considering an upgrade also.
One of the events I want to make you aware of in the NSP system is about two weeks ago we had an event at our Sherco 3 plant. We had just completed a major overhaul and an upgrade of about 21 megawatts. We had the plant up running for testing and we did have a failure in the exciter area that also did some damage to the generator and turbine. We expect this unit to be offline for at least six months, possibly longer. At this time, we don’t know what the cost to repair will be but we do expect warranty and insurance to cover all the cost.
Now I’d like to move on to our PSCo system. The chart is set up the same. You can see in the next five years we plan to spend about $850 million for environmental controls. That’s primarily the cost of our Clean Air, Clean Jobs program overall. Clean Air, Clean Jobs basically takes care of almost all of our major environmental requirements for Colorado. Beyond that, we don’t see a lot of other costs.
If you look at Clean Air, Clean Jobs, we’ll be retiring about 900 megawatts of old coal that’s within the city limits of Denver. Comanche 3 was a major enabler for this overall project and was strategic to making this happen. We’ll also build about 570 megawatts of natural gas and will fuel switch about 460 megawatts from coal to natural gas. We’ll install environmental equipment at Pawnee and Hayden. The overall cost, everything included is about $1 billion; but the one thing that’s critical with this, if you look in the upper right-hand corner at the pie chart shown there, we still have a very good fuel mix for our customers for the long run, and that’s really what Comanche 3 did for us.
Now we’ll move on to SPS and the environmental requirements down there. CSAPR is a major driver of our environmental requirements in SPS. At this time, if the CSAPR rules stay in place, we would expect to spend about $470 million in capital. There’s some other dollars that we’ll talk about here in a few minutes. I’ll talk about this in two slides.
One of the projects we’re also working on down at SPS is Jones 4. We plan to bring on another 168 megawatt natural gas combustion turbine, about $130 million for 2013. We still do have a fair amount of load growth down in that area with all the oil in that area overall, and this project will add additional capacity.
Now I’d like to spend just a few minutes talking about our CSAPR project overall. This will have a significant impact on SPS overall. We expect it to have major impacts on the requirements for SO2 and NOx. If you think about the rule that was initially issued in draft form, it didn’t include Texas. It was just a few months ago, as you know, that Texas was added into this. When we look at the rule, we don’t feel Texas should have been included. We do have two legal challenges going on at this time, one with the EPA and the other with the DC Circuit.
We have basically three major issues with the rule overall. One is we don’t think that CSAPR should actually include Texas in the first place. If you look at the air flows and you look at the impact to the rest of the country, it doesn’t have that much of an impact to the rest of the country so we don’t think Texas should have been included. The second one is we feel that the rule—basically the timeline on it was arbitrary. If you think about it being issued just two months ago and started out to January 1 of 2012, that doesn’t give us much time at all to install capital fixes for that. We don’t think the timing is reasonable or adequate, and so we are also challenging that. In addition to that, we don’t believe it’s consistent with the Clean Air rule, either. But we are actually preparing just in case the legal challenges aren’t successful in the end.
Our short-term preparation overall is we actually plan to flip the system so that we’d actually run natural gas as a base load and we’d use our coal more as an intermediate. That will provide less emissions. If that’s what we have to do from a cost point of view, our customers will have to spend next year – about 200 to $250 million – on the cost of fuel. One of the things that we’re looking at hard, though, is how many allowances are available in that area. We’re watching that market very, very close to see if we can buy some allowances at less cost to see if they’re available. We also plan to install some low-NOx burners on our Tolk plant. That will cost us about $15 million but it will reduce our NOx fairly substantially.
In the long run if we’re not successful with our legal challenges, we will be adding environment equipment to both Tolk and Harrington – a DSI at Tolk and Harrington, an SCR, an SMCR at Harrington also for NOx control. If we are successful in our challenges, we back off on this; or if we have the opportunity to buy additional allowances, we back off on this also.
One of the things if you take a look at all of our early action from an environmental point of view and you look at the dollars we’re required to spend in the next five years to meet these requirements, for a company our size, this is really not that much money. We acted early, we ended up getting a lot of the projects done at a low cost point, and now if you look at the next five years we feel it’s fairly manageable.
The last talk I’d like to talk basically just shortly about is our Colorado gas pipeline system integrity. We’re in the process of looking at our high consequence lines. We’re about 85% complete on that – that’s a federal requirement. We expect to complete that in 2012. We’ll also be investing a lot of money in upgrading our transmission system on the gas system in Colorado, about $230 million over the next five years. As Ben mentioned earlier, we’re investing money on the distribution side for bare steel, PVC, and other types of improvements. We plan to invest about $230 million there.
The good thing about our investments in Colorado is we do have a Colorado rider for the next three years to cover many of these investments, and we feel we’ll be in good shape as far as recovery.
So if you take a look at our overall investment plan, our infrastructure modernization has created value for our customers and shareholders. Our proactive actions are reducing the cost of implementation. They also provide flexibility to retire or replace older units, in particular coal units in Colorado. We’re on track to meet our environmental requirements and we’re well positioned for the future for the environmental rules, regulations and compliance.
With that, I’d like to turn it over to Teresa Mogensen to talk about the transmission area.
Good morning everyone. I’m happy to be here again today to update you on how Xcel Energy Transmission is delivering value. We’ve been increasing our ability to effectively execute all the different aspects of our business, engage the many stakeholders who are involved in the transmission world, and do it all in an expert and efficient way.
First, a few facts to set the stage. Although we serve retail customers in eight states, we actually have transmission assets in 10 states or 20% of the country. We operate in both the eastern and western U.S. grids and tie to the third U.S. grid in Texas. We have over 18,000 miles of transmission lines serving 22,000 megawatts of customer load. We operate in three different NERC reliability regions and under two regional transmission organizations, and with the traditional standalone system in Colorado. This diversity of operating factors within one company is pretty unique in the industry and does give us broad experience and industry perspective.
We’re also one of the fastest growing investor-owned transmission systems in the country. Our net book value is at 3.3 billion in 2011 and we expect that to double by the end of 2016.
We offer what we call a best value transmission delivery model. Best value means delivering at a reasonable and lower cost while meeting today’s stakeholder expectations, which are different and higher than those of the past. Our key strategic capabilities supporting this are internal expertise and resources in every aspect of the transmission business, key materials and services alliances to ensure sufficient and timely external resources, and the ability to effectively blend both of these in order to bet manage both cost and risk. At the same time, we’re improving our operations in order to meet evolving new baseline performance expectations for the transmission business in executing the volume of capital and maintenance projects we have to do, in delivering reliable system performance and fully complying with all the standards and requirements that are applicable to us, and in levels that of stakeholder engagement that are expected.
Here’s an illustration of where we’re at compared to our industry peer group of mid to large cap primarily regulated utilities. Analysis of the past six years of FERC Form 1 data shows that Xcel Energy overall is in the top quartile of transmission asset growth for this group. Our northern states Power Minnesota operating company is actually in the top decile of this peer group and in fact ranked second overall with a compound growth rate of 11%.
Here’s another look, both at where we’ve been and where we’re going. As you look from left to right, you can see that we’ve essentially been doubling our investment levels every few years. We’re planning to invest roughly $4 billion over the next five years. Our overall capital projections in the 2011 to 2016 time frame have been stable, our net changing only slightly as some projects move forward or shift out. These projections are for real projects, needed projects to meet a variety of customer, reliability and policy requirements.
Lending credence to the fact that these investment projections are for projects that are in alignment with regulatory and policy direction in our region, you can also see here that a high proportion of our planned transmission investment qualifies for some form of constructive regulatory treatment. Seventy-nine percent of the spend in this period is covered under a variety of rate riders, wholesale formula rates, or in the case of Wisconsin a statutory biannual rate case.
The transmission policy environment which affects what transmission is to be built, who pays for it, and who builds and owns it continues to be quite volatile. The new FERC Order 1000 has increased the volatility by removing the right of first refusal, or ROFR, for large projects that are to be cost allocated to everyone in a given region. We don’t support removal of the ROFR as it attempts to inappropriately split investment from ongoing operations and the associated long-term utility to stakeholder relationships. We think it introduces undue risk without commensurate reward to those paying the bills and holding the bag, our customers. We continue to be willing and able to build, own and operate any transmission needed in our region. FERC Order 1000 should not impact our five-year investment projection as it’s provisions are only applicable to new regional projects.
Many regional planning efforts are also underway right now that will likely result in new projects as they incorporate recent developments in FERC and DOE planning provisions, state and national energy policies, EPA rules and the like. We participate actively in all transmission planning and policy forums to influence outcomes for the benefit of our customers and stakeholders.
