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Executives

Paul A. Johnson - Vice President of Investor Relations & Business Development

Benjamin G. S. Fowke - Chairman, Chief Executive Officer and President

Kent T. Larson - Senior Vice President of Operations - Xcel Energy Services Inc

Karen Fili - Vice President for Monticello Nuclear Generating Plant

Teresa M. Mogensen - Vice President of Transmission

David M. Sparby - Senior Vice President, Group President of Xcel Energy Services Inc, Chief Executive Officer of Nsp-Minnesota and President of Nsp-Minnesota

Teresa S. Madden - Chief Financial Officer and Senior Vice President

David Hudson - Director of Strategic Planning and Community Service

Analysts

Andrew Levi

Neil Mehta - Goldman Sachs Group Inc., Research Division

Adam Cohen

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Michael Weinstein

Steven I. Fleishman - Wolfe Research, LLC

Kit Konolige - BGC Partners, Inc., Research Division

Greg Reiss

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Mark Barnett - Morningstar Inc., Research Division

Xcel Energy Inc (XEL) Investor Conference December 4, 2013 9:00 AM ET

Paul A. Johnson

Good morning. My name is Paul Johnson, Vice President of Investor Relations. Thank you for coming to Xcel Energy's Investor Meeting. Today, we have many people from Xcel Energy with us. We have Ben Fowke, Chairman, President, CEO; Kent Larson, Senior Vice President, Operations; Karen Fili, Vice President, Xcel Nuclear Generating Plant; Teresa Mogensen, Vice President, Transmission; David Hudson, incoming President and CEO for SPS; Dave Sparby, Senior Vice President, Group President and President and CEO of NSP-Minnesota; Teresa Madden, Senior Vice President and CFO. They will be presenting. In addition, we also have Scott Wilensky, Senior Vice President, General Counsel; Judy Poferl, Vice President, Corporate Secretary; George Tyson, Vice President, Treasurer; Mark Stoering, President, CEO for NSP-Wisconsin; Jack Nielsen, Director of Investor Relations.

To assure that we keep our meeting on track, what we're going to do is we're going to have the presenters present and we're going to hold the Q&A until the end. And then we'll have all the presenters come back up on stage to answer all your questions. We expect to keep this meeting moving, and we'd like to be done by about 11:30. On this slide, you'll see our Safe Harbor language. As you are aware, some of our speakers will make forward-looking statements. These are based on certain risks and assumptions that are listed on this slide and also our SEC reports. With that, I will turn this over to Ben Fowke. Thank you.

Benjamin G. S. Fowke

Well, let me also welcome you to our 2013 Analyst Day. I'm really pleased so many of you can make it downtown. Also like to welcome the people that are listening in on webcast. And I hope you had a chance to mingle and meet some of the management team and our board -- some of our Board of Directors. We have 3 of our directors here today. Kim Williams, formerly with Wellington Management; Gail Boudreaux from UnitedHealthcare; and Richard Davis from U.S. Bank, who also serves as our lead director. I can tell you, we have a great board. It's a supportive board and very much in line with myself and the senior management team in making the right decisions for long-term sustainable value. Got a great agenda today. And as you can see on the screen there, I hope that if you don't already believe it, you will believe at the end of this presentation that while Xcel Energy today trades at a discount, we really are truly a premium company and a company that's very well positioned for future success. So I won't do the Safe Harbor unless you really want me to, Paul did that well, and I'll go right to our value proposition. And again, I think it's one that we are positioned to deliver on for a long time into the future and has a balance value proposal between growth and yield. We think we can grow EPS at 4% to 6% and we can grow the dividend of 4% to 6%. You risk adjust that, again we think that's a very compelling value. And we're going to talk about how we are positioned to achieve this in the future. But I think it's also not a bad idea to step back and look at our track record of delivering on past promises, and it starts back in 2005 when we introduced our long-term guidance range and growth range of 5% to 7%. You fast-forward to today, and I would challenge you, I think we're one of the few utility companies that actually achieved their goals. And you can see what we did on both an ongoing basis and a GAAP basis. So we're one of the few that achieved their EPS growth objectives. And that same timeframe, we said we wanted to grow the dividend 2% to 4%. We achieved that, too, with our growth rate of 3.4%. And finally, we also recognized the importance of a strong balance sheet. We didn't want to have leverage and introduce more risk to achieve those 2 goals I just mentioned, so we had some credit goals and we achieved those goals in 2010. So while the path doesn't necessarily mean how successful we'll be in the future, I hope that gives you some comfort that you're dealing with one of the few companies that has a track record of delivering on promises.

So that's the past. Let's talk about the future and how we're going to be successful. And there's a series of building blocks that you'll hear more detail about today, that I think will -- has positioned us very well for success, and it starts first and foremost with operational excellence. Now every day, we deliver to our customers on the promise that we've made to them to give them clean, safe, reliable energy at a competitive price. We do that every day, and I can tell while it doesn't guarantee financial success, if you don't run a good operating company, I can guarantee you, it ensures you won't be successful. And we run one of the best, if not, the best utilities in the nation. I hope you also know that over the years as you've known Xcel Energy, we are very keen on risk management, whether it's the operational risk, day-to-day operational risk, whether it's the environmental challenges, the whole industry faces, whether it's making sure you don't over-leverage your balance sheet and introduce short-term things that can have long-term very negative consequences. So we've got a focus on risk management. We continue to have in our 21 jurisdictions across 8 states, and yes, that means we follow a lot of rate cases in this construction cycle, but I believe we have a very solid regulatory compact. You'll hear about that. We continue to have great organic growth opportunities. That's getting rarer and rarer today too, and when you put them altogether, you really do have sustainable shareholder value and you're positioned for success, and that's Xcel Energy. So let's talk a little bit about some of those components. Let's start with growth. This time last year, roughly, that we introduced our 5-year forecast in 2017. It was a pretty robust forecast at $13 billion with over $3 billion in this year. Well, today, we're going to introduce our 5-year forecast and I'm pleased to tell you, it's grown over $1 billion in this timeframe. So we continue to have great organic growth opportunities. Start with the base you've heard about last year, we're going to have the wind projects at NSP, 350 megawatts of owned wind. Again, this is wind that is going to save customers money in fuel, forgetting the environmental benefits. We've gone through a resource plan with the department and we believe that Black Dog 6 will be the best alternative for our customers, so that's in the forecast. And then you're going to hear a lot about this today but we have a very unique opportunity in the southwestern corner of SPS, in [indiscernible], if you will, in New Mexico and that's to invest in primarily transmission plus some generation, and I think you're going to be pleasantly surprised about the recovery opportunities there. So that's what's in the forecast today. Now I can tell you, I think we have other opportunities on top of that. I think we're very well positioned to be a winner in transmission in the FERC 1000 world. We know that it makes sense to form a Transco, so that we have another arrow on our quiver. You'll hear some -- a little bit about our plans to make sure we do that and we'll get started on that. But we've got great plans in the hopper. We've developed transmission competitively, and I think we'll be very successful in that arena. We'll continue to look for fuel for steel opportunities like we did with Calpine. You might remember a few years back, I think we have some opportunities to do that and again, none of those opportunities are captured here. So more to come with our growth opportunities. Of course, growth opportunities, without a constructive regulatory compact, aren't very good, actually. Again, we have a great regulatory compact and I'd like you -- again, the step back in history a little bit and we'll go back to 2005 and you remember, when we started this construction cycle, our full utilities were in various spots. NSP-Wisconsin. NSP-Wisconsin was in a great place and today, and the outlook is about the same. Now, Wisconsin is a relatively small part of our portfolio. PSCo is a big part of our portfolio. Back in 2005, I would say, most of you here thought it was mediocre at best, maybe worst. Store test years, some pretty contentious rate cases. You look at today and where we're heading, multi-year plans, riders, forward test years, so we've made tremendous amounts of improvement at Public Service Colorado. In SPS, back in 2005, I think everyone, myself included, would agree it was a pretty poor regulatory spot. Fuel disallowances, contentious relationships with some of our stakeholders, so tough place to be. Albeit had the lowest prices in the country or close to and it still does today. So let's fast-forward. SPS has room to improve but we're going to talk about some of the mechanisms we have to invest in that are available to us today that allow SPS to compete for capital internally. You'll hear more about that.

And then finally, NSP-Minnesota. Back in 2005, the constructive good regulatory environment and while we took a setback in 2013, I really believe and you'll hear, again, more about it today that NSP-Minnesota is going to be a great place. By the end of 2014, we'll have multiyear plans in place, and then that will mean 2 of our top jurisdictions are in a multiyear plan, and it kind of segues into the next slide. One of the trades you make when you're on a multiyear plan is to get capital recovery and de minimis of O&M recovery. So it's really important we bend the cost curve down. We believe we'll be able to do that over the next 5 years. You'll hear it today about our operational excellence plans, the process improvements we're making that really are going to drive the cost curve down, in addition to some things that are naturally turning around like pension expenses. We'll be able to hit those markets. And so that's going to be aligned with the multiyear plan, it's going to reduce regulatory lag and I think again, that positions us for success. Now, one of the things that we won't compromise on to get to that 0% to 2% growth rate is reliability. We're not going to defer maintenance. Our stakeholders have been very pleased that we put the money into the system. Some basic blocking and tackling like tree trimming, to more progressive things about how the grid will look in the future and how -- and state of the art storm restoration techniques. And it really comes together, this last year, when we had storms in all of our jurisdictions. We had ice storms in February at SPS. We had a store flooding just recently in Colorado. And then, of course, at the end of June in Minnesota, we had a series of 3 storms over 3 days in late June that took out over half of our customers. We returned 95% of those customers back into service within 3 days. So I'm proud of that. Our customers are pleased with that. And I'd like to show you a little video that -- well, I thought I would show you a little video.

[Presentation]

Benjamin G. S. Fowke

Currently, we have roughly 107,000 customers still without power. The majority of those are in the Twin Cities Metro area.

The good news about those storms is I don't think many of you heard about it here on the East Coast. And you can see from some of the clips that we had, we really got great media coverage and we got all the customers back on within 6 days. So we're really pleased with that and I think it should give you comfort that one of the core risk that we all have to manage is operational risk and we do a great job with that. We have other risk we have to manage to, starting with the environment. Of course, this is a challenge for the whole industry. But here again, we've been proactive, saw this challenge coming, got started early, started making changes on our own terms with our own recovery mechanisms. And what you're seeing as a result is we're going to have to rely less in carbon in 2020 than we did in '12 and of course, less than we did in '05, some pretty significant decreases. What you're not seeing is this dash to gas for Xcel Energy, where everybody moves the gas and then you're very much tied to whatever the price of gas does. You can see in 2020, that we're going to actually use a little less gas than we do today, and that's because the renewable portfolio is going to grow so much and it's going to grow with economically justified renewables. The wind projects that I talked to you about. They're going to save our customers hundreds of million of dollars in fuel. The environmental benefits are just a byproduct, essentially. So you got a balanced fuel mix there, balanced energy mix. And again, I think that positions us very well and of course, we're achieving the environmental results that are going to be so important for the future. At 2020, we will have reduced our carbon emissions by over 30%. You can see the other emissions that we have are also going to be reduced. So you have a utility in Xcel Energy that saw this coming, took the steps and because we started early, we're able to keep our prices low, get started on this and the environmental challenges that we have, have pretty much been mitigated.

