CALIFORNIA WIND ENERGY COLLABORATIVE FORUM UNIVERSITY OF CALIFORNIA, DAVIS DAVIS, CALIFORIA TUESDAY, DECEMBER 16, 2003 KEYNOTE: Michael O'Sullivan, FPL PANEL: WIND PENETRATION AND THE CALIFORNIA ELECTRICITY MARKET MODERATOR: Nancy Rader, California Wind Energy Association SPEAKERS: Dave Herrick, FPL Bob Gates, GE Wind Energy Dave Hawkins, California ISO PANEL: INTEGRATING WIND AND OTHER RENEWABLES INTO CALIFORNIA'S GRID AND MARKET MODERATOR: Kevin Jackson, Dynamic Design Engineering, Inc. SPEAKERS: Brendan Kirby, Oak Ridge National Laboratory Michael Milligan, National Renewable Energy Laboratory Jeff Miller, California ISO Tim Tutt, California Energy Commission WEDNESDAY, DECEMBER 17, 2003 KEYNOTE: Lewis Milford, Clean Energy States Alliance PANEL: WIND AND ENERGY STORAGE MODERATOR: Dora Yen Nakafuji, California Energy Commission SPEAKERS: Alan Lamont, Lawrence Livermore National Laboratory Joan Ogden, Institute of Transportation Studies, UC Davis Scott Flake, Sacramento Municipal Utility District PANEL: LIVING AND WORKING WITH WIND: PROPERTY OWNER ISSUES MODERATOR: RICK RUSSELL, Property Owner in Montezuma Hills SPEAKERS: RICK ROBERTS, Senior Appraiser, Solano County Assessor/Recorder IAN ANDERSON, Farmer and Rancher in Solano County TUESDAY, DECEMBER 16, 2003, 1:00 P.M. MR. VAN DAM: Good afternoon, everybody. My name is Case Van Dam, and I'm a faculty member here at U.C. Davis. We would like to welcome you to the second California Wind Energy Collaborative Forum. We have an excellent program and look forward to very informative talks today as well as tomorrow. Before I -- before we start out, I want to give you just a few tidbits of information about us. We are the California Wind Energy Collaborative, and that is an effort that is funded by the California Energy Commission as part of its PIER program, Public Interest Energy Research program. We have been in existence since the early part of last year. February, March 2002 we started off, and we're slowly getting onto some solid footing. It's been a slow start, but I think we are making some good headway. One of our goals is to facilitate, to improve communication between the various parties interested in wind energy in the State of California. And this forum is an excellent way to get these parties interested in wind energy together in one room and to talk about wind in California. I could go on about us, but I kind of want to stop here. More information about us can be found at our web site, and I think most of you already visited that web site to register for this forum. And, of course, you can always E-mail or call us here at -- the information is available, and I will also have some cards available. Before I introduce today's keynote speaker, I would also like to introduce two more people who are very instrumental in getting here and keeping the collaborative going, and these people are Bruce White -- and I'm not sure where Bruce is. There's Bruce. He's standing in the back there. He is also a professor here of aeronautical and mechanical engineering at U.C. Davis, and he's also an Associate Dean in engineering, so he's a fairly busy person on a daily basis. And then a very important person, actually maybe the most important person, is Henry Shiu. And Henry is there in the back, and I think many of you have already had contact with Henry. He's really, as I would say, the glue that keeps things together. So those are two very important people that I enjoy working with on a daily basis, and you'll meet some other people that we interact with on a very regular basis in the coming two days. They will be giving talks. So, at this point, I'd like to introduce, then, today's keynote speaker, Mr. Michael O'Sullivan. He's the senior vice president of development at FPL Energy, and his talk is titled Wind: 2003 and Beyond. A few words about -- a little more information about how we came about contacting Mr. O'Sullivan. Actually, it was really -- it came about when, you know, I heard about the High Winds Project. FPL invested close to $170 million in Solano County here, not too far from here, in the High Winds Project. It's a terrific facility. And given this investment and FPL's known interest in wind energy, we thought it would be an excellent idea to have him speak at the second California Wind Energy Collaborative Forum and to give us his thoughts on the future of wind energy in California, in the United States, and probably just in the world in general. So without further ado, I'd like to invite Mr. O'Sullivan to the podium. (Applause.) MR. O'SULLIVAN: I've got two goals today. One is I think I have a certain amount of time. And every time I've done something like this or similar to this, the main goal everybody usually wants is get done with this stuff and get to discussion, Q and A, theory, whatever you guys want to talk about. So if I go a little too fast, I apologize, but my main mission today is to give you this much on FPL, a little more on our view of wind, and hopefully at the end have at least that much time to discuss issues or things that are on your tongue, get our opinions and maybe just debate amongst ourselves things we've all been frustrated by or finding successful. By the looks of everybody in the room, I think that