One illustration of our delivery capability comes from a Southwest Power Pool evaluation of cost for its priority projects, a group of large projects that provide regional benefit and will be paid for by everyone in the region. In the future, these are the kind of projects that would fall under FERC Order 1000 ROFR provisions and would likely to be subject to some sort of competition. Immediately after approval of this project group that was based on various benefit cost analyses, Southwest Power Pool subsequently requested updates of the project estimates. Our estimate was the only one to go down. The other estimates went up. This prompted an investigation and regulatory concern about how to handle this type of situation in the future. Because of our value proposition capabilities, we know how to deliver projects and we have the stability, the resources and the experience to back up our estimates.
In looking for more cost comparison data to reinforce those SPP findings, we found that there is very little available so we decided to do a study on 345 KV overhead transmission lines. These are kind of the bread and butter of big transmission. Using only publicly available data, we pulled data from various regulatory filings to identify recent projects in our regions of the west, southwest and midwest as well as a couple from New England with similar terrain to the midwest. Out of the 89 345 KV projects we found, we had to exclude 33 of those representing 1,900 miles due to lack of cost information or detail needed to isolate the line costs. The remaining 56 projects, representing about 4,500 miles are shown here. Twenty-eight projects are complete and 28 are in progress. The 10 Xcel Energy projects at the top represent just under 1,200 miles of this total. You can see that we’re currently developing a significant amount of the higher voltage transmission mileage in our regions.
The next thing that we did was to adjust all of those project costs to 2011 dollars by applying the Handy-Whitman Public Utility Cost Construction Index, which accounts for changes in material prices and time value of money. Then, we calculated average dollar per mile cost. The average cost of all 56 projects was $1.77 million per mile. Xcel Energy’s average was $1.4 million per mile. You can see how the SPP, ERCOT, MISO and WECTs averages compare respectively. On average, Xcel Energy is delivering at a lower cost than the overall and the regional averages.
The transmission development process can be an endurance contest. It takes ongoing long-term engagement and commitment as well as expertise and resources to move projects effectively and successfully through this whole process. It’s interesting to note the interplay between dollars and time inherent in transmission investment projections. Generally around 80% of the dollars are spent near the end of the process, along with about 50% of the time. You don’t get to the big spend stages of engineering, procurement and construction until you can successfully navigate through the other 50% of time spent in planning and permitting activities. Our investment projections incorporate projects at all stages of this development continuum.
Underlying our value proposition is our general approach to transmission as illustrated by our transmission principle. Our number one principle is to focus on our responsibility to meet customer needs and to address concerns about affordability. We collaborate and communicate in all activities that are necessary to define the right plan, gain policy and regulatory alignment, and deal with the broad array of stakeholder considerations. We’re looking at our work differently and regularly incorporating new ways of doing things that save time, cost, or better address stakeholder sensitivities. We’re also committed to developing all beneficial transmission for our regions.
Our CapX2020 transmission initiative is a great example of that collaboration principle. We’re demonstrating that we can develop common ground and work effectively with a wide array of different partners for the mutual benefit of all of our customers in the region. Expertise in this kind of collaboration will be critical in future post-FERC Order 1000 large project initiatives.
Now I have a few recent examples of changing the way we do work that you might find interesting. Starting at the upper left, pretty much everyone knows Google now, which is why we find Google Earth to be such a useful tool in working with people on routing and siting activities. The Google Earth application is free, familiar, and gives people the ability to see how a transmission facility might affect their community or property. We can also link this up with other systems to show existing or future facilities in the context of their surroundings. This enables more productive stakeholder participation in the routing and siting processes as it’s much easier for people to engage with us on finding workable solutions if they have a familiar frame of reference. We use this tool in hearings and group meetings as well as in one-on-one situations with landowners or local communities.
Next we have a great example of innovation to address environmental construction constraints. On a new line project, we had a protected wetlands site where we needed to build two towers. We planned to build an ice road – this is Minnesota where you can build ice roads – to allow for minimal impact winter construction when the wetland would be frozen. As it turned out, we were able to build the foundations that way but the ice road wouldn’t bear the weight of the 85-ton crane that we needed to build the towers, so our engineers and construction people had to come up with a different approach. We decided to use heavy lift helicopters.
We start with showing construction of the foundation. Next, we see the heavy lift helicopter lifting the first segment of the tower and carrying it over to place it on the foundation. Linemen then bolt that base to the foundation. The helicopter then brings the next segment, linemen then climb up to receive that top segment, and they bolt everything together. The helicopter and those linemen took less than two hours to construct those two towers in a very environmentally responsible way.
Next, we have a way to make stronger splices to connect segments of line together. These connectors use implosive forces, or what looks like an explosion to you and me, to make a much stronger and more consistent splice than traditional manual compression methods. A sleeve gets placed over the two ends of line to be connected and the implosive material gets put into position. The charge is then detonated and the forces meld the two ends together. Let’s take a look.
A closer look. A little closer. This approach saved labor dollars, can be used in all kinds of weather, and minimizes access and equipment requirements and less associated environmental impacts. It also lets us connect and pull longer reels of already spliced line through stringing blocks, allowing for a more efficient line stringing process.
Speaking of stringing, another way we’re changing the way we do work is to use helicopters in certain cases to minimize the impacts associated with stringing new transmission lines.
So here we see a helicopter lifting off and it’s going to carry a lineman at the end of a 75-foot cable. There he is. So the lineman ultimately will attach (inaudible) attaches line stringing blocks to the arms of the structures. Then the helicopter pulls a rope through the wheels one way and the cable gets attached and pulled back the other way, and then the helicopter sets the lineman back down to do that. We don’t quite have all that, but we do have next what happens when the lines are strung. Helicopter brings the lineman back up, sitting on a nice little perch, and the lineman then installs spacers between the cables and puts one of these in about every 200 feet. He is wearing a seatbelt. We also install bird diverters this same way on our new transmission lines, so this approach addresses equipment access considerations - you saw this was along a freeway – in a more time and cost efficient way and it has less impact on land and environment from the crew and ground equipment movement.
And then briefly back to software – no more video – we also have mobile data tools that we’re indicating at the bottom there that can be used in the field, whether they’re on the ground or via aerial inspection, that are linked to our GAS and assessment management systems. This helps us streamline our operations in collecting and integrating updated asset information and also in tracking work orders in progress. So all of these examples as well as many others like them show how we’re making great progress in maximizing the productivity and effectiveness of our work.
So we’re putting these techniques to work in our major project portfolios as well as in the balance of our projects. Here’s a little update on the status of our four CapX2020 projects in the north. They are all now in the final stages of permitting or actively under construction, and the first segment will actually be in service in a few days. The new MISO multi-value projects that we are involved in are shown in the pre-permitting stage pending final MISO Board approval later this month. Our SB100 portfolio in Colorado continue to progress. The first elements are now in service - the Missile Site 230 Kb switching station and the midway to Waterton 345 Kb line, our Pawnee to Smoky Hill 345 Kb project is under construction, and other projects are in permitting or pre-permitting stages. This portfolio is currently undergoing some revision in conjunction with our resource plan evolution and associated circumstances in the western region.
Our Power for the Plains brand in the southwest covers all projects that received a Notice to Construct from the Southwest Power Pool, but we’re highlighting only the larger projects here and in the appendix table. The first major project from this group in the northwest panhandle is now in service. Others that are part of the Texas north load-serving group are well under construction, and the two big Texas to Oklahoma 345 Kb projects are in the permitting stages.
We have just highlighted our major project portfolios, but we have many other projects underway as well. The major project portfolios I just discussed make up about 43% of the five-year investment plan with many other projects making up the balance. Some of these other projects will likely migrate to the major portfolios as they develop.
I want to leave you with a recent example that illustrates our value proposition capabilities. In July, we had a major storm in the Buffalo Ridge wind production area of Minnesota with straight-line winds and tornadoes that destroyed a significant amount of electric infrastructure. The wind turbines in the top picture took a beating, as you can see, and those little stubs that you see in the bottom picture used to be transmission and wind collector lines on either side of the road. This is what it looked like over the entire area. Because we have internal resources and expertise in all transmission functions, we had people out there immediately assessing the damage and developing initial restoration plans. We marshaled our external resources and materials that we already had on hand due to our active construction program and supplemented those over time with our alliances and immediately begin to engineer and rebuild the area. We actually got 110 miles of line completely rebuilt and back in service in 90 days.
So why Xcel Energy for transmission? Because we’re transmission experts. We’re committed to our customers and to our regions for the long term. We collaborate with everyone to help determine the best projects and the best locations to meet multiple needs most efficiently. We can deliver at a reasonable cost and meet today’s expectations for stakeholder engagement and alignment. We have internal and external resources that we blend for highly effective risk and cost management, and we work hard to improve our operations. We’re the kind of transmission utility that can and will deliver the best value and you can count on us to get it done.
Thank you. Now I’ll turn it over to Dave Sparby.