The other thing that I hope you know about Xcel Energy when it comes to risk is we don't put the balance sheet at risk to achieve financial results. I think it's very important for the long haul to have a solid balance sheet. We've got great liquidity. Our debt has a great tenure to it, and we've made the right decisions on our balance sheet. As a result, we have great credit ratings. So we've got the dry powder that's so important. And speaking of dry powder, we get to the dividend. And we recognize that we have a lot of flexibility on the dividend, having just raised our growth target from 2% to 4% to 4% to 6%, we know we've got flexibility. We know our payout ratio is below the median. We also know we've got great growth opportunities that we need to balance against, and you saw a little bit of that on my slides and you'll hear more about it today. And we want to keep our balance sheet strong. So the dividend is obviously an important part of our value equation. It's very important to the board. Obviously, it's their decision. We talk about it periodically and we're comfortable with this -- our ability to achieve this kind of growth rate for you and we recognize, too, that with flexibility, we can, at times, potentially grow the dividends faster than earnings. So hopefully, the dividend flexibility you have combined with the growth opportunities we have is compelling to you. Again, I think we're a premium company that happens to trade at a discount today. We have all the hallmarks of excellence and we're very well positioned to deliver to you the 4% to 6% growth in both EPS and dividend that we've talk about. Today, you're going to hear from a number of people, as Paul mentioned, we'll start with operational excellence. You'll hear from Kent Larson, who has really over the last few years, introduced significant innovation and process improvement into the operational side of the business. Some of those costs have been masked or those cost reductions have been masked by cost increases across other parts of our business. Karen Fili, one of the many new senior leadership executives we brought into our nuclear group will talk to you, not only what's happening at Monticello, so a little bit on Prairie Island, but the fact that having gone through a few years with some pretty high costs in our nuclear operations, we're now in a position to see those costs go down. We'll then hear from Teresa Mogensen. We have real transmission opportunities and I think we'll be very well positioned to continue capitalizing on our own opportunities within our backyard and the regional opportunities that are right in front of us. We got a great track record, you'll hear about that. Of course, regulatory issues are always important. Two people that you'll hear from. You'll hear from David Hudson, who is the incoming CEO at SPS and David's been with the company a very long time and he's very versed in regulatory strategy. He's got a great strategy to invest in SPS and get recovery. A lot of it, especially incrementally, coming from FERC-type jurisdictional returns. And then Dave Sparby is going to give you the latest on the Minnesota rate case. And finally, Teresa Madden will close it up by talking about some of the particulars, our financing, things like that related to our strategy. Again, I think it's a great agenda. I won't take any more time. I'll introduce Kent Larson and thanks for coming today.

Kent T. Larson

Thanks, Ben. Good morning. I appreciate the opportunity to be here with you today. Today, I'll discuss our operational excellence journey. I'll talk about some of our past successes, along with our plans for the future. You've all seen the Safe Harbor, so I won't cover that. For us, operational excellence is about putting the best processes and procedures in place that deliver strong operations performance, along with good efficiency, both for the short term but sustainable for the long term. Our goal is to be a solid top quartile performer with O&M growth rates in the 0% to 2% range. We started this journey about 4 years ago in energy supply. We've made a decision we wanted to operate energy supply more from a centralized approach with a one-fleet approach as opposed to a plant-by-plant approach. We put together a transition team for this effort that went out and benchmarked with a dozen other utilities looking for the best practices, best procedures and technologies. Over the last few years, we've been implementing those and as you can see on the graphs here, we made significant improvements. Our unplanned outage rate has improved by more than 40%. Safety has improved by more than 50%. In my mind, safety is a good measure of discipline in an organization. It's good to see that. But also from an O&M perspective, we've taken it from a growth rate around 4%, down to an average of 1% over the last 2 to 3 years, if you exclude chemicals. We did the same thing in supply chain starting about 4 years ago. We made a decision we wanted to transform the organization. We put together an overall plan to do that. One of the first things we looked at is the talent we had within supply chain, we saw there's opportunities for improvement. We did a lot of training within the organization. We actually transformed about 1/3 of the people over the last 3 years. We brought in people from the retail, the food, the manufacturing area. And with the economy being down, it gave us a great opportunity to bring in some real talent. We also put in new software system for supply chain that allowed us to mine the data and look for opportunities for improvement in savings. We dramatically improved our processes internally and also with our suppliers. As you can see here, it's delivering results. Our material availability has improved substantially. What that means is our crews have the right material at the right place at the right time which helps them with productivity. Our supply chain savings has gone from third quartile to first quartile. This is measured by CAPS, a leading supply chain research firm. And again, OSHA has improved, their safety has improved by more than 60%. We've made great gains in energy supply and supply chain, but we're just getting started and there's more opportunities in both of those. As we move forward, we want to build on our past successes and take what we've learned in energy supply and supply chain and move it across the entire operations organization. Operation represents about half of the O&M spend of the company and most of the capital. Our goal is to implement one Xcel Energy way across the entire organization, putting in common processes within the business unit and across the business units also. And also, leveraging technology substantially to take cost out and improve our overall product. To give you an idea, one of the technologies that we have been using is LiDAR. We actually use LiDAR to actually patrol our transmission system. It's a helicopter with radar attached at the bottom of it, then we'll fly and pinpoint problems or line clearance issues on the transmission system and issues that way. What that allows us to do is improve reliability and take cost out as a process also. Let's take a look at a quick video we have here.

[Presentation]

Kent T. Larson

Vegetation or trees are almost always the #1 cause of electric service interruptions across North America. So one of the main reasons we do vegetation management is to try to mitigate or reduce the threat of vegetation in terms of causing outages and having people out of power. The advantage of LiDAR is we can pinpoint precisely, identify in a surgical fashion which trees truly are a threat. So after those and leave the other ones alone, which have saved us millions in terms of management [indiscernible]. LiDAR is a remote-sensing technology and essentially, it enables you to create a 3-dimensional point cloud of the right-of-way, the facilities in that right-of-way, adjacent vegetation, any other objects that are essentially in that -- in the LiDAR's path. And how it's done is it's typically an integrated pod that is attached to the bottom of a helicopter. You're going to have usually at least 2 high-resolution cameras on there as well, so you're getting some really good imagery of the right-of-way the facilities and the vegetation that the helicopter is flying along. And the helicopter can typically survey about 100 miles of right-of-way in a day. One of the things that we've demonstrated is that you can recycle that data for many different uses, and we're constantly finding different ways to use that same set of data that was collected in one pass. Vegetation management has been around ever since there's been overhead lines. There's certainly been improvements in the equipment and the tools to do the work, but essentially, you're still pruning trees or removing trees, so that part of the work really hasn't changed a lot over the last century. However, remove-sensing technologies like LiDAR and taking a more geospatial approach to the work has really been a gamechanger for us in the last 5 years.

Kent T. Larson

Strong project management has been one of our core capabilities for quite a few years. We have strong capabilities in the engineering area, supply chain and also construction. That gives us the ability to bring in projects at a lower cost than what is normally done out there on average in the industry. If you take a look at building projects and if you don't have the capability in each one of these areas, to bid out project as a whole, typically the cost of that is much more expensive than if you manage a project closely. You've got very strong supply chain capabilities. As you can see, a generation here, we brought in projects substantially below the market. Just as last year, Jones forward down at SPS came in at the price of about $540 of KW compared to the market at $750. Teresa Mogensen will show you similar results for the transmission area. Our plan is to be the industrial leader within the last 5 years, both in performance and cost. You could see here that we are in the top quartile or near the top quartile in most of the areas that we major, most of the 3 critical areas. In 2013, we stepped back and took a look at operations so -- and said, we could do a better job either what we're doing right now. So at the beginning of 2013, we put together a team to take a look at all of operations. Operations, nuclear finance, and also IT to take a look and see how we can make improvements. What they've done over the year has gone out and benchmark with 25 other businesses, about half of those are utilities and half of them aren't. What they've done is identify the opportunities for improvement moving forward. The plan is to take these 75 people that have been working throughout the year and redesign our major processes to take cost out of the business and improve overall operations performance. To give you a few specific examples we're already working on, in energy supply, we're putting in a new diagnostic center. That diagnostic center will be a central system that will manage the performance of all of our major power plants with thousand of data points out there to try and predict failures before they occur. That will improve overall reliability and reduce our overall cost. We're also putting a lot of money into improving our distribution system from an automation point of view. You saw the video that Ben showed earlier. With the improvements we've made within the last year, we've actually reduced the cost of net outage but at least $1 million and shaved at least a day off of the restoration time. Our goal is to be a leader in the industry within 5 years. That 75 people that have been working throughout the year have identified the opportunities for improvement. The 3 major opportunities for improvement overall are in the field productivity. As we improve our processes, procedures and scheduling in that area, over the next few years, we can take 5% to 15% out of the cost of that part of the business. In energy supply, the best place to look for taking O&M out is on plant overhauls. We'll be focusing on that area to improve our planning and scheduling and material availability, and we believe we can take 5% to 20% out of the cost in that area. And lastly, is in the supply chain area. We've made great progress over the last few years, but they're substantial opportunities that we move forward. As we improve our processes within operations, it will allow supply chain to get involved with projects even earlier and take out more cost than we have. And we see a 5% to 15% opportunity there. Operational excellence is a journey. We're making great progress but there's many opportunities in front of us. We will be a top quartile performer with O&M growth rate in the 0% to 2%. With that, I'd to introduce Karen. We'll talk a little bit about our nuclear part of the business.

Karen Fili

Welcome. I'm Karen Fili, Site Vice President of Monticello Nuclear Generating Plant, and I appreciate the opportunity to talk to you today about our nuclear fleet. It starts with running a great utility, one that is prepared for tomorrow. Our nuclear fleet has strong operations. We are proactive in addressing environmental risk and we have invested in the facilities and the workforce for long-term sustainability. Nuclear excellence is about striving for perfection. It's about ensuring our equipment, our operations, our training programs and cost aligned with industry excellence. Today, I will discuss our nuclear strategy and how we are preparing for the future.

Our nuclear fleet also offers energy diversity. Nuclear is a safe, cost-effective and clean alternative. Our nuclear units offer clean, carbon-free power to Xcel's overall energy mix. We run our nuclear fleet -- units as a single fleet. We use the same processes, have the same high standard and incorporate industry best practices. Both Monticello and Prairie Island have made significant capital investments to ensure our plant equipment is in good, material condition and to keep them running safely and reliably. We've also invested in the facilities and the workforce for long-term sustainability. Our nuclear strategic cornerstones are performance, people, cost and revenue. We are positioned to safely run our plants for the long run. We have great operations and that is fundamental. We have managed our risk well. Our nuclear fleet has demonstrated strong performance and is well positioned for sustainable performance in the future.

Nuclear power plays an important role in Xcel Energy's fuel mix. We carry 29% of northern state power and for non-carbon emitting generation, nuclear is 56%. Nuclear is one of the most reliable forms of generation available today. Our nuclear plants run 24 hours a day, 7 days a week and for very long periods of time. In our recent history, our Prairie Island plant has run reliably from breaker close from the last outage to breaker open in the current outage, 480 days of continuous power operations.

Unit 1 has run for 300 days continuously. At Monticello, the unit has run continuously since July, over 140 day since the last refueling and extended power uprate outage. Both units have run well and will continue to run well.