usually is pretty fair. To start things off, you know, I'm going to give a brief discussion of who FPL is and then try to spend very little time on that. But as many of you may know, we're a subsidiary of Florida Power & Light. Actually, FPL Group, there's two entities: Us, the energy company, that's the wholesale, nasty, merchant generator type entity; and then there's the utility regulated entity that serves most of south and eastern Florida. We're about a $20 billion enterprise value company, with about an $11 billion market cap and about $9 billion of debt. One thing that we're not real well-known outside of the wind business is we're the largest owners of other renewable assets. We have a little over 300 megawatts of hydro, but we also own half the SEGS facility out here in California, which I guess still holds the title for its solar facility, but someday somebody will correct me there. Why are we in wind? A lot of people ask why is FPL, from Wall Street investors to bond investors to stock investors to wind investors. We get this question a lot lately. One is it is probably the most competitive, from a wholesale market point of view, renewable technology. You know, we can produce wind energy anywhere from two to five cents depending on where we are and assuming, of course, PTC. And we'll discuss that a lot in this presentation. And especially with high gas prices kind of uplifting the market this year, we saw a lot of customers sign PPAs with us this year and last year because of gas being on the margin in a significant manner, not just in California. The other one is just public policy support. There is no -- it doesn't take a rocket scientist to figure out that in the public policy environment, both out here in California and in a dozen other states, we have an RPS type syndrome going on. And then just production tax credits which I think everyone understands pretty clearly in this room. From a shareholder point of view, we find this a very attractive business because of the long-term contracts and we can predict the revenue. We also get a lot of value in PTCs and accelerated tax depreciation at the parent level because of the taxable income that we have at the utility. We also get attractive book income earnings in the first year. And to everybody in the room, ultimately somebody answers to a capital source, and ours is our public shareholders. And the cash returns on wind are the way you and I would measure the cash coming in in two cents or four cents a kilowatt-hour at the PTC, but the book earnings are just as important to us. And Wall Street finds them very attractive. So the book earnings is the front end nature of the marriage, which is both the tax credit and the accelerated depreciation. The other thing we found this year was, as many of you may have saw in July, we made a 144(a) bond offering for numerous -- I think it was 702 megawatts, 712 megawatts. That was cross-collateralized with a 144(a) bond offering and financed with a true third party debt. What's unique about that was it was about 50-percent leverage. We also just last week put out a second tier of bonds on that same portfolio and put another 125 million of debt on there, and I'll talk about that a little later. What we feel is that that validates the business model from a Wall Street point of view. Now, you may disagree with the terms and conditions we agreed to in the bond offering. Whether you're a fan of that or you think we gave away the store, what we needed to do was test that market for the betterment of future construction that we will build or investments we will make or others may make. We needed to prove to Wall Street this is an ongoing business. Because there's a negative aura still hanging out in the investment community on what happened 10 or 20 years in the wind business, and we still are tackling that every day in our -- in our end of the industry. Then and now I think it's pretty obvious to everybody in this room in a drive through the Altamont or other parts of the state. To people from outside of California that's a little more interesting slide. This is our view of the market this year. I'll talk about this a little more as we go through. We expect just under 1600 megawatts to be built in the U.S. this year based on our intelligence. We may be off by a hundred or two hundred, but our view. And then some acquisitions we're buying. We expect to close on the Enron wind acquisitions hopefully before the end of the month or maybe in early January that we bought in the bankruptcy court a couple weeks ago. Subject to FERC approval and some other minor regulatory approval, that would get us to about 2719, which would give us about 43 percent of all the wind in the United States. We don't believe it's an agenda issue any more. We made up to about 6200 megawatts, maybe 63 or 64 this year cumulative; about 2000 megawatts of that is in California. But what it really boils down to is, you know, we get to PTC now or we get to PTC later. And the question I get asked most often from our investors or from people interested in the wind business is generally how good is next year going to be? Okay. And our view of wind for next year is pretty low. It could trend very close to a minimal amount of new wind