Thanks, Teresa. Joining me for this panel discussion this morning will be David Eves, President and CEO of PSCo; Riley Hill, President and CEO of SPS; Judy Poferl, President and CEO of NSP Minnesota, and Mark Stoering, incoming President and CEO of Northern States Power Wisconsin. Mike Swenson, who has been here with us in the past, will retire at the end the year and we wish him well.
Well, you heard it earlier – I only have two responsibilities: grow the top line and improved our earned return, and it’s good to be focused. Now to do that, we’re pursuing several measures: multi-year plans in Colorado and Minnesota, interim rates in Colorado and South Dakota, improved regulatory recovery and riders at SPS, as well as step increases to traditional rate cases across all jurisdictions. Now, we’re also focused on remaining aligned with our stakeholders across the service territory. We’re committed to communicating the value of clean, safe, reliable energy not only today but into the future.
You know, our recently filed resource plans highlight the success of our DSM programs. They show we’re ahead of our renewable portfolio standard targets, and they also tell us that we’ve added wind at a great price point for our customers. Our plans also show that although sales are slow, we have significant capital investment opportunities ahead of us like Clean Air, Clean Jobs and the life extension of our nuclear plants, which will continue to drive rate base. Now in this morning’s panel discussion, we’ll talk about our efforts to reduce regulatory lag, the economy across the service territory, our resource plans, and key priorities in 2012 for Xcel.
Judy, let’s start with you. What actions are you taking across NSP Minnesota to improve our earned returns?
Thanks Dave, and good morning everyone. At NSP Minnesota, we’re working to build on that framework we already have in place of rate cases and rate riders. As all of you know, that’s served us very well and has supported significant capital investment on our system over the recent years, so we’re going to build on that to work to close our earnings gaps. To that end, as you know, we have three rates cases pending on our system. We’ve resolved or filed settlements in two of them, and I draw your attention to one aspect of the settlement that I think is really moving us in the right direction, and that is the step increases for 2012, which is a year beyond our test year. And the step increases would allow us to recover the full year’s cost of our investment thus far in the Monticello nuclear project, and to my knowledge it’s the first time that a step increase for capital would be allowed for recovery outside of a projected test year in both Minnesota and North Dakota. So we certainly appreciate the work that we’ve done with stakeholders to get to this point and look forward to getting that in front of the commission for a resolution, but overall we think that’s a step in the right direction.
I’d just note that we have other features of those settlements that I think highlight the type of regulatory environment that we operate in. It has features such as the ability to true-up to actual sales in North Dakota or to allow recovery of extraordinary expenses we incurred during the Minot flooding. It allows for the possibility of deferral of our property taxes in Minnesota, which we expect in 2012 to be higher than in ’11, and it has allowed recovery of our litigation costs in our lengthy litigation with the DOE over nuclear waste storage. So the features of these settlements I think really highlight the type of constructive regulatory environment that we have. It shows that when we have issues and we share those facts to work with stakeholders that we can get things done.
So looking ahead, we’re going to build on where we’re at here towards a multi-year plan which we would expect to file in our jurisdictions in 2013 with a 2013 rate case. Building on the step increases and the legislation that we got adopted in Minnesota here this past session that clarified the Minnesota commission’s ability to approve a multi-year plan and set some base parameters for that plan, we’re going to work with stakeholders to get to consensus and try to get that done.
So that’s really how we see ourselves moving forward. Certainly we’ll face different issues in each of the jurisdictions we serve – for example, in South Dakota we have a historic test year, so we’ll be working from a somewhat different place – but we think if we do that model that Ben talked about of engaging our stakeholders, working to align interests, bringing folks together around the facts of our plan, we’ll be able to make progress. So in Minnesota, what we’ll be doing is taking what we have and working to make it even better.
David Eves at PSCo?
Okay, thanks Dave. Good morning. In Colorado, we’re working with our stakeholders in the different jurisdictions, and they are somewhat discrete – you know, large shippers and large customers on the gas side of the business aren’t the same, necessarily, as the electric customers. But we’re continuing—we have been and we’ll continue to work with them to improve the regulatory treatment and the cost recovery. A big part of that, obviously, is reducing the regulatory lag moving to future test years interim rates. That’s been a challenge in Colorado. We’ve filed a couple of future test years. We haven’t been totally successful with those, but in 2010 legislation that created Clean Air, Clean Jobs enabled both interim rates as well as future test years, not just for electric but also for gas and steam rates for investor-owned utilities.
So the electric case that we just filed last week is the first time under this new statute that we filed for the interim rates, and I assume that you’ve all had a chance to see the primary points. I won’t try to go through the electric filing, but I do think we have a solid case for the increases, both the 142 million as well as the 100 million interim rate increase. At the same time and actually ahead of that filing, we’ve been working with parties in discussions about the potential for a multiple year plan. Given the regulatory schedule in Colorado, there were major hearings on Black Hills electric rate case that took place. We were in the final stages of preparing the 2012 future test year that we just filed last week, so there was a little bit of a break; but we’ve resumed discussions with the parties on a multiple year plan. Our goal would be to have the plan address probably three years, provide some protection for customers through an earnings test. But we’re just at the stages now where it’s a little bit difficult to say exactly how that will go and provide any more detail about the mechanics; but I can say that there are constructive discussions taking place and we’re really listening to them, trying to make sure that we incorporate things that they are interested in accomplishing here. So I think there is some good potential for that.
On the gas side of our business, we had primarily settled – there were a couple of minor issues that went to hearing, but we had a settled rate case. Rates went into effect in September. The increase was not huge – it was, I think, a 12.7 million increase that went into effect in early September. But importantly, we implemented a cost adjustment mechanism for pipeline safety and integrity work that recovers both capital investment and expenses associated with both transmission and distribution integrity. That’s clearly the portion of our business where the assessments that we’re doing, the smart pigs, the inline inspection work and the other assessments result in findings that are sometimes leading to major renewals or replacement of pipelines, or other major capital work, and it’s a lot of our expense. So a big part of the cost of our business that’s been changing is largely captured in the PSIA adjustment.
The final jurisdiction is really the production and transmission components of the FERC jurisdiction. That wholesale part of our business has declined a little bit as two of our big customers became part owners of Comanche 3, and now at the end of 2011 Black Hills will—our contract with them terminates. But it’s still an important part. We’ve got to address all the pieces of business. And the primary thing we’re doing in the FERC arena is moving the formula rates toward forecast formula rates with true-ups. And we’re close to having a settlement in our production case and we plan to file the smaller transmission forward-looking formula with a true-up. We plan to file that in either December or January, so I think we have plans in place across all of the jurisdictions or new mechanisms in place that we’re using now.
David, the commission took up the electric rate case yesterday. Are there any updates from that meeting?
Yes, what they took up was the procedures around the interim request, and basically they set a date of December 22 for parties to file comments on that. The Company and any parties that have cross-replies to that would to file their position on January 5, and then the commission intends to take the matter up and develop a ruling on it, I think, January 21.
Okay, thank you. Riley Hill, could you speak to improvements you’re making at SPS?
Sure, David. As you heard Ben mention, at SPS we had been struggling with recovery but in the last three years, we have improved recovery mechanisms as well as ROE and expect that to continue as we go forward. We’re doing that through stakeholder outreach and alignment, as Ben mentioned, as well as delivering on the commitments that we’re making. In rate cases, we’ve made commitments for service levels and customers satisfaction, and we’re delivering. You saw the numbers – we’re doing very well across Xcel and SPS specifically.
Recently in recent years, we’ve seen some real stakeholder support for recovery mechanisms that have been beneficial. As you may recall in the 2010 rate case in Texas, we were successful in settling for a two-year rate plan which will have about $13.1 million worth of rates going into effect in January of 2012 as part of that settlement, and that was unique for Texas. We were the first company that had been successful in doing that there, and as you recall, we have worked with our stakeholders and gotten strong stakeholder support for a transmission cost recovery factor in Texas. Most recently in the legislature, we were successful in getting a distribution cost recovery factor as well as energy efficiency cost recovery factors, and in New Mexico of course we have a future test year available to us there which we used in this last rate case.
As you recall on the slide Ben showed on comparison of rates across not only Xcel but the United States, you saw that Amarillo was on the very low end of that chart. We have either the lowest or second-lowest rates in the state of Texas as well as New Mexico, so I believe we’ve got room to actually grow our rates and we’re not seeing a lot of rate fatigue from our regulators, and as Ben mentioned and I think I support as well, I think we’ll be able to continue to improve our regulatory picture there.
Big issue, I guess, for us you saw and heard Kent talk about is CSAPR. So we’ll be working to recover the costs associated with that. We recently filed last week for new fuel factors in Texas, as you heard Kent mention, about 200 to $250 million worth of increased fuel costs as well as if the allowance market takes shape, we do have the mechanisms to recover those costs – we’ll run those through the fuel factor. So we’re in a good spot there.