Just to give you a benchmark, in 2012, operating nuclear reactors in the United States operated at just over an 86% capacity factor. Prairie Island is currently running this year at a 94% capacity factor. And Monticello, in the last few months, has run at 90% capacity factor. Being online, 24 hours a day, 7 days a week helps our nuclear plant keep our dollar per megawatt hour bases low, and it also provides a foundation to allow other resources such as wind, solar and hydro to be integrated into our operating mix.

To continue providing safe, clean and reliable energy, our nuclear fleet has implemented several key projects to ensure equipment is in top condition. At our Monticello plant, it's a 600-megawatt, single-unit, boiling water reactor, and it received a renewed license allowing the plant to operate into 2030. Our Prairie Island plant, which is a 2-unit, pressurized-water reactor, each unit rated at 550 megawatts, has been extended to 2033 and 2034. In 2013, at Monticello, we completed a 6-year life cycle management and extended power uprate project. This project placed a large majority of major equipment and will support our plant through end of license.

So as I said, both Monticello and Prairie Island have made significant capital investments. Nuclear investments paid for this year with the completion of the Monticello life cycle management and extended power uprate installations. Monticello is conceptually a new plant. Major equipment replaced included the main transformers, main generator, the steam dryer, reactor feed pumps, condensate pumps, and feedwater heaters. These outages were complex and difficult but Monticello was successful in implementing all outages safely and the plant is currently running well.

Major projects at Prairie Island include the Unit 2 steam generator replacement, the main generator replacement project and the main transformer replacement. Capital investments at our plants are expected to return to more typical levels following completion of the Prairie Island life cycle management project. A large part of our future capital spend will include mandated, regulatory projects such as cybersecurity, Fukushima-mandated projects and potential security upgrades.

The final cost estimate was higher for our Monticello life cycle management and extended power operate project. There were 3 key contributors to the overall cost increase from the initial estimate. These were: program and design and scope changes; delays in the licensing progress; and installation complexities. Program and scope changes include uprating the reactor feed pumps from 2 versus 3 smaller. This required upgrading our 13.8 electrical distribution system. The complexity of this replacement for the 13.8 system was incredible. We routed during the last outage over 20 miles of large cable, made thousands of connections and completed this task in very tight spaces. So if you picture building a house and then trying to rewire the house, that's what we did in replacing the 13.8 distribution system.

The second impact was challenges and delays in our licensing process. NRC escalated standards from previous approvals caused delays and additional cost. And also, the government shutdown impacted our final approval date. And we do expect to receive that approval late next week.

At Prairie Island, the Unit 2 steam generators have operated successively for over 39 years, longer than any other steam generator in the United States. This complex project will ensure that Unit 2 is operated reliably over the next 20 years. This project is similar to the steam generator successfully installed in Unit 1 in 2004. This project's currently in progress, with the old-standard generators already removed, and they were removed through the existing equipment hatch. The new steam generators have been moved in place. This cost and outage duration are currently on track.

Our nuclear operations and maintenance budgets will decline in 2014 and stabilize. Our O&M cost in 2012 and 2013 were slightly higher due to longer refueling outages at both Monticello and Prairie Island. These outages were not only to complete our Monticello life cycle management and extended power uprate, but were also to work on the overall maintenance of the plant. Our future O&M expenditures will decrease, and then future increases will bend the cost curve and increase at a slower rate.

As you see, our largest capital investment are the investments made to complete life cycle management and extended power uprate at Monticello and the steam generator replacement Prairie Island in 2013. There are some continuing life cycle management projects at Prairie Island through 2016. And then the other, which is in the blue, include our regulatory required projects, including compliance with our Fukushima orders and cybersecurity orders. Not only have we invested to achieved high reliability, we have also invested for improved safety of the facility. We offer high reliable and safe operations at the plant. Even with the events of Fukushima, we can be predictable in our cost curve and our capital investments.

The standard for nuclear power in the United States is continuous improvement and the pursuit of operational excellence. Xcel Energy is implementing a strategy to continue to improve our nuclear fleet performance. For performance, we have liked new plants. Our investments are have positioned us to safely run our plants with high-capacity and additional operational excellence for the long run. Excellence in operations for our plants will yield reliable equipment performance, which will reduce our cost for the long run.

For people, it's leadership sustainability. We have an infrastructure in place to support our nuclear fleet. We have invested in training and in recruiting talent. Our workforce plans include succession planning and transfer of knowledge. Our workforce stability and our leadership ability are an important factor and a key part of our workforce strategy. The industry expectation in nuclear is perfection, and we measure ourselves against that perfection day in and day out.

Our approach for cost over the last few years was for the long run, and now, you see the results. We have liked new plants and we'll be able to stabilize spend. Our cost curve will provide consistency and predictability. All of our investments we've made in the plants over the last few years are prudent and add value to the customer. Our EPU investment was a good investment for the long run and a benefit to customers.

Nuclear overall provides our customers with safe, clean, reliable and cost-effective energy and is a key part of Xcel's energy portfolio. Our work and our investments have positioned our plants for the long run. Our Monticello life cycle management and extended power uprate work were good investments for our customers and gave us new plants for the rest of license. Our strategy and cornerstones: performance, people, cost and revenue, will position our nuclear fleet for success for the long run.

Thank you. I'd like to turn it over to Teresa Mogensen.

Teresa M. Mogensen

Good morning, everyone. I'm Teresa Mogensen, Vice President of Transmission for Xcel Energy, and it's been a busy and exciting time in the transmission world. I'm happy to be here today to talk to you about how Xcel Energy is a transmission leader.

A few facts to start out. We're one of the largest U.S. transmission utilities with transmission assets in operations in 10 states or 20% of the country. Our net book at the end of 2012 is over $4 billion, with significant investment underway. Out of the 3 North American interconnections, we're part of the eastern and western grid, and we have direct ties to the third grid in Texas. We're currently successfully executing over $1 billion of transmission capital investment in 2013, with many projects under construction and also in the pipeline.

Our upcoming 5-year transmission capital forecast remains robust. We're selling our currently planned base spend in the green, and recent adds to support significant oil and gas industry growth in the SPS area in blue. Coming off our $1.1 billion transmission spend in 2013, we're at just under $1 billion next year and back at that mark again in 2017 and '18. This forecast reflects real projects with planned spend. It does not include all the additional possibilities that may occur as we continue to move through time, energy policy changes and industry evolution.

Our transmission investment recovery situation also continues to be very positive. 75% of our upcoming 5-year capital forecast spend qualifies for rider of formula rates, 5% is recovered through Wisconsin's biannual rate case process, and 20% is recovered through other states' normal rate case processes.

Let's move to some of the significant developments in the transmission world as driven by the Federal Energy Regulatory Commission. FERC's transmission policies have been substantially based on the idea that transmission is a key enabler to broader energy policy goals. FERC's primary transmission objective, shown on the slide here, ultimately led to Order 1000, which is driving the next major evolution in the transmission investment environment today.

At Xcel Energy, we've been focusing on our transmission strategy in response to FERC Order 1000. Many details of Order 1000 regional compliance plans are still in flux and aspects of the order itself are still being challenged. Like many other impacted companies, there are some parts we support and some parts we don't necessarily like and are still working to modify. However, assuming the order is ultimately implemented, the key things for us are to get the competition rules right, to make sure that the regional plans make sense and will truly benefit our customers and the regions, be able to win the projects that we want to win, and make sure that we can successfully execute those projects within the bid parameters.

This map shows our 3 current FERC Order 1000 regions. You can see our 4 operating company retail territories in the solid colors, and the crosshatches show the boundaries of our FERC 1000 regions. MISO is our region in the north in the green crosshatch, and the solid pink area shows Entergy, which will become part of the MISO footprint by year end. SPP is our region in the south in the blue crosshatch, and WestConnect is our region in the west with the orange crosshatch.

I mentioned that Xcel Energy transmission is currently in 10 states, with Oklahoma and Kansas being the 2 states where we don't currently have retail territory. You can see that these FERC 1000 regions now hit 25 states or 50% of the country, not considering potential interregional projects with at least one foot in one of these 3 regions. We already an integral part of these 3 regions, and with our current customers financially affected by any projects that becomes eligible for competition in any of these regions, this reflects potential new opportunity for us to make a difference.

Even in an emerging competitive environment, we'll continue to operate with our foundational principles of focusing on customer benefit and collaborating with partners and stakeholders. We don't build just for the sake of building. We seek to plan and build the right projects for the customers in the regions, ones that truly deliver value. We really work hard to stay aligned with our regulators and policymakers in this process. We know what it takes to bring projects from a plan to in-service. Our track record shows that. We have strong internal expertise and resources in every aspect of the transmission business. We have key materials and services alliances to ensure sufficient and timely external resources as well, and we have the ability to effectively blend both internal and external resources to best manage cost and risk. Because we're in this business for the long haul, we also don't do things for the short-term on one particular project that could hurt the installed base or future projects later. We've also been successful in influencing the emerging rules and plans by having people deeply involved in regional transmission planning and policy matters, and we'll continue to be deeply engaged going forward.

The competitive aspects of FERC Order 1000 creates both opportunities and challenges. To compete and win will require both flexibility and multiple approaches. One of these strategic tools is the stability to deploy a transco investment structure under FERC jurisdiction, where it's appropriate to do so. We're working now on creating alternative transmission investment structures to provide this future flexibility.

Let's talk a little bit about our track record of successful project execution. This chart is an update of one I first showed you in 2011. This comes from the study of publicly available data on 345 kV transmission projects, 345 kV being the bread and butter, if you will, of big transmission in the U.S. The study covers projects that have gone in-service over the last 15 years starting in 1998, or in the process of getting ready to be in service by 2020. This chart shows miles of right-of-way by owner for 140 345 kV projects with publicly reported information that was available in enough detail for analysis. The top line of this chart shows Xcel Energy has the most miles of 345 kV transmission completed or in progress since 1998. This includes our CapX2020 project portfolio, with 3 major 345 kV projects now under construction in the north.

For an updated cost-comparison analysis, we applied the industry standard Handy Whitman construction cost index to adjust all of these projects to equivalent 2013 dollars. For the same set of 345 kV projects with mileage shown on that prior slide, you can see that the overall average cost for all the projects is $2.1 million per mile. For the Xcel Energy projects, the average cost is $1.72 million per mile. Regional averages are also shown with the overall Xcel Energy average being lower than the overall average for each of these regions. We work hard to deliver the best value projects in consideration of the many different stakeholder requirements and expectations in play.

In closing, I reminded you today of how Xcel Energy is a major transmission presence in the U.S. and a proven transmission performer. We're positioned well, both geographically and competitively, for continued growth. We're experienced collaborators and transmission development partners, and we can create the alignment necessary to get things done. We're focused on best-value project delivery, which means being able to deliver at a reasonable cost and for an attractive return, while meeting today's stakeholder expectations, which are different and much higher than those in the past. Our track record shows our success at doing this. In short, we are, and we'll continue to be a transmission leader. Thank you.

I'll now introduce David Hudson.