capacity being built if that PTC doesn't get passed in the January session, early in the session in January. As you can see, the PTC has created a cyclical environment or bust cycle, if we keep getting these two-year extensions. And this year we benefitted from that. We'll have 2719 megawatts by the end of this year, assuming the closing that's projected based on 6200 and change being built total cumulatively. The last three or four years we've averaged between 50- and 55-percent market share of all the new wind that's been built, either organically developed by us or acquired. We'll be adding just under a thousand megawatts this year including acquisitions. About 811 of that was greenfield. And this is a big tag line that gets Wall Street's attention now. In the last three years, we've invested just about $2 billion of FPL in wind, just wind. And cumulatively since we entered the wind business a number of years ago, it's two and a half billion. And to us, that's a big business now, and we're taking it seriously, and this is not a business that we entered just to be in for grins or kicks. To us, we think it's a compelling strategic move from an environmental and clean energy point of view, but apparently it also is a good investment for our shareholders. A little bit about that financing. I told you a minute ago it was $380 million. We did get investment-grade -- an investment-grade rating both with Moodys and S&P. We had 34 different institutional owners buy into that debt. That's how universal and wide it was. We actually cut all those guys down in our initial applications. It's 20-year debt with a nine-year average life. It has a 6.6 percent coupon. And I think the last bullet is probably the most important one, the diversity component. We had credit diversity. We had I think 12 different customers inside of that 700 megawatts. We had credit diversity. We had regional diversity, meaning the Midwest, Southwest, California. Wind resource diversity, that's what it is, geographical diversity. And the third one was we had equipment diversity. We had Vestas equipment in there. We had in GE equipment in there. We had some old Zond equipment in there. We had everything. And standing behind both warranties and our reputation in O and M, I think we operate over 64 or 6600 megawatt -- or excuse me -- 64 or 6500 turbines we now have in the United States under FPL's ownership. And that boils down to 2700 megawatts. And a lot of those turbines are out here in California, so that grew the ratio real quick. But the bottom piece of what made the bond offering so successful, if you're a bond investor, the best you could do is 6.6 percent. There is no up side. You can only get less if the price went down, so that diversity really meant a lot to them. So what are we focused on nationally these days? The three basic ways in wind is greenfield development, which is kind of organic; that's going out and beating bushes ourselves. The second one is late stage greenfield meaning a smaller developer may have done those first three, four, six innings of development, and then we come along in the sixth inning or the ninth inning or the third inning and buy into it or buy him out based on where he is in the development pipeline. And then the last one is out and out acquisitions. And I think the Enron wind portfolio at bankrputcy is a good example of that. Last year, if you followed us closely, we bought 123 megawatts of National Windpower's assets because they were exiting the U.S. market. Where we see as it -- what makes it successful? One is you got to have the right site, just like in the real estate business. Whether you're building office buildings or shopping malls or wind parks, you've got to work with the land use in the business and the landowners. And more and more, the wind data, you've got to have solid wind data. And I'll get into that in a minute. You've got to have a PPA with the right entity at the right price. What we're seeing a lot of these days is smaller, no name guys who are good business people overpromising the wind price to the customer. There are dozens of contracts getting proposed or executed in different states, not so many in California, and they're just not getting built because somebody is going out there with incomplete wind data or they're promising a two-cent price or three-cent price. They're telling the customer what he wants to hear, and the wind data just doesn't support it or the interconnection costs or whatever needs to be done. And that's hurting all of us. That's hurting all of us. And one of the things we're deeply concerned about in the industry is keep the quality of the industry up. Because we've come through an era getting to this point in the last few years, it's now considered a legitimate wholesale business in many states, and we don't want to see it regress back to the dark cloud days when you guys were troubled both out here and in other parts of the country. One of the last most often misunderstood parts is public acceptance, especially at the local level. Obviously the PTC shows the federal support for wind, but at the local level we've found whether you're in rural South Dakota or semi-rural California or other parts of the country, if you don't have the regional