Of course, on the FERC side of our business, we have formula rates so that any CSAPR costs will be projected and estimated and intrude up in those as well. New Mexico, we did recently announce a settlement for a rate case there for rates to go into effect hopefully in January of about $13.5 million that we left the door open there for the ability for some either rider or deferrals for CSAPR-related costs, as well as possibly some interim rates for the Jones 4 unit that you saw. So I think, again, all of this is predicated on whether or not our motion for stay is granted. If it’s not, I do believe we’ve got good mechanisms in place. We will file in January in New Mexico as well as Texas for deferral of all associated O&M and capital-related costs with CSAPR, so again, I think we’re in a good spot there.
And then lastly, in the third quarter of this year we will be filing another Texas rate case and building upon the success of the last one with a two-year step increase working with stakeholders. And that’s our plan, David.
Okay, thanks. Mark, can you speak to Wisconsin?
Sure, Dave. Thanks. Good morning. In Wisconsin, we’re nearing completion of our 2012 electric and gas retail rate case that we filed earlier this year in June. Our adjusted request is at $25 million. The staff recommendation is at 15. There’s really three primary categories in terms of what the difference is – it’s in labor compensation, it’s in a request we made for pre-collection of manufactured gas plant remediation costs, and it’s on ROE.
Regarding ROE, our request was for 10-75; the staff recommendation is at 10-3. For reference, we’re currently authorized to earn 10-4 in Wisconsin. We’re basically coming down the stretch on this case. We expect a decision later this month and new rates to be effective in January. 2012 is a reopener year for us. We’ll make a decision depending on how we come out of this rate case as to whether we file a limited reopener or a full rate case.
Just a couple of comments regarding the regulatory environment in Wisconsin. I think we have a very constructive working relationship with our staff and commission. I’d like to think that our state-leading position in many key categories has lent to that relationship. We have either a top rating or very near the top rating in terms of low rates. System reliability, customer satisfaction, renewable energy – I think all of that assists in the relationship, but it’s a good regulatory construct. The commission requires biannual rate cases with forward test years. We have a new fuel plan that’s in place this year that limits our fuel cost recovery risk to 2% of the projected amount of fuel costs for the year, and then as I mentioned earlier, we have the opportunity to file a limited reopener in the off years.
Mark, you had a new governor come into place. You’ve got two new commissioners. Are you seeing any policy changes at the commission level in Wisconsin?
Yeah, that’s right. Two of our three commissioners—appointed commissioners are new; but no, we don’t anticipate any significant policy changes at the Wisconsin commission.
Okay. There’s been several questions this week about the economy of our service territories and the impact on sales. David Eves, starting with you, could you talk about the health of your local economies in Colorado?
Sure, Dave. In Colorado, the economic outlook is improving. Several important indicators like gross product, employment growth improved going forward compared to where we’ve been and they’re better than the U.S. as a whole. There are some specific industrial large customer developments that are pretty positive. Freeport McMoRan, the company that owns Climax and Henderson mine, is reopening—plans to reopen in 2012 and go to full operation in ’13 – the Climax mine, one of our longstanding largest customers that hasn’t operated in the last 15 years. GE bought PrimeStar Solar and announced late this summer that they’re going to open a large manufacturing facility in Aurora, and Colorado attracted—the Denver metro area attracted Arrow Electronics, which is a Fortune 200 headquarters, and we only had nine in the metro area, so that’ a big improvement.
Overall, electric growth, electric sales growth just under a percent; gas under half a percent. Of course, C&I is stronger than residential. One thing as you look at those numbers, though, it’s important to keep in mind that solar rewards and our solar program, as well as especially our DSM programs, probably take the organic growth that we would have and cut that—they halve that growth. They significantly impact it, and we do get the cost recovery and incentive treatment for the DSM that helps offset that.
Similarly, I think that we’re seeing the same thing. Texas and New Mexico’s economies both are performing a little bit better than the U.S. average, and energy—the petrochemical area business sector in Texas and New Mexico is very strong and has been strong, and we’re continuing to see growth in that area. We’re also seeing some growth in New Mexico in the agricultural, mostly in the potash mining segment sectors of the business, and we’re continuing to see a steady stream of requests for line extensions to serve the load both in the petrochemical as well as the agricultural areas. So our projections out through 2012, we’ll see just under 2%, so from the Xcel family of opcos, SPS is doing very well and mainly driven by the petrochemical oil production.
Mark, in Wisconsin?
Sure. We expect some minor sales growth on both the electric and gas side, but the definition of minor here is somewhere between probably half a percent to 1%. We do expect it to be largely in the large C&I customer segment. One of the more interesting areas in western Wisconsin where we’re seeing some economic vitality is in the mining sector. It’s sand mining today but potentially long term could be even copper or iron ore mining. Interestingly, as it turns out, western Wisconsin has some of North America’s best frac sand, and it’s generally quartz in nature and composition and the grains are round, and those are good qualities. We saw in 2009 in our service territory three sand mining operations. This year, we’ll see somewhere near 11, and by the end of ’12 we expect to have 18 sand mining operations in our service territory in western Wisconsin with the possibility for more. So that’s been kind of an interesting opportunity for us in terms of economic growth and trying to support that unique growth.
And Judy, across Minnesota, North and South Dakota?
Sure. NSP Minnesota has a very diversified customer base, probably even more so than some of the other Xcel companies here, and it’s actually performed better than national average as we’ve gone through the recession. We are home to 20 Fortune 500 companies. The Dakotas certainly saw, I think, less impact from the recession than other parts of the nation, and many of our largest customers have actually returned to their pre-recession levels at our largest customers. So overall, we think we’re faring well.
Looking at 2012, we are projecting it to be much like 2011. We will see some loss from a couple of large customers which is muting the other growth we’re seeing from data center expansions, and we also have some of the mining operations that Mark mentioned so it’s muting it somewhat. And it also reflects our demand-side management success, as David had mentioned. In Minnesota, we have a state goal to achieve 1.5% of our retail energy savings through our DSM efforts, and we are on track this year to achieve it, which is a substantial accomplishment. We do, in our efforts to get the rules right, have the ability to both recover our investments there and achieve incentives, and this year we’re looking at approaching up to 50 million in incentives. So overall, we think even though the load growth is tempered here this year, our overall framework serves us well.
Okay. Now Judy and David, you’ve both recently made resource plan filings and you’ve made some transmission filings. Can you speak to the future investment that you expect in your service territory? And Judy, let’s start with you this time.
Okay, sure Dave. With respect to our research plan, we are seeing continued slow growth but slower than we had originally expected, and so today we will be filing an update to that plan that does propose some changes, one being that the Monticello outage will occur in ’13, which I think everyone’s already aware of from our rate case. It does seek to delay the Black Dog filing that we have just because the load growth is not justifying it on the schedule that we currently have, so we’re looking to put that on hold for a while. And then we are asking that we have regulators take another look at our Prairie Island upgrades. Certainly from our experience from Monticello between the licensing and some additional requirements and some delays, we think it’s very important that our commissions get all that information and take another look. This is all really a part of is we’ve always talked about keeping our stakeholders aligned with our plans. As we do that – bring them information – we think that it certainly helps minimize our risk of recovery because we’ve brought our policymakers along with us all the way. So those are some of the things going on on the resource planning side.
On the renewable side, we’ve been successful in bringing wind in on our system. We just brought in another project done through a PPA. We filed a report that showed that the wind on our system has actually helped lower costs to customers, which we think has been really important to communicating to folks the value of what we’ve been doing that Ben had talked about earlier, and so keeping folks, again, in line with our plan is always really important to us.
In addition to those kinds of resource acquisition or resource growth, we have a very healthy and solid base of transmission investment, as Teresa Mogensen talked about, distribution renewals, some environmental requirements; so overall, we have a healthy investment pipeline and are expecting to spend somewhat over a billion dollars a year for the next several years.
Judy, you also sit on an electric vehicle policy group. Are you seeing that impact your resource plans at NSP Minnesota?
Not really at this time, especially not so much on the generation side. Certainly in Minnesota, folks are particularly excited about electric vehicles and want to do what they can to encourage them, and we’ve been supporting that through both putting some vehicles out on the street through local government, helping to support that, and some charging stations just to increase the visibility. But overall, even if penetrations were coming on electric vehicles, it’s not going to have that dramatic of an impact on us and shouldn’t affect our generation; but it certainly will affect distribution. And so in our efforts to continue to work with stakeholders to get the rules right, we’re participating in some policy groups that look at what would we do with pricing to ensure that charging happens off-peak and isn’t contributing to the need for new generation; what can we do with distribution planning, which isn’t something that folks have necessarily spent a lot of time with, to ensure that our distribution system can accommodate these vehicles on our system. So overall, we think it’s really important that we get out there up front and get the rules right to encourage this on our system in as constructive and healthy as way as we can.
Good. David, can you update us on PSCo’s plans?