Kent T. Larson

Well, good morning. I'm David Hudson. I'm with the SPS system out in Amarillo, and I'm a West Texas boy. And it's my privilege to be here today with you. This is a great opportunity for me. I'm excited about becoming the incoming President and CEO for the SPS system. I've been with SPS for 30 years in various roles and so I know the stakeholders and the system quite well. I know our past and I could see a vision for our future. And I'm also very proud to work with Xcel Energy, especially over the last 5 years, we've done a lot of constructive things. And we've got a lot of exciting opportunities for SPS in the future. A lot of investment coming in because we're seeing a lot of growth that Ben talked about.

Last night, I was watching the local news and they came on with a story, talking about when you're talking with and having conversations with people who are presenting, there's certain keywords you should use. And for -- when you're talking with men, they talked about you should talk about football and beer. Well, naturally, that got my attention and I laughed, started watching this news story. And they said, for women, you need to talk about chocolate and shopping. And I thought that was pretty interesting, too, because I love high school and college football. I love beer. I really enjoy chocolate, and I like to shop for chocolate and beer, in particular.

So there's 2 main things that I really want to talk about, with respect to the SPS system. And one of it is we've gone a lot of improvement on the regulatory construct both in Texas and New Mexico on the retail side and at FERC, also, over the last 5 years. We've now developed and we're using a lot of tools to help improve investment and cost recovery on our systems.

The other thing is we've got some really interesting opportunities coming up. We serve a lot of oil field load. We always have, but right now, the growth is really expanding as we have 2 major tight oil or shale oil plays within our service territory. So I'll be talking a little bit about that.

Just sort of an overview, the SPS economy has always been pretty well stable. We've always had somewhat of a slow but constant growth. I can remember SPS growing at 1% CAGR for many years. But we're actually growing a lot faster then right now. We have a lot of oil field load in our area with the shale plays, the Avalon Shale play in southeastern New Mexico. It actually dips down into West Texas down in the ERCOT region. But all of that shale play that's north into New Mexico is in the Xcel Energy SPS service territory. And then we've got the Anadarko shale play, which is up in the northeast panhandle, and that's primarily a wet gas play. The natural gas there is very wet and there's very valuable liquids there that people are producing and drilling a lot for.

Just a little bit a quick background, SPS is an electric-only bundled utility. We serve in Texas, but we're actually part of the Eastern Interconnect. Our generators are perfectly in sync with the generators serving New York City right now. We're part of the Southwest Power Pool, so we're an interstate commerce. We got a lot of FERC regulation. We serve a lot of wholesale, agricultural load in our service area, and we have a lot of transmission. We serve at retail in Texas and New Mexico, which are 2 challenging jurisdictions, but we've made a lot of progress in both of those jurisdictions over the last 5 years. And then we have, like I said, a lot of transmission at FERC under formula rates. And also, we make a lot of power sales to wholesale co-ops and municipalities under power formula rates. So that gives us opportunity for a very quick recovery and timely recovery of new investment expenses on the system. We're not in ERCOT, so we're not in the restructured ERCOT market. A lot of times in Texas, they'll issue news releases that we're having a statewide issue, when they're really just talking about ERCOT. We had to explain to our press, that no, SPS and Xcel Energy are still fully regulated by the utility. And we have a lot of success, as Kent talked about, bringing on new generation with our growth.

53% of our sales are actually at Texas retail. Like I said, we have a very large industrial base. It's primarily petrochemical related: oil extraction, natural gas extraction, we have other mineral-extraction industries in New Mexico. Potash is actually very valuable now. It's used as a fertilizer and the international market is pretty good.

Our second largest jurisdiction is actually FERC at wholesale. 32% right now of our power is sold from generation at wholesale, but about 35% of our transmission is sold, and we see that as a really growing segment, as our co-ops are actually serving a lot of irrigation load where the irg [ph] farmers are now producing more and more crops from underground irrigation and pulling the water up from deeper depths.

We talked about the petrochemical down at southeast New Mexico in northeast panhandle, but we're seeing those areas grow. We're seeing the Permian Basin grow up into our Southern Texas boundaries. We're seeing more oil extraction around the Amarillo area. But all of this is leading to significant growth, and we're outgrowing many element on our system and having to add new capacity.

I looked -- we've had a lot of capital added to our transmission network. And the simple explanation is over the last 19 years, we've had a 2.7% CAGR for transmission peak demand. So naturally, we are -- with that type of compound growth rate, we're outgrowing many elements. And so we're adding a lot of transmission investment and we see that actually growing a lot more.

Another real important key thing is we have improved returns on the SPS system. I'll show you that in a little bit. And we actually have very low rates still in our jurisdictions. We have the second lowest retail rates in Texas and the lowest in New Mexico. And we've been very focused in the last 5 years in improving our regulatory compact that Ben talked about. We've been working on our stakeholder relations, developing new tools, that I'll show you in a few minutes, to get more timely cost recovery.

Just focusing on our retail load growth. Our base retail forecast right now is about a 1.8% CAGR. But it's just pretty strong growth. I talk about SPS years ago being around 1%. So we've got it -- when you start compounding that over time, we're outgrowing elements, we're having to add more capacity to the system. But now, we look at all the shale oil plays in southeast New Mexico, it's basically doubling that CAGR, because they are now drilling oil wells where there's not infrastructure at all. It's no man's land. It's literally the corner of the electric universe, so the -- of the eastern grid. It's very -- at the very southwest corner of the whole eastern grid. And so we are planning. The oil companies are expecting us to be out there as soon as we can, because right now, they're using diesel generators to power their pumps, and we can give them a lot of savings by adding this infrastructure. So that's a very important takeaway.

On regulatory, cost recovery improvements, we've made a lot of progress, especially at FERC, we've implemented forward-looking formula rates on transmission. Also, on the power side, they're trued up to actual cost after the fact. We've got ROEs ranging from a low of 10.25% to 11.27% on the transmission side that reflects the 50 basis points for ROE participation. SPS participates in the Southwest Power Pool RTO. And then on the Texas side, I just listed here several examples. We've got the TCRF. We just filed a $13 million case last week in Texas for that. We have opportunities for purchased power capacity recovery distribution. We've been focused very heavily on stakeholder relations. The way I view it in my past job as over industrial customer community relations is stakeholder relations is sort of like the grease that helps the regulatory machine run smoother. So we've really got to focus on that. And right now, we have a very positive image in our jurisdictions with our customers. And that gives us more acceptance for interim rates, which are not exclusively allowed in Texas. It also allows us to come up with rate plans and get more timely cost recovery. And then we're also working on recovery increase environmental cost through our fuel factors. In New Mexico, we now have a future test year that we're using. And we have a case proceeding there. This just shows you our increased ROE performance. As Ben talked about, in 2007 and '08, we were working through some very difficult retail cases where they were upset with us for making so many wholesale sales. And so we've sort of refocused on retail. And now, we've really rebuilt our relationships. And now, we're earning a 9.4%. We're still targeting, over the next 5 years, the 9% to 10% range right now for ROEs based on our current expectations on interest rates and stuff. So we're really focused on that. We're driving that hard with the stakeholders. We've worked a lot on local visibility and engagement. We're very, very visible in our communities in the past, we were seeing somewhat as withdrawn. We had upset our cities. Remember, in Texas, we use a historical test year, but more importantly, the cities have original rate jurisdiction. And we have to reimburse them for their regulatory costs. So they're very active. If they're upset with us, they can take a pound of flesh off out of us. So we work on that. On capital recovery, we're seeing -- we have about 60% of our transmission is under FERC transmission rates, and that's because we're part of the RTO. If you recall, we go through the RTO's open access tariff and allocate cost. So a highway cost opposed to stamp [ph] across the pool. SPS is about 13% of the pool. So only about 13% of our cost come back to us for highway projects. On byway, it's 1/3, 2/3. So on the transmission side, we get a lot of recovery through these formula rates that I talked about and the cost allocation to the SPP. But we also have the TCRF that we're using in Texas. We just filed a case there. And then we have the New Mexico future test year. On the production side, again, we have formula rates there, that true up. We have the TCRF and the New Mexico test year. And then even on the distribution, we have the distribution cost recovery factor and future test year. So we have a lot more tools available to us now than we did 5 years ago. We still have more room to improve. And that's what we're focusing on. And as Teresa talked about, we're looking at opportunities for establishing the TransCo, closing any leakage gas that we have on transmission recovery, differences in allocation between jurisdictions, continuing to use interim rates. We're getting ready to file a major rate case in Texas. And then we'll be using interim rates there, capacity riders. And then, of course, we're going to be pursuing legislation in New Mexico for transmission cost recovery riders. I really think the competitive aspect now is a great time for us to be looking at the TransCo, especially within the whole SPP footprint. As Teresa explained, we've demonstrated a lot of capability in building transmission. And we can do that, not only in our footprint, but across the pool. And so we'll be working on that.

In summary, we're providing a lot more attractive investment for Xcel Energy. We've got lot more opportunities and tools available to us. And so we're now working our way through that and using them. We're filing timely rate cases. But even more important, we have a lot of opportunity for new investment in the SPS system because of the oil industry. We'll be focusing on timely recovery and tactical operations to get that done. We'll continue to focus on our customer and stakeholder relations because it's so important to the regulatory process and communicating with customers about why we're having the raised rates. We're linking up economic development with infrastructure improvement. And therefore, it will translate into rate increases. But I think with lower natural gas prices, that's going to be to our benefit and customers' benefit. And it show you the increase rate recovery for these rate base investments. We've resolved a lot of the issues in the past on earnings gas. You've seen our increased ROEs. And we're taking a lot of actions to improve our regulatory returns. So again, thank you very much. I hope you enjoyed the football bowl season coming up. Eat lots of chocolate and drink plenty of beer. So thank you very much. And now, I'd like to turn it over to Dave Sparby, who's going to talk about the regulatory situation with NSP-Minnesota.