folks supporting you, you're not going to get your project built. And we've spent a lot of time at this level in grass roots support. Another one is the actual topography of the site, make sure it works. I think to everybody in the room that's probably pretty obvious. Where the wind blows, as you can see by mostly the green, yellow, and gray, that's where we prefer to put wind facilities. And I think it's kind of a humorous thing that FPL is the largest wind company in the world now, not just the U.S., and we're in the lower right-hand corner of the map, and we ain't going to build a plant within a thousand miles of our corporate offices even if the PPA is eight cents a kilowatt-hour. I think it's one of those things, building where they ain't, something like that. Back to wind data. We look for established wind regions and data. We love to have lots of on-site data. And the beauty about California is most of the sites that make sense out here commercially and from a wholesale point of view have good data. And we've been very lucky on that, especially at the High Winds site. We think very good data makes for very good, informed decisions. We generally, for a new site, look for up to two years of data, on-site data with strong correlations. Some legitimate, reasonable measuring system in the nearby distance doesn't necessarily mean there's any correlation. And also having similar terrain or noncorrupted data is very important. We put the first billion into this business without being as rigorous on this last bullet than we have the last billion and a half. We now have in-house statisticians, analysts and meterologists that are dedicated to our wind decisions for new investment. It's hard to believe how unsophisticated we were ourselves when we look at ourselves and try to introspectively decide how did we get here and what can we do better for the next billion? This is the one where we probably spent the most time and money, make sure we don't miss it. Because anybody who's invested in wind, if you miss the wind by 10 percent, the quantity of wind by 10 percent, it could be the difference between a good return and a troubled project that you've got to turn the keys over to the lender. A little bit on California, and to this group this may be a little flat, but I felt if I got invited to speak out at this thing in Davis this week, we're going to talk about a little of our view of California. If you think back 20 years ago when most of the wind with the older machines put a bunch of tax emphasis, not like the PTC emphasis, but more just get it built for the tax credit depreciation, nobody cared how the plants really ran. I think they did -- the PPAs had some uplift. Generally the PPAs were not structured in a way that really did make the economic sense they do today in the production tax credit scheme. The older technologies had much lower yields. I just mentioned why on that. They were focused on availability, and to be honest they were mostly older machines. You know, the QF contracts were there for the taking. People went out and did them. You know, today we think California has a great opportunity for more wind. If you listen to SERA, which is a pretty well-known internationally, consultant-based firm, they think there's somewhere between three and 7,000 megawatts of wind just in those four or five easily identified regions in California, either through repowering or just straight out expansion. You know, we tend to agree there's a great -- there's a great up side there. Today California sits with about 2000 megawatts. Only about 300 of that, though, has been built in the last three or four years, including our large project here in Solano County. Looking down the road, I think the importance of PG&E coming out of bankruptcy soon -- hopefully. I think that's going well. I read another press release today that looked positive. Southern Cal Edison getting their investment-grade status and some of their debt back a couple of weeks ago, that all bodes well for all of us. And then the munis and the co-ops, those are our basic customers out here. And even though the High Winds projects are actual customers, specific core power marketing, the end users of all that power, they're selling it to basically the munis, co-ops and IOUs. So, at the end of the day, whether we're selling it directly or someone is selling it through a PPA, we have to be sensitive to what their needs are and what they're looking for, because they are the real market out here. The other thing I think we find in California, more so than in other states, is gas is on the margin so much, at the end of the day, more and more customers are pricing their wind decision off of what their other fossil energy alternatives are in the wholesale market. And out in California, we think as gas stays around four or five bucks per BTU delivered to the burner tip, that just provides, no pun intended, wind at the back of the wind developer for getting some energy only pricing in the three- to four- or five-cent range. It's often needed out here because of the costs and permitting. Some of the challenges and issues we see in California and not -- I don't want to spend a lot of time on this, on the negative side, but I touched on the