Sure, Dave. I used to be in resource planning, so I was a little disappointed that the resource plan that we just filed at the end of October didn’t get all the fanfare and attention that a rate case does, but I guess it’s because the implications are a little bit further down the road. It was an important plan, and I’m actually really excited about it. We’re talking a lot with our large customers in particular about the implications of the plan. One is that there’s not a lot of load growth. There’s not a lot of resource need in the near future. As we look at the acquisition period, we don’t have any resource needs until 2007, and through the total period that we’d acquire resources, it’s like 300 megawatts by 2018, so not real significant.
The good news, I think, is that we think we’ll be able to meet a lot of that need with supply from regional generation and do it in a really low cost manner to help keep prices low for our customers.
A couple of other implications to the plan and things that are highlighted – coming out of Clean Air, Clean Jobs at the very end of the 2010 regulatory process, we had some debate amongst the parties and the commission had to weigh in and make the decision about converting Cherokee 4 350 megawatt coal unit as opposed to putting new controls on it to convert it to gas. At that point, we thought it would have to be a must-run, heavily operated unit because of voltage issues in the metro area. We did the additional transmission studies and now know that that’s not the case, so we can put a few auto transformers in, less than $10 million of investment, and actually be able to be a little more flexible about how we meet our needs. So it took the requirement for another gas turbine or another generation shaft at Cherokee, or running all that gas on the old 10,000 heat rate steam plant and kind of changed that whole picture. So I think it’s a better prospect for the independent power producers to supply to us to take advantage of regional supply and keep costs a little bit lower, so the combination of low gas prices and that change actually made Clean Air, Clean Jobs look better than it did at the end of the commission approval at the end of 2010, especially from a standpoint of customer costs.
Another important part of the resource plan is where we are with renewables, and with the recent approval by the commission of the 200 megawatt Limon II wind project, we now have enough wind and utility-scale solar to satisfy the requirement out through almost the end of the next decade, way beyond 2020. So we’re in good shape there. It gives us the flexibility to be opportunistic. We’ve shown the ability to do that in the past, and we want to acquire more renewables when we can get them at the right price and not do it under a prescribed schedule, so hopefully the commission will give us some flexibility in that regard.
One other part of the plan was it led to us concurrently indicating to the commission that we need to do reconsider the San Luis Valley transmission line. Our half of that line with Tri-State – roughly half – would be about 100 million, and frankly given where we’re at with the solar RES requirements, the cost reductions we with PV versus central solar thermal, what we hear from our stakeholders, this would have been up to a $15 million impact to our electric customers in terms of the cost to build our part of that line. So taking all that into account signaled a willingness to look in a different direction there.
In terms of investment drivers, Dave, the load growth and new generation is not the significant thing driving investment in the Colorado company. It’s really Clean Air, Clean Jobs; it’s the environmental work, it’s the transmission projects, Senate Bill 100, it’s the major gas investments, the renewals, and the work that’s associated with the gas integrity, both transmission and the distribution replacement of the pipe types that we want to get out of the ground, and it’s distribution electric infrastructure. So our investments are really not tied to the economic growth in this service territory.
Okay, thanks. Riley, we know Texas doesn’t require an IRP but New Mexico does. What can you tell us about SPS?
Sure, yes. Even though we don’t obviously have to file a plan in Texas, we do resource planning; and as you heard Kent talk about the Jones 4 addition that we’ll be adding in the 2013 time frame, we have filed for CCNs in both Texas and New Mexico for that unit, getting favorable response back. In fact, we’re approved in Texas and working through the New Mexico process. We will—as we go forward, our retail load growth that we’re seeing, and we’re seeing good retail load growth as I mentioned with the petrochemical as well as the agricultural, will mostly be offset by the roll-off of the wholesale contracts that we have through 2020, so after Jones 4 I don’t really see us having a huge resource need at SPS if the load growth continues at the current rate it is.
So with regard to other investments, you saw Teresa talk about Power for the Plains at SPS. We are significantly investing in new transmission, about $1 billion over the next five years, all with good recovery as I mentioned. We have the transmission cost recovery factor in Texas and the FERC jurisdiction for transmission there, so that’s pretty much where we’ll be.
Okay. Mark, anything to add from Wisconsin?
Yeah, I just might add two brief points to the resource planning discussion. Of course, Judy and I at NSP Minnesota and NSP Wisconsin plan, build and operate an integrated system—generation production system. We have an interchange agreement that’s governed by FERC, and so everything that she said obviously impacts us and is very important to us. And then secondly, you’ve heard a lot about transmission investment today and that’s probably—well, it is our biggest category of investment in Wisconsin. We have a $920 million projected capital budget over the next five years. About half of that will be dedicated to transmission and substation investment. We could easily double our rate base, transmission rate base investment in Wisconsin.
Okay. Now briefly before we take some questions from the audience, could you tell us what your priorities are for 2012? And we’ll start with you, Dave.
Well, obviously the rate case we just filed, the electric case, the multiple-year plan, given the major construction projects, Clean Air, Clean Jobs, the gas infrastructure, transmission – really executing on all those and being transparent. We’ve filed a lot of CPC and we need to update everyone about—the communities and customers about those projects, and then probably finally Boulder, even though it doesn’t have a material impact—we don’t expect it to have a material impact on us financially, it’s going to take a long time. It is a high profile issue and we want to make sure that we work through that in a way that we protect our other customers’ and our stockholders’ interest in the outcome of that.
Assuming that CSAPR rule goes into effect obviously we will be focused a lot on that. First, from a compliance perspective, ensuring that we are meeting the compliance caps on emissions, and doing that reliably there will be some challenges, I think, in doing a re-dispatch of our system; but I think we’ve done a lot of analysis, a lot of work. I think we’ll be in good shape there. And then the cost recovery associated with any CSAPR-related costs, we will be working with our stakeholders. We’ve spent a good deal of time already doing education and outreach with stakeholders – the commissions, the staffs, and our large customers – and they’ve been very favorable and supportive of us, but we will continue to communicate and engage with them as we go through 2012.
Okay. Mark, priorities in Wisconsin?
Yeah, first it’s complete the current rate case, and secondly, quickly look to next year to decide if that’s a limited reopener for us or a full rate case. Second, it’s to continue to support the regional economic development, continue to help our customers realize we can bring the most cost-effective, safest, most reliable energy to meet their projects. I talked about the mining sector and our focus there. And then lastly, I think a priority is just to continue to advance our progress and leadership on remediating some of the manufactured gas plants in Wisconsin. We’ve made good progress there. We’ve got more work to do, but keeping our regulators informed and bringing them along on that so we can continue with a good, fair, equitable cost recovery on those initiatives is important for us.
And Judy, Minnesota?
For NSP Minnesota, it will be our priority to work to develop the multi-year plan and aligning stakeholders around it, all with the eye towards the 2013 rate case. As part of that, we’ll be working in particular on South Dakota and just seeing what we can do there. That is our one jurisdiction with an historic test year and as our investments have grown, that leg has become more noticeable, more significant, and we’ll be working to address that. And then finally, we’re going to have to continue to work on and continue to deliver our excellent execution of projects and our business plans, continue to provide great value and service to our customers because those are always key to having a good spot to go to your regulators with in the regulatory arena. So good execution overall will be our focus.
Okay, well we’ve got time for a couple questions for this panel. There will be an opportunity for questions to hit operations and finance later, but are there any questions for this panel dealing with regulation? At the back?
Just a question on the Colorado rate case, or two questions on it. First, can you just remind us if there’s anything in the law on the interim rates that kind of tells the commission how an interim rate case should be addressed, since it’s the first one? And then just secondly, one of the things that was mentioned in the case, I think was a big increase for a contract that ends with Black Hills. Can you just go through what the story is with that?
Sure. Thank you, Steve. I’ll take the last question first. About a third of the increase proposed is associated with reallocation, a change in the jurisdictional allocation between wholesale and retail associated with a 300 megawatt power sale to Black Hills that expires at the end of 2011. In two resource plans, the last two plans, we’ve identified and quantified that it would in our customers’—all of our remaining customers’ best long-term interest not to continue that sale, and that’s been fully vetted through the process. So there is a near-term impact – I think it’s 52.8 million.
With regard to the standard, I don’t remember the exact language but basically the commission, I believe, will have to look at the ability of the company to earn its authorized return and the degree of impact on the—it’s whether the increase is meaningful and whether granting or not granting interim rates would impair our ability to earn our return. So I think we’ve addressed both of those in the interim request.
Okay. Other questions?
Hi. Two-part question. Ben had made the point that the current ROEs that utilities are earning are about 100 basis points below authorized. I was just wondering, number one, in the best case scenario, assuming things work out as planned, would you expect that you really should be earning exactly the authorized ROEs or there will always be some lag in the system? And secondly, related to that, are the regulatory tools now in place that will allow you to earn those authorized ROEs, or are there other changes still to be done or something that you would pursue in your various jurisdictions that would cause that lag to ultimately go away?
Judy, do you want to start?