David M. Sparby

Well, thanks, David. It's great to be back here in New York. I'm pleased to have the chance to update you on Minnesota regulatory strategy this morning. And I have to say, early on, there are no exciting video clips from the regulation department like Ben and Kent have. Now we have a very constructive regulatory environment in Minnesota. And we're building on that compact to improve our returns with our proposals like our multiyear plan, our rate mitigation proposal and the detailed filing we're making in support of our Monticello nuclear plant. And this morning, I'll review each of these initiatives in some detail. Our regulatory strategy has always been built around aligning our investments with the interest of our stakeholders. And take our investment in wind energy, for example. Policymakers support it because it addresses the state's renewable energy goals. Customers benefit from the low predictable production cost. And investors see the benefits of the reduced environmental and operating risks associated with these kinds of projects. And over the next 5 years, we see considerably more of these projects in our investment queue. We see investment in carbon-free generation like wind and nuclear projects, maintaining a resilient grid with continued transmission investment, as well as an increased focus on our polls and riders [ph] programs, and continuing a diverse energy supply that includes environmental upgrades to our Sherco units. Now although these investments offer significant value to our stakeholders, they do create the need for rate increase for us in 2014 and to support projects underway, as well as recover the cost not captured in our last rate proceeding. In 2013, we experienced several unique events that have contributed to the size of our 2014 request. These events include the return of Sherco's 3 to service, for example, and our Prairie Island steam generator project. Now recognizing the significance of the deficiency, our rate request proposes to moderate the annual increases by accelerating the return of depreciation ordered in our last case. Now the application of interim rates further shifts some of the cost recovery from '14 to '15. Overall, we expect revenue increases of 4.6% in 2014 and an additional 5.6% in 2015. And in the upcoming slides, I'll talk about that in some more detail. Now key costs driving the need for the case includes several highly beneficial projects, some of which I've touched on, the replacement of the PI steam generators, the return to service of Sherco 3, our Monticello investment and some increased nuclear O&M in 2014. But the drivers also reflect significant investment in our core delivery system to ensure its ongoing high reliability. So what's different about this request? Well, there's several favorable differences that should improve our recovery success. Most apparent, if you've seen a copy, it's 11 volumes tall, that even includes the discovery asked of us [ph] in our last case updated with more current information. The case encompasses a longer review period, which addresses a significant concern of our regulators in our '13 case. And we've introduced new tools like our rate moderation proposal to help reduce the significance of the impact on consumers. And of course, finally, we don't expect the return of some very unique circumstances we saw surrounding our Sherco unit in that '13 timeframe. Of course, central to the right strategy is moderating that impact on consumers as we cut through the current investment cycle and creating more predictable pricing for our customers. And to do this, we're making 2 proposals in the case, first, to accelerate the amortization of depreciation ordered in our last case from 8 years to 3 years and amortizing 50% of it over 2014, 30% of it over 2015 and 20% over 2016. Now we're also proposing to utilize settlement payments from the DOE to mitigate the 2015 impacts of the filing. Now together, these proposals should keep rate changes in that 4% to 6% range as we cut across the investment peak. Now another important part of the filing, of course, that aligns the interest of our stakeholders is our decoupling proposal. Decoupling, of course, separates sales levels from investment recovery. And we're recommending the mechanism for our residential and non-demand-metered customer classes. We've proposed a true up mechanism based on weather-normalized use, so we would retain weather risk. Now we've also proposed a plan that will complement our current conservation incentives. Now a significant part of the case, for us, of course, is related to the recovery of our Monticello cost. Now I'm pleased to say, and as you've heard from Karen, the physical additions to the plant are working well. We expect to get our license later this month. And we've made a strong filing in support of an affirmative prudence determination. We also plan to request deferred accounting treatment for certain expenses after the uprate license is approved for the period of our interim rates. Now our Monticello filing demonstrates, in some detail, the costs that were incurred are prudent. Our testimony shows that our plant's a sound investment even at its final cost. And that even if we had known that cost at the time construction was started, we would have proceeded. It includes detailed cost information that supports the reasons for the increases, and also a very detailed summary of the experience of other plant operators completing similar upgrades during a comparable period of time, showing we weren't alone in experiencing these kinds of cost changes. Now looking at the timeline, of course, this Friday, we could see staff briefing papers on our interim rate decision. The commission is expected to make a determination on interim rates December 12. We anticipate implementation on January 3. We expect to intervene our testimony late spring of 2014 and orders in our Monticello and our rate case in the first quarter of 2015. Of course, these schedules could go much more quickly if we're able to resolve issues with intervenors. And we're well-prepared to do so.

So in summary, our investments continue to be well aligned with those of our stakeholders. We've taken actions with the case to ensure that we improve our existing regulatory compact. We filed a multiyear plan to help create more price predictability and to mitigate the impact on our customers. Together, these actions should result in improved returns for NSP-Minnesota. Now it's my pleasure to introduce Teresa Madden, our CFO

Teresa S. Madden

Well, thanks, Dave. It's good to be here today. And it's good to be finally up here, hard to be last in the lineup. So I guess we still have our panel. But anyway, today, as you can tell, the focus of our topics at this meeting has been to provide you information on things that we are -- believe are important to investors. We've started with an overall strategic update. And Dave, it's easy to be a Dave at our company. We now have 3 presidents with the name, Dave. But Dave and David have provided updates in terms of our regulatory plans that will improve our compacts in Minnesota, as well as SPS. We've provided information on our capital opportunities, and then information about lowering our overall O&M, bending our cost curve as we go forward. So my goal is, today, is to bring this all together in terms of how we plan to continue to deliver value for you as we go forward. So just skipping through our safe harbor, move on to, and I'll start where Ben started with our value proposition. And since 2005, and in terms of our earnings growth of 5% to 7%, as well as our dividend growth of 2% to 4%, we've successfully achieved those targets. Now, in October, we did introduce our new value proposition, which is aligning dividend growth with earnings growth at the 4% to 6% level. We continue and plan to have a strong balance sheet with very solid credit rating. And then we also plan to be proactive with our continued risk management. And that would be around all aspects of our business, whether it's operations, regulatory, environmental or overall financial. So ultimately, we think we're well-positioned in terms of this. So starting with how we will bring this altogether, what are the key drivers in terms of earning our overall EPS or achieving our 4% to 6% growth rate? And you can see we have several of those, and I'll walk through each of them individually. And you've heard about them, but again, the objective is to tie it altogether. But probably, the first and foremost, and most important, is to improve our overall earned ROEs. And we have several plans in that area, particularly in the regulatory environment. We have a very robust pipeline. As Ben introduced, we plan to spend $14 billion over the next 5 years, which will drive our rate base growth at just about 5.5%. Along with that, we have a strong balance sheet and solid credit metrics, which will allow us to access the capital markets at very attractive rates. We do plan to lower our O&M cost curve, and you heard about that from both Kent and Karen this morning. And finally, while we have really modest sales growth projected, we believe that, coupled with our multiyear plans, will all lead to successful execution on our target of 4% to 6%. So let's specifically step back and talk about ROEs and how that will drive our goal of earning between 4% to 6%. And this is somewhat just math. If we start with 10%, earning 10%, which we have done for the last several years, that would put us in the bottom half of our targeted range of 4% to 5%. Now if we just moved that up 50 basis points, that will put us in the upper half, or 5% to 6% earnings growth. And if we move all the way to 11%, and we would say that, that probably would require a change in our overall authorized ROEs, that would put us at the very top at 6% or even 7%. So with that, how does that translate in terms of actual absolute earnings growth? And starting with 2012 and our rate base, 25 basis points improvement will actually contribute about $0.05 a share. So you can see the blue line, 25%, $0.05; 50%, $0.10; and 75 basis points, of course, at the $0.15. So let's talk more specifically about ROE and our actions to improve it. One of our base fundamentals has always been get the rules right. And we do have changing and evolving regulatory compacts. Now Dave talked about the multiyear which we do believe will lead to success in terms of closing some of our gaps in Minnesota. And we have really solid experience with this in Colorado. We're in the second year of our 3-year multiyear plan, the first year being 2012, and we actually earned in excess of our authorized at 10%. And we went into the sharing mechanism. We're exactly where we want to be. And we're on track for that in terms of 2013. We also plan, as David Hudson talked about, to expand our riders. And we've been very successful with that, particularly in Texas. Other alternatives like decoupling, and maybe it doesn't make sense across all our jurisdictions, but we're proposing that in Minnesota. And then, of course, Teresa and David also talked about our new construct that we plan to pursue in terms of TransCo. The second area in terms of improving the ROE really has to do with forecast accuracy, and particularly as we enter into the multiyear environment. And sales forecast accuracy is really key, not only to us as we run our day-to-day business, but to our constituents as we look forward on the multiyear plan. Other areas that are important, our timing of our capital spend, as well as our in-service days. And we really believe we have demonstrated improvement in these areas over the last several years. And particularly, in 2013, I will say, on our sales in terms of Minnesota, I mean year-to-date basis, we are like spot on relative to our budget. Cost of allowances, we do have minimum cost of allowances. But wherever we do have them, our high focus is on minimizing our spend in those areas. So if we move on in terms of regulatory fatigue, we do believe we have some regulatory fatigue, but we do think the answer to that is execution of the multiyear plans and the moderation plans, too, because clearly, there's a balance or a tolerance in terms of the customer bill impact. And Dave just talked about in terms of the smoothing proposal with our excess depreciation reserve. Now finally, I will just talk about one additional area that we're really stepping up our efforts, and this is on our outreach program. Basically, we're taking a grassroot approach to this. We had a great story to tell, not only about the storms, where you saw the video, but our everyday service that we provide at a clean, reliable, at reasonable cost. So we really have a great story and -- sorry, we're making a big effort to improve our communication. So the second area that I'd like to focus on is operational excellence in terms of -- I think I'm okay, anyway, in terms of bending down our cost curve. And you can see, we have had a history of about 5% in terms of our overall increases. We plan to bring that to 0% to 2%. And it's been indicated we're not going to do that by just deferring maintenance expenses. We really plan to have sustainable long-term process improvements that will allow us to stay at the lower level of O&M, but more specifically in terms of bending that the cost curve. Operational excellence, you heard from Kent and Karen, and they talked about that in terms of standardization of processes, new technology, but I would just note, in terms of nuclear, I really do think we've rounded the corner in terms of really lowering that curve with the completion of the Monticello upgrade, as well as the life extension and making great progress on Prairie Island. We do anticipate that the headwinds we face are now turning into tailwinds. I just want to mention a few other things. In terms of our overall workforce, we have about 11,000 employees across our system. Over the next 5 to 10 years, we expect 50% of those employees actually to retire. And in that environment, we see that also as a real opportunity with the new workforce coming into play to really implement our new technology, as well as our process improvement. I wanted to spend a couple of minutes talking about our employee benefit program, both on the pension side, as well as the healthcare side because we do see this is an area where we're going to see significant lowering of our O&M cost curve. On our pension, if we start with that, in 2011, we actually modified our pension plans for our new employees. In fact, we just changed them. We went to a 5% cash balance program. The rest of the employees starting before that are on average final pay plans. They vary a little bit. That will significantly reduce our overall pension cost as we go forward. Now it will take a couple of years, but as I just talked about, we're anticipating having a pretty big turn potentially in our workforce. In other things, even with our average final pay, we have examples in PSCo, for example, our last union negotiation, we went from a 3-year average final pay to a 4-year average final pay. On the healthcare side, starting back in about the 2011 timeframe, and now this is really effective for the lion's share of all our active employees, as well as our retirees, we implemented high deductible healthcare programs. And we really, in particularly in 2013, are seeing some traction in terms of how employees are managing their healthcare cost. With that, in turn, will transition to us, then lower O&M. We're also -- we have other design changes that I'll briefly just touch on. We've changed our pharmaceutical programs. We -- well, I wouldn't say we require everyone to go to generics, but we very much incent them through cost measures to go to generic drug. We have a central pharmaceutical provider. If you use that, you'll also see cost benefits on a personal level, which then translates for us. So we've done a lot of plan designs in this area. And as we go forward, in fact, in 2013, we're starting to see a lot of traction. And going back to capital, in terms of our capital investment, as we prioritize capital, and particularly on our refresh and refurbishment program, there's only some O&M that goes with capital. And those that have larger reductions in O&M have higher prioritization. And then finally, I maybe should have started with this, our goal is to align our overall cost curve of our O&M expenses with our sales. And our sales, as we look forward, they are conservative and modest over the next 5 years in terms of our overall projection. You can see on a consolidated basis, it does vary by jurisdiction. We're only projecting sales of about 0.5%. Now there may be some opportunity there if things turn around where we could see some additional improvement, which ultimately could go to the bottom line, or it could serve to just offset some of our future rate case requests. With that, third area I'll just touch on in terms of just tying this altogether has been introduced. You can see, we have our $14 billion of spend over the next several years with the new addition, the New Mexico infrastructure, the Black Dog addition of the CT, as well as the wind projects in Minnesota. So how does that translate in terms of the overall breakdown of our spend? Clearly, transmission is our biggest investment at 27%. A lot of this is represented by the completion of the CapX2020 projects in Minnesota. But we have new projects planned and in progress across all our jurisdictions. If I drop to generation, that's represented primarily by Clean Air-Clean Jobs in Colorado, which is on track to be completed by 2017. And then in the distribution, in the gas areas, you can see that we basically have about 32%. This is primarily driven by refresh and refurbishment. And in the gas area, I'll just say in PSCo, because of the overall economic environment, we had been on a 20-year refresh plan. We think it's better and more -- it's a great time to move that to a 10-year refresh program. It's not because we're concerned about safety, but in terms of the system, but it's just the overall economic environment is right for that. So just a brief update in terms of our investment growth opportunities on our wind projects, it's just where we're at on these. It's the 350 megawatts or it's about $650 million. We just recently received the Minnesota Commission approval. We are expecting the North Dakota approval in December, but we are awaiting a micro-transmission interconnect study, which is expected to be completed in early 2014. Relative to the Black Dog, the additional CT, 215 megawatts, which was about $100 million. We expect to hear from at the ALJ in terms of the overall recommendation later this month. In terms of New Mexico infrastructure, you can see how the $900 million actually breaks down. 2/3 of that is for transmission. And we do believe we'll have a preferred right of recovery or a recovery through a, potentially, a TransCo for that investment. The remainder is in generation, which is in the latter part of our 5-year projection. And then I can just spend a few minutes talking about up and above our $14 billion of spend because we do see quite a bit of opportunity still out there within or close to our service territory. Clearly, in our larger jurisdictions, distributed generation is front and center. And in terms of renewables, we do have, on the solar side of the business, new requirements in Minnesota that were just recently legislated in terms -- we do see opportunity for, potentially, for some solar garden. That is not included in our $14 billion. If the PTC was extended, we think wind is a very good investment, a great gas hedge as we look to the future. So if that changes, we would clearly pursue opportunities there. On the environmental front, while we've been very ahead of the curve in terms of our retrofit and refurbishment of our power plants, we do have some continued opportunity, depending on how the EPA rules ultimately sort out, and Sherco 1 and 2 with some additional SCR addition, as well as we have potentially some further retrofit of Tolk and Harrington at SPS. On the transmission side, I will say, we have very fertile minds in Teresa's group in terms of always coming up with additional investment opportunities. They're great, and particularly with a great recovery mechanism. And then finally, I'd just like to say, I think many of you are familiar with our WYCO investment. We do plan to continue to look for more opportunities in the gas business that would be similar to the WYCO investment, whether it be in pipelines or storage, but we think that there are some things that potentially could well align with our businesses. So we'll continue to keep our eyes out and evaluate those opportunities. So not only do we have a robust $14 billion plan, we think we have more opportunities as we move forward. So again, that was, just quickly, you can see, as we look forward, this will drive our rate base growth at just about 5.5%. So of course, what comes with that, in terms of our financing requirement, we do believe -- again, we have a very strong balance sheet and solid credit rating. We expect to only issue modest equity relative to this $14 billion investment. We think we have a very good track record in terms of being opportunistic overall in terms of our timing and our level of equity investments as we go forward. So more specifically with that, relative to the $14 billion, we plan to finance the lion's share of it with cash from operations at just under $11 billion or the $10.6 billion, a new debt at $10.3 billion, and as I indicated, $700 million. Or we believe it's modest, it is $700 million of new equity. And in terms of the timing on that, I think it's just safe to look at the timing of the capital spend. And it really aligns with that. In terms of the DRIP programs, we anticipate that we'll yield about $70 million a year relative to those DRIP programs or a total of $350 million. Again, it's the same slide Ben showed you. We're very proud of our very solid credit metrics, our strong balance sheet position, which we think positions us well as we move to the future in terms of our capital investment. And then I just want to spend a couple of minutes in terms of actions that we've put in place over the last several years in the low interest rate environment. Clearly, we've lowered our overall average coupon rate. We've gotten rid of all of our expenses, 8% debt. And you can see, in the operating companies, all of them have an overall lower rate. And if we just look to the left, you can see we've moved from an average rate of around 6% to less than 5%, 4.7%. In that same thing, we have been extending our average maturities. We've gone from basically 13, on a consolidated basis, a 13-year average maturity, to 15 years. But you can see on the operating companies, all of them are going to benefit from improvement of extending our maturities.