creditworthiness of the offtakers. I think the reason I put this bullet up and I'll say it again is, often the creditworthiness of the developers is not taken into account. And that's what I mean by overpromising. We need that food chain of people in the wind development industry. We can't just all be FPL with a strong balance sheet like a parent that can write checks. We need every player in this business, because we can't be everywhere to serve every possible customer nor are we trying to be. And secondly, the small developers who need those do add a lot of value to this process because they can find sites and have relationships at the regional local levels that we never could get to. And we need to have that understanding going forward. They can't necessarily sign that PPA, you know, the utilities are looking for either. Because there's this back to back guarantee and credit requirements that goes -- it's a two-way street these days. And then most of the smaller developers are unwilling to take those risks or put up thousands of dollars in deposits and rightfully so, because that's binding on their credit structure. The biggest issue here is permitting time and money. I was joking out in the hall with a colleague a few minutes ago. And in some states I could spend a hundred grand that David or Darryl or a couple of guys here make from our team, and they have a site permitted and ready to go in weeks or months. Tens of thousands of dollars. Out in California, I don't know if you can get a driver's license that easy. You know, I don't know what the law is today. I might not even be able to get one out here. When we are competing for capital in order to place wind plants, a lot of our decision is, you know, risk, rewards, success, how quick, and what's the turnaround time to get the plant up and running. And out here we're looking at a year or two minimum and often millions of dollars. And we're finishing permitting a gas plant not too far from here, and we're going to have $5 or $10 million into that and not even put a shovel into the ground. So the cost of doing business in California is much higher than in most other states that are pro wind. And California is very pro wind. We believe that in the next seven years, if you believe SERA, and I think this is a little aggressive, but they're predicting about 2000 megawatts of new wind in the next seven years. I think that's a very optimistic graph, but I think they're basing it mostly on the RPS and the fact that wind is very economic and gas is going to stay north of four bucks. So when you mix all that in the bowl, it's not hard to get to this number and talk yourself into it. What they fail to miss is transmission interconnection and permitting cycles just don't go that quick out here or anywhere for that matter. I think the bottom bullet is probably the most important thing. As long as gas stays up, it keeps that energy only non-firm energy price in the, you know, four -- $40 a megawatt-hour, then you'll see people open and listening to wind. If we ever go back to the gas at 150, 250, you'll see a lot less interest in wind. Today the 2000 megawatts in California is spread out over nearly a hundred sites. There's several different owners; very fragmented ownership. Many of these sites generate very low electricity from a capacity point of view. And, in our opinion, it's a tremendous opportunity for repowering, expansion and just consolidation; taking a lot of old machines down and repowering essentially. But when we say 2000 megawatts of wind, with the Enron acquisition, you know, right up to almost exactly 600, which is 20 of those facilities scattered around the country, most are in part complicated partnerships as some of you have been following the Enron stuff in the last two years in the Wall Street Journal, some famous complicated partnerships that hopefully are getting cleaned up with our acquisition this week. Three of the other -- three or four of the other larger owners of 100 or 200 megawatts or thereabouts are the guys at SeaWest and Shell and Caithness. But the bottom line is, as the wind industry in this slide -- I think we're at the fourth slide -- we own about 2700 megawatts out of 62 or 6300, and the next guy only owns three or four hundred. And it's very fragmented. And what that says to us is there's a need for new capital to come into the industry, and there also may be a consolidation place. So that's what we're constantly looking for. In California is the competition for the same space as I mentioned the challenges with the permitting and cost of the land. But as we've found in other states, siting is also critical. We're thrilled to have the investment that we call High Winds down in Solano, an investment we made there I think north of $170 million. But I think a lot of it went into being responsible on an environmental basis and also a community relations basis. We wouldn't have done it just because we were willing to spend the money. The biggest thing that's coming besides transmission is offtaker credit. Going forward, we're seeing that in every state. And in California, to get back to its market share historically being almost a third or a half of the wind that was built in the country originally, today it's -- in the