Sure. With respect to would we—with all our plans, would we exactly earn our ROEs? I think there will always be some amount of difference if you’re looking at it on a weather normalized basis, just because there will be probably some things that aren’t directly recoverable or some form of lag. But I think certainly we can cut that gap significantly from where we are, and that’s what our efforts would be.
To your question about would—what else is needed? For us, what’s really needed is the work we’re going to try to accomplish with the multi-year plan, which is because at the level of capital spend we have year-over-year, one single test year just doesn’t catch you up. So how can we actually set rates on a three-year trajectory looking at what our anticipated costs are over that time and actually set rates to get us there without that lag so we don’t have that every-other-year kind of cycle where you’re up close to your ROE in a test year where you have a rate case, and then the next year you have some lag. So those will be the things we’ll address.
The one other thing that we would need to address for Minnesota is the historic test year lag in South Dakota, and that’s one of the things that’s on our plate to tackle. And even without maybe having a full move to a projected test year, you could still do step increases even on a backwards looking basis that would help cut the lag there, so there’s some tools, I think, that we can try to employ to help minimize lag in our jurisdiction, and that’s our task.
And to be sure, just to add to that, it’s things like some charitable donations, lobbying expenses, some dues and donations are in some states by statute and are recoverable, so there will always be a slice. But a multi-year plan goes a long way to recover that percentage of return that we’re not getting today.
Leslie Rich – JP Morgan
Leslie Rich, JP Morgan. So I know you showed a slide showing what the absolute level of your retail rates are, but as you layer in all the spending, often customers don’t care about how their prices are relative to other states; they care about the percentage increase. So at SPS in particular where you have CSAPR spending plus passing through potentially 220 million or so of fuel uplift, what kind of rate impact are the customers going to see, and is there likely to be a backlash? And also in the other jurisdictions where there’s big, heavy CAPEX programs for 2013?
Sure. I think we were very proactive in getting out in front of this with all of our stakeholders, from the legislators, our delegation in our jurisdictions, as well as our city councils, mayors, and a lot of articles, a lot of op eds in the local papers talking about CSAPR and its impact. And we got a very favorable op ed in Amarillo the other day with regard to CSAPR, and I think people understand it, in fact are rallying around the fact that the EPA is really mandating those requirements on us. So, so far so good. I did mention earlier we have a $13.1 million step increase in January, so that combined with a fuel increase, we could see some pushback; but I think being out in front of and working with them has been very helpful.
Of course, opinion on the rate class, the increase associated with CSAPR is all over the place, anywhere from 7% up to around 15 or 16% from a fuel perspective, and so we’ll continue to work with them. We’re doing a lot of outreach and hopefully, again, our motion for stay will be granted and we won’t have to go through this. But in looking at the longer term rate impacts, we’re working with our major stakeholders to come up with a long-term solution on what controls we will put on the plant and help minimize those costs. And if there’s any—if CSAPR is not completely stayed, it could be delayed, which would allow us to spread those costs over a longer period of time and not have such a rate impact in the next couple of years.
Is there one final question? Go ahead.
Greg Reiss – Catapult Capital
Hi there – Greg Reiss of Catapult Capital. Just a real quick question on the Clean Air, Clean Jobs. On the slide over here, it says it’s a possibility to have a rider recovery for that. Is there some sort of filing that has to be made in order to ensure that rider recovery, or is that pretty much guaranteed to go through a rider at this point?
Yes, we do have the ability to implement a rider. There’s some work that we need to go through, and in fact if we end up with a—it’s likely that a multi-year plan, if we’re successful, would avoid the need for that during this near-term period; but absent that fruitful result from the MYP work, we would be working in 2012 to set the groundwork for a rider to begin to get the quid because we’re investing now in emission control projects at Pawnee. We’ll start Hayden, the two on one.
Greg Reiss – Catapult Capital
One more question – go ahead.
Andy Levi – Caris & Company
Hi, it’s Andy Levi from Caris & Company. Just on the allowances, obviously in Texas you said you’d have to probably be buying allowances if nothing really changes. But also in the other jurisdictions, are there going to be any allowances that are going to need to be bought, and if so and including Texas – I think you mentioned it – is it an automatic pass-through on the fuel clause, or is there a little bit more to it than that, and then whether Texas or your other states?
In Texas in the last rate case, we did reach agreement with stakeholders to be able to pass allowances through fuel. Through New Mexico, it’s not automatic. We will have to work with the commission to be able to pass those either through fuel or a rider.
Okay, well thank you very much. Now, I’d like to introduce Teresa Madden.
I always have to check – can you all hear me? I always have to use my outside voice, it seems like even with a microphone. So anyway, this morning you’ve heard from our leadership team in terms of what we believe the successful execution of our strategy, and really the importance has been introduced – stakeholder alignment, having a very solid pipeline of investment needs, as well as constructive regulatory alignment. And today, I’m just going to talk about how we plan to finance our strategy as we go forward, as well as how we plan to continue to deliver our total return of 10%.
So with that, since 2005 our strategy has been the same, but it’s basically we invest in our regulated utilities, get timely recovery of those investments, all while maintaining solid credit quality. And this has really proved to deliver a total, very positive 10% return to our shareholders. We do think this is a very effective strategy even in good times as well as our economic slowdown of times, and as you’ve heard from all our presenters, we do have a very strong, robust pipeline of investments. But hopefully, you’ve gained an appreciation that they really are prudent investments and they’re based on reliability needs as well as environmental needs. Again, we believe this really positions us to provide our total return now and in the future of 10%.
So going to our capital investment, I guess we’ll add up all the numbers because you’ve heard a lot about them. As Ben had mentioned, for the next five years we’re anticipating spending $13.4 billion, and I think it’s important to look at the timing of the spend, our peaks—really our peak is in 2013, but really the concentration is in the first two years and then we begin to taper off in terms of the last three years of our spend.
From a rate-based growth perspective, what does this mean to us? We’re expecting rate base to grow about 7% over the next five years, but from this chart I think the most important takeaway – maybe most important, but a very important takeaway – as we get to the latter part of the spend, actually the slope of our curve starts to come down in terms of ’15 and ’16, and of course that’s because our spend is declining in those periods. In terms of with that level of rate base growth, we in turn expect to have an increase of our cash generated from operations, and in fact in 2016 we’re expecting our cash funds from operations to be at about $3 billion on an annual basis, so you can see that’s definitely ticking up.
Of course, with this level of spend we will be in the external markets in terms of financing our capital. We won’t have enough internal generation, so therefore we’re very focused to continue on—continue with maintaining a very strong balance sheet and high credit quality. This is going to be very important as we need to access the credit market and in terms of obtaining attractive rates from our financing.
So turning to our financing over the next five years, we’re anticipating and issuing about $3 billion of new debt and $800 million of equity, and this is up and above our $400 million that we plan to issue through our DRIP as well as our benefit plans, and the 400 million just breaks down about $80 million a year.
In terms of our CAPEX program, we thought we should maybe take a break here just for a second and talk about our pension plan because we do have some financial commitments or commitments that we plan to make around our pension plans. Currently, we believe we’re funded at about an 80% level across all our plans on a consolidated basis. We have four plans, but we do plan to make pretty substantial investments in each of the next five years from around 150 to 200 million. In terms of our pension expense assumptions and as we look forward, in 2011 our actuarial assumptions for discount rate were 5.5% and our long-term rate of return was 7.5%. As we move into the end of the year 2011 and look to 2012, we do see pressure to lower both of those actuarial assumptions. What that’s going to do, of course, is drive our estimates for pension expense up in 2012 compared to ’11; however, we believe we’ve been very conservative in terms of estimating our 2011 pension expense and we have incorporated that into our overall O&M guidance that we provided you in the third quarter earnings call.
Going back to financing, in terms of our debt financing, in 2012 we plan to retire about a billion dollars of debt. We’ll be glad to get rid of some of that old 8% coupon debt. We do plan to issue in all four of our operating companies new debt, but you can see the highest level of concentration is in NSP-Minn and PSCo, not only because of the refinancing but we have very high levels of capital spend, which you’ve heard a lot about this morning.
Regarding equity and in terms of what we indicated in our third quarter earnings call, we do not plan to issue any new equity in 2012 outside of our DRIP and benefit plan issuances. But we will be opportunistic, and if market conditions warrant, we may enter into a forward sale. We believe there is real advantage in terms of locking in the price as well as avoiding dilution or delaying it for a period of time. We had real success with this in 2010 when we had a transaction similar to this.
So turning to our track record, we strongly believe we have a proven track record not only for delivering on our earnings growth of 5 to 7% but our dividend growth of 2 to 4%. As you can see, since 2006 we’ve achieved both of those, and really 2011 is just much the same – we’re on track. In May of this year, we did raise our dividend $0.03 a share or 3%, and as we said in our third quarter earnings call, that we expect to end 2011 in the upper half of our guidance range. But as we look to the future, and I think it’s important to have this discussion, in terms of our earnings guidance, and if we look at 2009 as our base, at least through 2013 we’re very sure and we have a lot of confidence in terms of continuing our earnings growth of 5 to 7%. However, there’s a few things that we need to discuss and actually was discussed today in terms of potential headwinds.