So then, just wrapping up and in terms of where we started, we do believe we're low risk, attractive at sustainable return, we can provide to you. We have a lot of actions and initiatives in play relative to improving our overall ROEs. We have a very robust pipeline in terms of capital investment, with the $14 billion and even more as we move forward with opportunities, we believe. We're really focused on bending the cost curve down to the 0% to 2%. We think our plans are really solid in terms of getting us there. And then finally, we just -- we have a very strong track record in terms of actually delivering on our financial objectives, and we plan to continue that in the future.

With that, Paul, are we -- I guess we're going to go to our panel and take questions.

Paul A. Johnson

All right. As our panelists come out, we do have a couple of people with microphones that are -- Jack and Darren [ph] that are wandering out in the back.

Question-and-Answer Session

Paul A. Johnson

We'd ask that you identify yourself and the firm you're with before you ask your question. [Operator Instructions] First question?

Andrew Levi

It's Andy Levi from Avon Capital. I guess one of the things I was intrigued by Teresa was the ROE improvement slide and the sensitivity there. How much of the sensitivity is under your control? Meaning, whether it's O&M or other in-service improvements you can make or financial improvements that you can make to raise the ROE versus getting a higher authorized ROE?

Teresa M. Mogensen

How much do we think is our control? I think, clearly, we can move to the 50 basis points. If you get to the 11%, as I indicated, we probably would have to move to a higher authorized ROE.

Andrew Levi

And on the 50 basis points, what do you think the timing on that is? Is it 1 year or 2 years to get there?

Teresa M. Mogensen

In terms of how long it will take us to get there? I mean, we're continuing to work on it all the time. Do we have an exact timeframe when we think we'll get there? I mean, I can't probably commit to that today.

Andrew Levi

And your 2014 guidance is based on what ROE?

Teresa M. Mogensen

Our 2014? We're targeting right around the 10% where we've been earning.

Andrew Levi

Okay. So we should really look at the 50 basis points as where opportunity is over the next year or 2. Is that...

Teresa S. Madden

Sorry, Andy. Can...

Andrew Levi

Because I don't know if this is on -- but we should really look at the 50 basis points as far as the opportunity?

Teresa M. Mogensen

I think that's a good target.

Andrew Levi

For the next year or 2?

Teresa S. Madden

Yes.

Andrew Levi

Okay. And then for Ben, just on the dividend. Got a chuckle out of you on that. Just if you could kind of give us some more detail -- I mean, detail on -- there was a comment on, there could -- it could be somewhat choppy, and I don't mean on the negative side, but on the upper end as far as trying to award the shareholders that way. Because I think, to a lot of shareholders, the dividend's important. So maybe you can kind of talk about that a little bit.

Benjamin G. S. Fowke

I don't know I can add too much clarity on that, other than when you have that flexibility and you have a 58% payout ratio, we can discuss with our board, periodically, whether we could raise the dividend a little bit faster than the earnings growth within any given year. But I really think that, Andy and everybody in the room and listening, when you look at those growth opportunities we have, you really do want to strike a balance between a yield and growth. And I think we've done that. So we'll continue to look at it. We have a flexibility with a relatively low payout ratio. But probably about all the clarity I can give you. Let me go back to your last question, too. If you think about why we are in 10%, because we have some extra leverage at the whole quotes, because our operating utilities typically don't earn their authorized ROEs. So I think what Teresa's talking about, if you look at why we don't earn those authorized ROE's, it's O&M growth faster than sales. Well, we're going to bend that down 0% to 2%. It's not -- it's having capital recovery lag with the multiyear plans will do for us, and it's the incremental investment. And one of the things that David Hudson didn't touch upon is that it was this incremental investment that we have at SPS, and most of it is being recovered in FERC jurisdictions. You combine that finally with a revenue decoupling mechanism in the Minnesota, and our sales disconnect has been pretty significant in some of those cases. And I think we get much, much closer to earning on top of our authorized ROE. You got a little leverage that we've always had at the holdco, and that's where your 50 basis points comes into.

Teresa S. Madden

Neil, you want to go ahead?

Paul A. Johnson

Go ahead.

Neil Mehta - Goldman Sachs Group Inc., Research Division

Neil Mehta, Goldman Sachs. As you think about rate case timing, it's not necessarily the cases that you've filed already but the next iteration of these rate cases across each of the jurisdictions. How do you think about that timing?

Benjamin G. S. Fowke

Well, I mean, it's going to be specific each jurisdiction. But I think the key is, well, we have a multiyear plan in place in Colorado. The next time we file in Colorado, it will be a multiyear plan request. And I think our stakeholders will be pleasantly surprised that the amount of that request is less than probably what they are anticipating. In Minnesota, we'll have a multiyear plan in place at the end of '14. And so now, those are your 2 key jurisdictions. We don't see much change in Wisconsin as every other year. Although we have had success in getting interim -- or not interim, but off-cycle increases in as well. When we look at Texas, well, Texas, we'll file and New Mexico we'll file as needed. But again, I just want to emphasize that much of this incremental investment is going to be socialized under the Highway/Byway programs within the SPP region. So I don't know, Teresa, do you want to add anything to that?

Teresa M. Mogensen

No. I think -- I mean, you've hit the highlights in terms of our timing. I mean, Colorado could be mid next year. Minnesota, we're got to get first through the '13, '14, either '14 and '15, and then we'll probably have one more. But we plan to or intend to go to a 3-year plan there as well.

David M. Sparby

And I'll just add. With my slides included the plant and service, which is the way I think about the need for rate relief. And what you can see is '14, '15, '16, a high-level plant going into service. Following that, the plant looks much more closely aligned with the rates of inflation. So for us, we'll cut our cost at that investment peak, and then we should see rate changes moderate downward significantly.

Adam Cohen

Adam Cohen from Mizuno. Just with respect to your [indiscernible] spend, is it -- what stages are fully excited and ready to go or what stage or the sort of projects [indiscernible]?

Benjamin G. S. Fowke

I had a hard time hearing that.

Teresa M. Mogensen

Yes.

Teresa M. Mogensen

I'll tell it, yes. He says a little bit, so what phase or the projects are making up the transmission spend? So the projects are in all phases. We have a range. We have quite a bit in construction, we have a lot in permitting, we have some in planning. So a substantial amount is in permitting or construction stages with applications out or pending.

Paul A. Johnson

Over here.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

Ali Agha at SunTrust. A 2-part question. One, on the equity need, the $700 million number. Teresa, I wanted to be clear, your current act of market offering still has $177 million left in the authorization. Does -- is that getting absorbed in the $700 million? Or is that $700 million in addition to the remaining $177 million?

Teresa S. Madden

It is the -- it includes that $175 million that we have left under the $400 million in our last update in terms of capital. So it's not -- $700 million is not incremental to that. The remaining $175 million is inclusive of that.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

And my second question. Ben, just following up to be clear on the ROE question. When you look at your current authorized at your utility companies versus what you're earning, can you just remind us what is the lag today? Is it that 50 basis points or what is the exact lag between authorized and earned right now for you?