last three years it's only about 10 percent of the new wind has been built in California. But until the offtakers out here get their credit rating back up, it's going to be very difficult for some of us to step into those situations. So our primary focus when we go out and try to find new wind sites is to find the customer first. A lot of efforts by smaller developers and some of our competitors that are name brand entities, they go out and they may find the site first, and we seem to have a philosophical difference with some of them in that respect. We go out and find the customer first. We try to determine the size of the two- to three-year period, the timing and when they want it, but also it's competitive wholesale things. Believe it or not, we've walked from certain customers where we've not frowned -- we're not as excited about talking to certain customers, because if they need six or seven cents to make the wind work because of their poor wind regime -- we're talking mostly out of California in some of those spots -- and their wholesale price alternative for non-firm energy is two, three or four cents a kilowatt-hour, we're just looking for an unbalanced pie at some point. We prefer to be in wind situations where the creditworthiness of the guy on the edge, we're selling wind at a price that's probably competitive in that wholesale market. And that's important to us going forward. Nationally the pricing we've seen this year is between two and five cents. Most of it is now reflected in the wholesale market, not in the wind cost back into a return on investment calculation. It's both kind of converging at the same price point. We're also looking at green credits with most of our PPAs, if not all of them, with the exception of I think one small one where we basically sell a bundled product. And then going forward in the near term, especially with California's RPS getting to be such a large piece of the bundle in the next five or ten years, and some of Texas' issues, we may see that item kind of separate a little bit, and we may take a little more risk selling the green credits ourselves in the future. One test we apply to third-party financing testing, even though we've balance-sheeted two of that two and a half billion on wind, we still hold each and every customer to the same criteria a bank would. On the financial side, we look for returns on an unleveraged basis, IRR basis, I'd say the 9-, 12- or 13-percent range depending on the risk of the project. On an ROE basis, when it's leveraged, we see returns in the high teens, low 20s, depending again on the amount of debt we put on that. And then we're always looking for positive earnings per share. We don't do this unless it makes sense for our shareholders both on a cash and a book basis. And then the other thing we spend most of our time on, the financials, that probably nobody else does, is wind resource analysis. We discussed buying other people's projects this year, large, successful, well-structured PPAs, good sites, the whole bit. But we just have a different view on the wind analysis. And part of that goes probably to having a lot of experience with 2700 megawatts of other wind, so we know -- we think we know what we're doing from wind data and analyzing the actual output of these machines. But objective people have different opinions just like politicians used to, and now they seem to hate each other with a vengeance if they don't agree with each other. But in wind, if you have a 5-percent difference of opinion, that could be five or ten billion, and that could cause us to shake hands and just look for another deal. So from a financial point of view, what's really driving these deals, about half the economics is the tax credit and the depreciation. And as the PPA price is lower, that percentage kind of sneaks up to 50 percent or higher. As the PPA price is a little higher, that other number might slope down closer to 40 or 45 percent as a piece of the pie. But if you're not optimizing the tax credits, if you're not efficiently utilizing the accelerated depreciation, you're leaving money on the table. We're very interested in non-recourse financing. Now that we've proven the bond market will accept this product, we hope that tests, you know, that we have the choice of balance sheet. It might be slightly cheaper debt on our balance sheet, but at the same time we're trying to use as a diverse approach. This is an interesting photo. I don't know if any of you have seen the modern blades up close. But that is downtown Oakland, Maryland last year when we were bringing some blades through town on its way to the Mountaineer site that we have in West Virginia, to the right, in that big part of Maryland. Maryland, Pennsylvania, and West Virginia all are close. In the end, we try and have construction expertise. We do -- we generally are our general contractor on most of our own sites. We buy our turbines and towers ourselves. We arrange for the site work. We hire the electrical contract design work for the cabling and the site work on the roads ourselves. As a result, we bring timing and economies to scale. We also do most of the transmission interconnection work ourselves in the sense of design, negotiation and oversight of that by