First, starting of with what we heard in terms of economic recovery, and the presidents all covered this, we do believe our service territories – all of them – are showing economic recovery. We’re better than the national average, but we do see that we’re facing headwinds in this area. We’re only projecting sales growth for the next five years on a consolidated basis of about 1%. Also, we’re seeing some headwinds relative to our authorized ROE. We’re seeing some compression closer to the 10% level. But regardless of this, we see we have a lot of dividend flexibility as we go forward.
Right now, our dividend payout ratio is about 60%, and I will say many of you have asked, even in my short tenure, is why are we allowing our dividend yield to lag behind our peers? And we really do strongly believe at this point in time, because we have such large construction programs for the next several years, that this is the best place to put our money in terms of our investment in our one programs. But as we get past that peak in 2013, we do believe we have a lot of flexibility. Our construction programs will moderate and our cash flow from operations will actually start to improve as well. Again, this is what Ben always calls our dry powder.
In terms of our low payout ratio, and just to emphasize the point of our strength, you can see we’re at the 60%. The average of our peers is 65%, but we’re significantly lower than that and we will have flexibility. Again, looking at our payout ratio, in the near term if we continue to achieve at our earnings growth between 5 and 7%, in only a very short period that we’re actually going to drop below that dividend payout ratio of 60%. So again, we see this as a real asset in terms of flexibility of our overall return.
So going back to the value proposition that Ben closed with, we do believe achieving a total 10% return by a combination of earnings growth as well as dividend and yield is very sustainable to the future. Again, through 2013, we strongly believe this is achievable through our continuing 5 to 7% earnings growth, the dividend yield of 2 to 4; but as we get beyond that, we do think we have a lot of flexibility. If we do hit the headwinds and temper in terms of our earnings growth, we have flexibility to increase the dividend to ultimately result in a total return of 10%.
So in terms of closing and delivering on our plan, I think you’ve heard—I hope you’ll have a clear appreciation. We do have a very robust pipeline in terms of capital investment, very strong in financial discipline including access to our capital markets, a proven track record in terms of earnings growth delivery as well as dividends; and I think the last bullet sums it up. We really believe we’re uniquely positioned to deliver a transparent and sustainable total 10% return.
So that’s it in terms of—that’s our story and we’re sticking with it.
All right, so we’ve got Jack and Cindy that are walking around with microphones. Mr. Fremont?
Paul Fremont - Jefferies
(Inaudible) it looks like on 100 basis points, there would be roughly $0.20 of incremental earnings power. Should I think about that as being part of the equation of keeping within that 5 to 7% range of earnings growth beyond 2013? I mean, is that part of the game plan to try and monetize that?
It’s definitely part of the game plan, and I think if we achieve that 100 basis point improvement, we’d be pushed at the top end of that EPS growth range, maybe beyond. So that’s definitely positive; and remember, we also have been pretty candid about the fact that we see some ROEs coming down over time if interest rates stay low. So there will be some push-pull there, but I think closing that ROE gap is one of the most shareholder accretive things we can concentrate on, and that’s where we’re focused.
I don’t know if you want to add anything to that?
I would just say—I mean, I think I would agree that if everything stayed constant and sales actually improved, that would put us above, but really, in terms of closing the gap it’s keeping us consistent in the 5 to 7% range.
Paul Fremont - Jefferies
And sort of the second question is as rate base growth slows and cash flow surpluses or increases continue, can you give us a sense of sort of priority use of surplus cash? I mean, it sounds to me like—you know, dividends, is that at the top of the list? Would you also in future consider potentially share repurchase? What would be—or are there projects that are not in your construction program that you think could actually boost your construction spend?
Yes. I mean, we’re going to be opportunistic – remember the Calpine deal that we did just a little while ago. I mean, if something like that came up again where it makes sense for customers, it makes sense for shareholders, you would see that CAPEX forecast increase and that would be a good thing, I think, to you as an investor. As far as whether we’d use cash for increasing the dividend or a share buyback, I think our bias is obviously to increase the dividend. That said, I think we have to be sensitive, and we have the luxury of time on how tax policy, if it does change, it all rolls out, so you have to be sensitive to that. But we know that as investors, you value that dividend. We also know that you value long-term strong balance sheets, and I think we’ve done a good job making sure we accomplish both of those goals.
Yeah, a couple questions – first, how should we think about—do you have kind of a target capital structure? Is this 46% equity ratio where you want to be, or given that you don’t plan to issue equity this year, are you kind of ahead of where you wanted to be?
Let me start, and I’ll give it—Steven, that is roughly our targeted capital ratio, but I think you hit upon something that I think is a good point, and because we have a good reputation with the rating agencies, because we’ve done what we said and we weren’t forced to issue equity, those sorts of things, I think we have a lot of credibility. So as Teresa mentioned, I like to talk about dry powder. I think we have dry powder with the rating agencies too, so more flexibility there.
You want to answer the equity question?
In terms of the opportunistic?
I mean, we’ll watch how the market conditions develop. Clearly we have big capital programs, and again if we see an opportunity such that it makes sense, we will seriously consider entering into an equity forward. Again, it will lock in our price and delay some dilution potentially into 2013.
And Steve, the long-term objective we’ve had in the equity ratio has been in the 43 to 46% range, so currently it’s at the high end of the range which is why we don’t see a need to issue equity in ’12.
Just one other question, I guess, on the—maybe two other questions. On the CAPEX plan, if you thought about what is the highest—is there anything in there that has decent potential to—you know, the most risk to it of either time or amount. Is it mainly the CSAPR-related spend potentially, or--?
I would say that’s the time in terms of risk. For example, if the stay was granted or it was delayed, but the amounts are probably right. In fact, all that we really did is move those up. Some of them were in 2016, ’17, and they’ve just moved up into—you know, as you saw in Kent’s slide, primarily in 2013.
And then one last question on the dividend policy and thoughts there, and I know this is probably premature, but when you think about that next stage potentially after ’13, do you think more about growing the dividend at a quicker rate than earnings, or more of a step change, kind of re-stepping at a new level just as you’re thinking about it right now?
I think it’s real premature to say that. You know, the thing that we have is the value of time, so you have some of the macro economic conditions turn out, what happens with the capital expenditure type opportunities. It’s something that we discuss with our Board obviously every year, and it’s just too early to really give you any more indication than that.
Andy Levi – Caris & Company
Hi, it’s Andy Levy from Caris again. December 16, we’re supposed to get some final rules out of the EPA. I’m just curious, number one, if they’re—I don’t think we’d get it from the EPA, but maybe eventually from the administration, a two-year delay on implementation or even maybe some delay on CSAPR. I would assume you guys would be okay with that, so I just wanted to get your thoughts on that. And then just also what you’re kind of hearing along those lines as far as what you’re hearing out of the administration and what they may end up doing or not doing once the rules come out.
I think if we do get a two-year delay in CSAPR, actually that’s going to give us two more years to do the capital investments. We think that would be a lot more reasonable time frame. If you looked at the 200 to $250 million for customers just to buy gas in the interim, that would be very, very expensive. We know that eventually those controls will have to be put on down in SPS, so we think that would be positive. As far as what we’re hearing, we’ll have to wait to see where that is. I mean, we’ve been—a lot of people have been doing a lot of work with the EPA to try and see if we can get some swings. There’s been things from people at FERC that have actually challenged the EPA on the rules, and others. So far, we haven’t seen as much movement there, but we do feel either between EPA or the DC court that we’ve got some really good arguments, and so we think we should be successful.
We should hear on our petition for stay. I believe we expect to hear from them at the end of this year or the very early part of next year, and clearly we filed the suit because we couldn’t come to resolution on the CSAPR issues. And you know, we don’t take that lightly. I mean, I think we’ve got a pretty good track record of working with the EPA, and we just needed the luxury of time. As Riley was talking about, our stakeholders are ready for it. They know it’s coming; they know that’s part of modernizing the coal fleet. So CSAPR is really the problematic area for us. MACT and the other things that have the industry concerned, I think it’s our proactive efforts that have frankly put us in very good shape to meet those standards.
What do you think as far as the Obama administration – are they kind of wavering a little bit from what you’re hearing? Are they maybe a little concerned about the election and how these rules may affect that?
I think they’re concerned about the election, but—I don’t know, Dave, do you want to take a shot at that?
You know, I just don’t have enough information to comment if they’re—you know, what the talk is inside with that agency between the administration and them.