Teresa S. Madden

It varies by company, but it's generally 50 to 75 basis points. And that's what we're really working on in terms of closing that gap, whether it's through a multiyear or various rider mechanisms that we're adding in jurisdictions or with sales, the decouplings. We have a whole host of things. But back to your base question, it's historically been about the 50 to 75 basis points.

Benjamin G. S. Fowke

But Ali, it does vary. And as Teresa said in her presentation, that at Public Service Colorado, where we have a multiyear plan, it's been very successful. We've actually been in a refund position because we're earning in excess of our authorized return. And so our customers are happy with it. I hope shareholders are happy with it. We're happy with it. We get that in NSP-Minnesota, where probably the lag has been fairly pronounced these last couple of years for a number reasons, and I think you see significant regulatory lag get closed.

Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division

So on a portfolio business, just to keep it simple from our perspective, is it about 50 basis points?

Benjamin G. S. Fowke

Yes, it's probably 50 to 75...

Teresa S. Madden

Yes, 50 to 75.

Unknown Analyst

Jim Bell Capital Partners [ph]. I have a question, David, on your partial decoupling case in Minnesota. Just the mechanics, does it mean that the consumer that saves energy still ends up paying more because you're asking to be compensated for some something that you said? I'm just not -- I mean, I understand the logic why you're doing it, you wanted to be compensated for energy efficiency, I just don't see the actual implementation from a consumer's perspective so they're happy about this.

David M. Sparby

Sure, thank you. Well, those people that implement our conservation programs like our residential lighting do continue to see savings. However, they will also continue, for example, to pay for improvements on the grid to ensure reliability. So there are savings, but there will be some cost like those improvements on the grid, for example, that they will continue to have to pay. But their rates will be lower overall.

Unknown Analyst

Maybe if I may, as a follow-up. What's your view, in general, on net metering by solar rooftop? And I don't know if you're affected by that, but there's obviously a big discussion going in a lot of states. What is your view on that and how do you think that should be managed?

Benjamin G. S. Fowke

I think we probably all have an opinion, but that will take a little while, so maybe I'll speak for the group. We're very supportive of solar. I mean, you can just see on the renewable side how much we're doing renewables, and we're doing it with economics in mind. Rooftops solar is highly subsidized at the federal level. There's other renewables that are subsidized. And we're supportive of rooftop solar. And what we think is important though, is that we call net metering what it is. It's another form of incentives, it's another form of subsidy. And what we're proposing in Colorado is that a portion of net metering is -- becomes transparent, and it gets included in what we have. It's called RESA, it's basically a 2% renewable cap where renewable projects can't move the consumer bills by more than 2%. We think it's important that the incentive associated with net metering is out in the open. We can have an open dialogue around that. That said, people want rooftop, they should have it. We should just be clear what incentives are and who's paying for those incentives. So you'll see us make those arguments. And again, we're going to add 170 megawatts of solar on Colorado. It's coming in at rates that are on parity with fossil fuel. So to me, that's really -- that really sets the benchmark for what the value of solar is when we compare other solar technologies that maybe aren't quite as efficient as the utility-scale solar project.

Michael Weinstein

Mike Weinstein from UBS. David, you were talking in Minnesota that it sounded like keeping rate increases in at the 4% to 6% level is the most important factor that you're facing, and that deferral of accelerated depreciation will be the major method by which you would do that. Is that really -- or what other issues are you facing in this rate case besides that? What other concerns do you have to tackle when you're thinking about that case and how you can get through it?

David M. Sparby

I think the other concern is, of course, the commission through a deal of our Monticello investment. I mean, we've submitted significant amount of documentation. The commission wants to take a very close look at that project. We feel it's a very sound investment and we've submitted just a significant amount of support for. But that, of course, will be something that the regulators will evaluate over the course of the 2014 case.

Teresa M. Mogensen

Dave, I would just add to that. I think in terms of the sales forecast, while we are proposing decoupling, we've had some basically some real challenges in terms of convincing the commission and on parties about our sales forecasting processes. And we're really pleased at where we're at. We made a significant effort to improve those. And as I've indicated, we are really, really, right on track relative to our budgeted electric sales in Minnesota and where we're at on a year-to-date basis through October. So we feel really good about that, and we have very strong arguments in that area.

Michael Weinstein

And Teresa, if you could talk a little bit more about pension savings. You mentioned a couple of interesting methods by which pension would be coming down over the next 10 years as you have 50% more of the employees retiring. And I'm just wondering, are these methods something that we could expect to see across industry? Are you in the forefront of something or is this something you need to excel? Just wondering.

Teresa S. Madden

Well, I mean, I can primarily only comment on our own company. But yes, moving to cash balance plans, I would expect see more. Our savings, the value of the pension plan, cash balance plan compared to a final pay average, it's only about 40% of the final pay average so as we move forward, with our transition of our workforce and our new employees, we do expect to see substantial savings. The other thing I failed to mention, but -- and this isn't so much with plan design, but we are finally, in 2013, through the last of our 5-year amortization of the 2008 losses. So as we go forward, we expect to see a real stabilization relative to this. And finally, as you all know, obviously, the discount rates we expect to be higher. Well, our discount rates will be our interest rate. So it will drive our discount rate higher, which will also serve to improve our overall pension expense. The high-deductibility plan in terms of the healthcare, that's really -- I mean, we are seeing a lot of traction on that. People are really grabbing on to people, our employees, as managing their own healthcare cost. And particularly on the retiree group, we're seeing our overall liabilities in '13 drop substantially, which will then affect our future years in terms of our overall estimate.

Steven I. Fleishman - Wolfe Research, LLC

Steve Fleischmann, Wolfe Research. Several speakers, I think, mentioned looking at a Transco in some way. Could you maybe elaborate a little more on the strategy there? And are you -- is that referring more to new transmission CapEx? Would you look at taking existing transmission out of the states and putting that into a Transco? And maybe a little bit more on kind of how your ROEs currently work on your transmission and what a Transco could do?

Benjamin G. S. Fowke

Yes. I'll start it off, Steve, and ask everyone who wants to contribute to do so. I think it's likely that it would relate to the new transmission opportunities, although it would certainly be open to having discussions about moving some existing transmission. But the reality is that we haven't done that in the past, as you know, because our bread and butter is at the state level. And as Teresa Mogensen showed you, we're doing a heck of a job in fighting for our customers' interest, making sure that transmission projects that shouldn't be built aren't built. And then when we build projects, we're building it cheaper than others. So that puts us in good standing with our states. But I think we also recognize -- you know we have our welfare in Minnesota, we expect it will be a challenged. That we have to have, if we're going to be in the game, our Transco is just something that you need to have so you're on an even keel. Now some of that will depend on how the bidding rules and other things come out. But we don't want to not have that vehicle if that turns out to be a competitive advantage. So where would you first maybe apply that? Well, potentially, in Texas. But you might not even need it at all. But not to have it, we've recognized is potentially getting us a competitive weakness and something that will be pretty competitive. But again, I think, if you look at our track record and if you look at what we've done, everybody talks about winning the bill transmission. We do it, we do it right and we do it inexpensively. So that's -- I think that bodes well for us in the future. Anybody?

Teresa M. Mogensen

I think that's a good summary, Ben.

Teresa S. Madden

Yes.

Unknown Executive

I may just add, after FERC Order 1000, it is critical to have an option like that. I think there's going to be more partnerships in the future, it will provide an opportunity for that. I think it will be an opportunity to look at different financing on projects that we had before. And then also, some projects may be completely in our territory and some might be right on the edge. We don't plan to go outside of our territory very far, but it provides us a lot more options than what we have today. And we need to get it ready, be prepared for that.

Steven I. Fleishman - Wolfe Research, LLC

ROEs. How do they, well, transition right now?

Benjamin G. S. Fowke

Well, I mean, FERC has more deal in ROE's . I mean, there's some concern that they're going to come down, and perhaps they will, but there's other opportunities, financial opportunities, bringing in partners, et cetera, that you can't do if you don't have a Transco. So again, I mean, maybe it's a shade tree we should have planted a few years ago, but you need to get started and we need to be ready. And you saw the spend we're doing, Steve, in transmission over the next 5 years, it's pretty robust. So this is more making sure that we can continue to be a big player in transmission.

Teresa S. Madden

Yes. Just to add, I mean, in terms of the Transco, and looking at Texas and the New Mexico area. In Texas, in particular, because we do have the historical test period, this will provide an avenue for us to move up our ROEs and keep it out of the historical test period, regulatory compact that we have at SPS.

Benjamin G. S. Fowke

Even that said, I mean -- and David Hudson, correct me if I'm wrong, while a lot of that oil patch is in New Mexico, the transmission that we're investing, only a small, small portion of that, 5%, 6%, is that right, is actually retail New Mexico recovered . I mean, of course, that assumes that our projects, our 345 projects are approved within SPP. But we think we've got very solid prospects there.

David Hudson

Yes, but that's right. The transmission is especially highway-socialized across the Southwest Power Pool, and I mentioned that we're about 13% of the pool. But the important thing is that's recovered under our FERC Formula Rate Mechanism, where we don't have regulatory lag. We true up to actual cost, and we have known ROEs. And we've got that through the Southwest Power Pool, out the formula rate mechanism. I think the Transco would just give us even more opportunities on top of that, the work in conjunction with SPP RTO.

Teresa M. Mogensen

And I'll just add. I mean, like I said in my slide, the main thing we're looking for is strategic flexibility. So we're not doing a one-size-fits-all approach, we're looking at having options and being able to deploy those depending on the circumstances that we see in front of us.

Paul A. Johnson

At the back, we have Kit.

Kit Konolige - BGC Partners, Inc., Research Division

Yes, it works. Kit Konolige of BGC. O&M, considerable discussion. Obviously, that's a key part of trying to improve the ROEs, as I understand it. First, I just want it to be clear, the -- I think in '14, you're looking for 2% to 3% O&M growth; and then '15 and forward, it would be in the -- down, below 2%, in the 0% to 2%. Can you give us an idea of why you're comfortable making those projections and how we can get comfortable with them?

Benjamin G. S. Fowke

Well, I mean, we talked a lot about it, Kit. But I mean, it's the headwinds, the turning into tailwinds on pension and health that Teresa talked about. It's the operational excellence initiatives that Kent has already started. But he has -- and he's already seen some, I think, pretty impressive results, but he has more he can do there. And then Karen talked to you about the pretty significant expenses, both capital and O&M, that we have occurred on our nuclear business these last few years. Well, that's over. And you will actually see -- as you saw on that slide, the nuclear cost declined. So you combine all of that, we feel pretty comfortable about it. And that's where we need to be. And then again, as I mentioned, you sync that up the multiyear plans where that is the trade, we're very much in line with where we see the future regulatory compact growing.

Teresa S. Madden

Maybe just to add that on the nuclear. I mean, our outages, particularly at the Monticello, I mean, they've been long. I think our longest one was like 75 days. We had another that was 52 days, 53 days. And those costs, for the refueling get amortized over future periods, 18 or 22 months. So those are starting to come through, but that will be behind us. And as we go forward, we expect to go to more standard outages, likely around the 30, 35 days, and maybe even at the $30 million level. So again, we think we're really rounding the corner. A lot of those outages were long because they had to do extra work relative to the operates and the life extension. So those are real key things. I mean, in fact, nuclear is one of the things that's driving our 2014 case. But once we get through that, we see it steady as she goes.