Ali Agha - SunTrust
Ali Agha, SunTrust. Two questions – one, going back to the CAPEX program, particularly the ’12 and ’13 numbers that are the big numbers ramping up, how locked in are those? In other words, is there a scenario you see that would cause you perhaps to dial down on some of that CAPEX and maybe (inaudible) the dividend earlier than the post-’13 scenario you’ve talked about? That’s question one.
Well, in terms of how solid is the 2013 CAPEX numbers, if we start there, they’re pretty solid. I mean, Clean Air, Clean Jobs that David Eves talked about in terms of that needs to be done by 2017. We have the CSAPR amounts – I suppose that could be delayed. We have moved Monti in terms of the upgrade to 2013. We have gas infrastructure in PSCo, and then we have quite a bit of transmission investment. So I think it’s pretty solid in terms of what we’ll be spending there, so in terms of that not happening and potentially delaying or having an earlier implementation of a dividend, right now I don’t think we see that as probably the first course of action.
And Ali, I would just stress too, the point that we’re making with the flexibility is that the law of numbers, the other things with macro economic conditions, sure, our EPS growth rate may change but we have the flexibility to move the dividend up. What could also happen is we find wonderful opportunities that could increase the capital expenditure program, so I think the point is the 10% total shareholder return we feel really strong about. We have different levers to get there, and that’s the flexibility that we’ve built into our programs. Time will tell which of those levers we pull.
Ali Agha – SunTrust
And second question, you alluded to the Calpine asset acquisitions that you made, and the timing was right and under the PPA expiring, et cetera. When you look at your portfolio of PPA projects right now, are there potential projects like there out there that could materialize in 2012, just looking at a timing perspective, or are these events that may play out over the longer term period?
Yeah, we do have opportunities, but there’s two things which have to happen which did happen for Calpine. I said it before, and I don’t want to be redundant, but it has to work for the customers and it has to work for you as a shareholder. So there’s a lot of discipline that goes with that, but we have a whole team of people that are constantly out there assessing those kind of opportunities. It could be ’12, it could be ’13, it could be ’14. It could not happen. But if it does happen, it’s the icing on the cake, obviously. The capital plans that Teresa and others have laid for you are solid and that’s just organic growth.
Jonathan Arnold – Deutsche Bank
Jonathan Arnold, Deutsche Bank. On Black Dog, Ben, I think it was mentioned earlier that in the new resource plan, you’d put it on hold for a while. Is it in the plan but just later, or is it not in this new plan that’s been filed? And have there been any other changes to transmission timing that kind of offset some of that as you’ve reshuffled the plan?
Jonathan, what we’ll do in the resource plan that the commission will receive today is show them what the change in volt load has been as well as what we’ve seen in the forecast over the expected life of the plant. And I think it’s going to tell them that it’s prudent to push that back a few years. Now, I don’t see because transmission is already to the site and what we would do is use the site to burn gas in existing units, and also convert some of the coal to gas looking forward, that there really wouldn’t be any change to transmission expense resulting from that decision.
Jonathan Arnold – Deutsche Bank
And are you putting a specific date on when you think you would need it, or not at this stage?
Well, right now it would be after 2020, but we’ve given the commission several forecast sensitivities and told them what some of the contingencies would be, and they of course could decide to move sooner or later with that unit.
Dave, I think it’s 2018, isn’t it?
And just—Jonathan, just a point of clarification, Black Dog is not included in the five-year forecast for capital.
Right. Actually, it was one that we removed this year, looking last year to this year, so it’s been taken out.
Jonathan Arnold – Deutsche Bank
It was in there and now it’s not?
Paul Fremont - Jefferies
Paul Fremont again from Jefferies. Just as a follow-up to Jonathan’s question, my understanding is that the commission is considering other competing proposals to Black Dog. Given sort of what you think is necessary in terms of timing and amount, does that mean you have to submit a revised proposal? Would you be looking to potentially bid it as a smaller sized repowering project, or would you anticipate that there would essentially be no changes to the original proposal that you had made?
Well, what we’ve done is we’ve asked the commission to put that proceeding you’re talking about in abeyance and then to evaluate the forecast, and then they’ll make some decisions about how to go forward.
Paul Fremont – Jefferies
Okay, so you’d have the flexibility if something smaller was needed to redo your whole proposal? You wouldn’t be held to your original proposal?
Right, right. Right.
Paul Fremont – Jefferies
Question on the ROE compression that you’re talking about. I’m just trying to understand, given the current yield curve, let’s say if it stayed like this for a while, should we think of—is it almost sure that you would see ROE compression then, or are you more looking into the future, saying look, rates could even go lower and then we’d definitely have some pushback. How should we think about this?
And on the flipside, your total return of around 10%, assuming rates went back to where they used to be – you know, 3, 4% over the 10-year, that type of thing – could we expect actually better ROEs or even more? Is this 10% a floor, or how do you think on the upside, how does that look?
Yeah, I think the 10% is based upon today’s conditions and forecasts, et cetera, and I think your question about ROE compression, we’ve already seen it. It’s come down gradually. Typically, commissions go a lot slower than the formulas might spit out a number for a number of reasons, not the least of which is they understand it’s a long-term gain. We’re in a high capital intensive mode, so it’s been gradual and I think it would continue to be gradual with some floors. As far as if and when we return to a normal interest rate environment, I think the answer is absolutely – we’ll have opportunities to see ROEs rise. The reality is they probably wouldn’t rise as fast, again, as the models would spit out. That’s kind of our business.
In the ROE compression you’re seeing, you’re seeing authorized ROEs that used to be somewhere in the 10.5% range, maybe a little bit north of that in Minnesota, come down to more in that 10.3, 10.4 range. So you’re seeing a gradual compression coming down.
Again, I think you can see the opportunity. If we can close that lag, we can more than offset 20 basis points of ROE compression.
And it has been gradual. If you look at the RRA averages for ’09, ’10 and what’s expected for ’11, I mean, it’s only been about 20 basis points between ’09 and ’10.
Any other questions?
Do you want to talk about (inaudible)?
Vikings over the Broncos this weekend!
Oh, I don’t know!
I have a question. In 2020, nat gas versus coal, why aren’t you planning more nat gas, less coal? I’m curious given nat gas prices where they are.
Why aren’t we retiring more coal – is that your question?
Yes, or have a bigger percentage of nat gas in your portfolio.
Well, I think we are transitioning—we are reducing our dependence on coal. I mean, you see that. I think the question is why isn’t it being more offset by natural gas? Is that the question? Well, the answer to that, I think, is the renewables, primarily wind, which while from a planning perspective you don’t put much planning capacity value on it, the reality is with our wind resources, they approach 40% capacity factors. I think in fact, didn’t we, David Eves, set a record just a few weeks ago for 56% of our energy being delivered by wind at one point? So you’re seeing gas as the backup but wind, again, as a kind of a hedge to natural gas, which is why I think you have such a balanced fuel mix there. So I don’t know if I answered your question or not, but wind—I guess renewables would take up the slack that normally would think that gas would.
I might add just a little bit to that. I think your question is around the diversity of the fuels. If you look through our history, I mean, we’ve had a very diverse portfolio of fuels throughout the company. Right now, the price of gas looks really good for the next 10 to 15 years. There aren’t any guarantees there, so have a variety of fuels, we’ve done very well in the past and we don’t want to put our money just on one particular fuel because there is no guarantee what the price will be in the long run. But we think our customers will be better off with the diversity.
Maybe I would just add in terms of our coal and many of our plants, I mean, our coal plants, we have extensive plans to retrofit them in terms of putting on the most current technology, like Hayden and Pawnee in Colorado. Comanche already has those on, so we’ve done a lot of work around that in terms of improving coal.
I think that’s a good point. Before we’re investing all this money down in SPS on controls down there, we’ve done some pretty extensive studies, taking a look—if you add all the different costs that it will take to keep these plants up and running for the long run, how will it compete with gas, even if you put some carbon costs on those and if you take a look at even $20 carbon, we think, like in particular Toke and Harrington are still cost-effective. If you look at how cost effective they are today, you look at all the environmental controls we’ve put on them, and you look at the shape they’re in, they’re very, very well run plants. And so we do extensive studies on each one of the plants to make sure it does make sense to run them for the long run.
Can you talk a little bit about transmission ROEs – what are you earning, what are you allowed, and how concerned are you about the possibility that FERC will lower the allowed ROEs?
I’m very concerned FERC will lower the ROEs, but our ROEs are typically state-authorized, and I think Teresa Mogensen did touch upon it, but one of the reasons why our stakeholders want us to build is because they’re quite aware of the premium ROEs that the independents get. So we do have a small portion of our transmission recovered through FERC ROEs, but the vast majority of it is recovered at the state level with whatever the authorized – and I think that is the key word, the authorized – ROE is because we typically have forward or rider mechanisms to recover that transmission. So it works out to be a very good risk-adjusted place for us to invest.
Any more questions? All right, well thanks a lot for attending. Have a great holiday season.
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