Teresa M. Mogensen

Teresa's correct. When you have the significant capital investment, that does take a longer outage such as a same-generator outage or extended power operate. I mean, the last outage in Monticello was 820,000 man hours. There's an O&M cost associated with that as well. So as we move forward, we replaced all the major equipment. We'll have less maintenance to do because the equipment is newer. We will have shorter outages. Industry norm about 30 days, about $30 million. That will drive actually, in the negative sense, our O&M cost at our nuclear power plant.

Paul A. Johnson

Let's go to Greg [ph].

Unknown Attendee

A couple of questions or one question in multiple parts, however you want to think about it. The first is if you're going to move on a -- to a former Transco, then we think about the significant amount of transmission spend you're going to do between '14 and '18, can you move to form that fast enough so that we can sort of assume that, that entire '14 to '18 spend could be within the Transco? Or practically speaking, are we thinking about '15? What -- if you're going to make a decision to pursue that route in the corporate structure, when would you make that decision, and how much of that capital would then be potentially falling within it?

Benjamin G. S. Fowke

Well, I mean, Greg, I think most of it would be, if we used, deploy the Transco option, would be in the back end of that forecast. It's going to take some time. And again, we're not going to do anything to alienate our stakeholders. And so -- but you've got to have that option out there, because the world is changing and who wins transmission and our competitive process.

Unknown Attendee

Great. And then a lot of it is happening at SPS. I just did some rough math, it looks like SPS's rate base could almost double between to '14 to '18.

Benjamin G. S. Fowke

That rate base doubled, yes.

Greg Reiss

Just based on the quantity of CapEx there, which is great. It also looks like, I think you kind of answered my question on Pages 7 and 8 of the SPS Co. section that a big chunk of it is under formula rates. Is that also accurate?

Benjamin G. S. Fowke

Yes.

Greg Reiss

But I wonder, as you're stringing transmission to go serve these oil companies, what's the life of the reserves out there? And are you putting in assets with lives, depreciable lives that matchup with the length of the potential demand for the power? If they've got tenure lives in these basins, you're putting in transmission lines with 20 or 30-year lives, have you thought about that as you've made the decisions to string all these wire?

Benjamin G. S. Fowke

Yes. We certainly had those discussions. We're pretty comfortable with it. Remember, a lot of that -- and David Hudson, help me out there. But we, SPS and particularly the oil patch region, is literally on an island. And so it needs transmission period. So I don't think you've -- even if those, the oil services and the plays had lesser lives than maybe we were anticipating, the transmission needs are still going to be there to serve the region. I mean, the region is underserved right now, regardless.

David Hudson

Yes. Well, what we've experienced, I mean, we serve a substantial amount of oilfield load already. The new oil wells, once they've sunk their cost by drilling their wells, they're going to produce out of that well. What we're finding and what we do know is, over time, the wells decline. We have factored in the diversity of that decline. But at a certain point, they start putting in secondary recovery, they start doing water flooding. And then, finally, they do tertiary recovery. We see Occidental really active in that, where they're doing CO2 floods. It takes a massive amount of power to push water and CO2 back into the ground to flush that oil. So we see this as a very long-lived activity in these new shale oil formations.

Teresa M. Mogensen

I just have one additional comment. We're going through the planning process with the Southwest Power Pool in this, and that's where all of this gets vetted out to as far as the transmission that ends up getting cost allocated, because that's a big concern, obviously, by other entities who are going to be paying a part of that transmission that becomes part of the regional grid as to sustainability. So this does all get worked out in a public forum and gets articulated, ultimately in notices to construct from SPP that reflect the approved plan that addresses all these combined issues and needs.

Paul A. Johnson

Okay, go back there.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Julien Dumoulin-Smith, UBS. First, with regards -- going back to the transmission question one more time, could you perhaps just be a little clear with regards to the Southwest investment, SPS? Is any of that potentially going to be funneled into this Transco, or is that 2 separate opportunities? Just to be very clear about it. And to the extent which you're evaluating a Transco, could you talk about the timeline on which we'll finally see some of these FERC 1000 projects come to fruition and how you think about the criteria and how you fit into those criteria that could be delineated here at some point?

Teresa M. Mogensen

Okay. So your first question was related to the slide with blue and the green, the base and then that increment for the additional oil and gas load?

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Precisely.

Teresa M. Mogensen

Yes. So we, as Ben said, we do plan to address focus the initial Transco on that aspect of spend. It will take probably a year or so to get things set up. So to the extent we can and where it make sense, the projects that we choose to put in there, based on the level of FERC recovery on those, that's where we intend to focus on first. So that's about the general timeline we're thinking right now. Second part of the question was focused on future competition?

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Right. So I suppose if you have 2 separate buckets here, as you think other opportunities arising out of FERC 1000, when do you think those will become clear to you? And as you think about elaborating a new Transco CapEx budget, if you will?

Teresa M. Mogensen

Yes. So in our 3 FERC 1000 regions that I showed up there, the way the compliance filings are right now for FERC Order 1000, the first project to be eligible for competitive bidding, because there's a bunch that's grandfathered right now under existing rules, will be the planning cycle that's going through in '14 and start of '15 will be the start of competitive bidding in our 3 regions there. That's how it's tracking right now. Depending on what happens with the compliance filing, that timeline may or may not hold. It may drop back a little bit. But that's what we're planning on, is competitive bidding. We'll start in '15 for projects coming out of the '14 cycle that end up being eligible by virtue of getting pegged for regional cost allocation. So at that -- for those points then we would be considering, as I said, with strategic options, what kind of structure we would like to use to go after those different projects depending on the specific circumstances.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Great. And then just lastly, if you could elaborate it, it seems that some of the criteria that are going to be used for each of the regions differ a little bit. Do you have any sense as to how to think about how projects would be selected? I mean, I know it's kind of preliminary here, but SPP versus MISO, et cetera?

Teresa M. Mogensen

Well, there are different criteria that are being established for each region. So in our regions, in our 3 regions, we've been working with the regions on coming up with an approach. And all 3 of our regions are using kind of a comprehensive evaluation criteria. Meaning it's not just a bid price, but it's a number of factors that get judged usually by some sort of an independent panel that's appointed by an RTO board or some other structure. So a variety of factors gets assessed, including how -- what's your track record, how's your financial stability and then what your price for going forward and proposing to build the project. So the rules are all still in flux, but that's how it looks in the 3 regions that we're participating in right now.

Julien Dumoulin-Smith - UBS Investment Bank, Research Division

Great. And then just a quick clarification for what Mike asked before. With regards to O&M, as you see that 0% to 2% growth rate, is that biased or weighted towards the earlier part of the year or as the later part of the year as you think about the pension benefits, et cetera?

Teresa S. Madden

It's pretty -- and actually we get and we have the 2% to 3%. It's pretty even as we go forward in terms of the projection to be below the 2% level. And it's not necessarily a tapering, but it's pretty even in terms of that.

Benjamin G. S. Fowke

One of the things I talked about, it's really a journey to operational excellence. And the goal is not to just take cost out of the business, it's to improve our processes to end up with better results and lower cost. Hence we've got a lot of work, a lot of processes going. We got 75 people who have been working throughout the year, that will work hard on it next year. I'm comfortable, but it will be a smooth process that continually drive down.

Paul A. Johnson

Over there.

Mark Barnett - Morningstar Inc., Research Division

Mark Barnett from Morningstar Equity Research. I have some of the O&M questions with nuclear, specifically. I guess not really pertaining to the outages that you're going to be looking for recovery, but on more of an look-forward operating basis. There's been a lot of talk in the industry and I guess, particularly with merchant plants about maybe personnel being the primary source of cost savings looking forward. And I'm wondering, when you look at your fleet and how you operate those plants, where are the major levers that you can pull to maybe bring down your overall cost structure there, and whether that's a big chunk of the fruit for your plants?

Teresa M. Mogensen

Okay. In nuclear, we do have a base, very stable O&M cost. And that personnel spend is about 50% to 60% of our overall O&M budget, the rest being materials and supplies and some small contracts. We do have a workforce plan that looks at retirement. We have pipelines and operations and engineering. So as we move forward, we will be focused on our workforce, making sure we've got the right people in place with the right training. But we see that being very stable as we move through the next 20 years.

Benjamin G. S. Fowke

Yes. I would just add that one of the, not necessarily a cost savings initially, but one of the investments we've made was getting fully-staffed. We've run very lean at those plants. And sometimes it's penny-wise and not so smart on a dollar basis. So Karen's new, our new C&O, who couldn't be here today because he's on an evaluation with INPO. We've got a multitude of new people. And what I'm seeing, and it gets back to running plants well, when you're running well, when you fix things right the first time, they pay dividends for you down the road. So I think we're seeing that and we're learning. It's a small fleet, there's only 2 sites, 3 units, but we're learning how to integrate supply chain savings and just kind of a blocking and tackling. And I think we were lagging because we didn't have the, maybe, the horsepower to step back and plan strategically. Well, we can do that now. And we're seeing better results on the operating side of our business, and that's going to translate to Karen's point on the financial side of our business.

Teresa M. Mogensen

We are seeing the benefits for what Kent's group is doing with supply chain and supply chain savings and a lot of our contracts. Our nuclear fleet is small with, as Ben said, 3 units. But we're also a member of the USA Alliance, which has 7 fleets, so we also take advantage of purchase power and contract services through our USA and resource sharing. So another way we save money is we send mechanics to one of our other plants, and they are like Cooper Nuclear station, our Susquehanna. We do resource sharing and we help each other with plant problems. Nuclear is very open to helping each other. So all of these things help us bend our cost curve in O&M.

David M. Sparby

I think both on the fossil and nuclear side, reducing the amount of time plants are offline is a key focus. So plant outages, we both have a focus on that. That will increase output. That will bring our average cost down. It will also reduce the overall cost. I think the other thing Ben mentioned, the better year-on-year plans, the lower your cost are. It's a lot less expensive to run a plant than it is to fix it. We have all of these efforts to take some of the -- take the initiatives to improve overall reliability, drive down our cost, too.

Mark Barnett - Morningstar Inc., Research Division

Maybe just a quick follow-up on that. Do you see any opportunity for outsourcing, especially along the supply chain? Or is that something where maybe you're already doing a significant amount of that or you like to keep that in-house?

Benjamin G. S. Fowke

I think looking at our supply chain group, we made a dramatic improvement over the last 4 years. And we're actually in the top quartile as far as savings. And with that, performance is coming along with it. I feel real comfortable. Like with the CapEx projects, we're in a partnership for those up in Minnesota. We do all the sourcing for those projects out of our group, because we know it will save everybody money when we do that. So we're comfortable with our overall processes. We're always looking for partnerships. But generally, we feel good about it.

Teresa M. Mogensen

And nuclear, our outsource group is our security force, which we want a very trained security. It's not the same as it was 10 or 15 years ago. So we actually do outsource security. No other group is outsourced. We did do some staff augmentation with our engineering group, however, though. And that still, our flexibility is the peaks and valley of our projects go.

Paul A. Johnson

Any other questions? All right. Seeing no hands, we will adjourn at 11:13, which is 17 minutes past or before our expected end time. So thank you very much.

Benjamin G. S. Fowke

Thank you, everyone.

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