the host utility. The host utility often will do the field work or take ownership of the infrastructure. We have a team of men and women now who do only that kind of design work for wind facilities. We also bring creditworthiness, and that's very important in the post-Enron world. Customers are looking for that. They want to make certain that if they sign the contract that it will get built. So why are some projects failing? We're not seeing this in California, but we're seeing a lot of land issues out in the rural part of the Midwest. People are tying landowners up for 50, 100 or 99 years with a thousand dollar payment or a dollar payment or some token amount. And what that does is it stains everybody in the industry. It's guys going out and promising land in the $5,000 a year royalty per tower of what the market rate is, and it hurts everybody that's in the industry. Unfortunately, we've got a few bad apples that are out there doing that, and the backlash comes at us because the governors, senators and elected representatives then get ahold of our folks and say, Can you clean this up? Or are you guys doing this? And the first thing we do when we come to a rural community that's never seen wind before is to tell them, I want you to hire lawyers, land lawyers, real estate lawyers, which sounds counter-intuitive, but politically it's one of the smartest things we do. Then the second thing we do is tell them we'll reimburse them. We'll pay their costs for them if we sign a lease with them. Just like you have friends that buy local real estate or maybe the residential real estate you buy, you might save yourself 250 or 500 bucks doing your own legal review of your closing documents. But too often on these deals we're finding people in -- mostly in the Midwest where people are out there just tying up tens of thousands of acres of land, and they have no hopes of ever getting a PPA or a wind farm built. PPA structure, I alluded to this in my opening comments. We've got a lot of people out there promising pricing that just can't be achieved. Wind is not going to $800 a KW or $700 a KW installed like gas turbines went; it's not going down. It's -- you know, it's around that thousand, $1100 mark. And if anything, in our opinion, it's actually trending up not because GE or Vestas or anybody is doing a bad job on manufacturing equipment; it's just the interconnection costs, the siting issues, the land cost, everything has got a cycle to it. And there may be some inefficiency as the units get a little bigger here. We're hitting a spot where it's going to stay in that range for awhile. And then the gas turbine business, which is the parallel universal that we were in in the last ten years, people bet on that improving heat rate and that improvement dollars per KW were coming down, and it's just not going to happen, not that big of a drop. The last one I think that we see that causes it is wind data and transmission challenges. People think you can put wind anywhere, but it really depends on the local utility and your interconnection scheme. Just in closing, I guess before we get to maybe Q and A, we see our competitive advantage being our scale, but also our track record of getting quick to market. And we also believe we have a decent tax appetite, and our creditworthiness some customers are looking for these days. And we have access to efficient financial. But, again, we're not the aspirin for everybody's headache, and we don't try to be. But our goal is to keep growing the business, and we've committed to Wall Street to keep adding on average, I think, 250 to 500 megawatts of wind every year. This year was a lumpy year. '04 will probably be a reverse lumpy year in the sense that the PTC delays will bring that down a little bit. So at the end, the theme is we -- you know, we need the PTC extension. The wind industry is not ready to be on its own. We see it as a -- roughly a 800- to a 1,000-megawatt business per year on average in the United States. And if we keep grabbing a 15-percent market share of that, we'll be very happy campers. But unless we varnish the truth here, we will see that shrink on what the graph shows as a nominal amount of repowerings and things of that nature. Predominantly I think if we spend a lot of time in California, with the PTC extending into '04, there's a lot of projects, especially repowerings, that would make sense without the PTC. With that, I'd be glad to deflect -- to answer or attempt to answer any questions. (Applause.) AUDIENCE MEMBER: You mentioned permitting is one of the biggest obstacles here in California. I just imagine the other developers feel the same. Could you highlight what needs to change to expedite the permitting process. Could you just highlight the obstacles or barriers as far as that -- MR. O'SULLIVAN: Well, let's ask the guy who permited in Solano. MR. HERRICK: CEQA? That would be a -- that cost us a little over a million dollars and 12 to 14 months of time. And I'll get into that a little bit in my presentation. But out of the permitting cycle, that was roughly 17 months. The CEQA process was over a year. MR. O'SULLIVAN: I think generically, if I could extend that answer, the biggest enemy to a developer, whether they're building malls or office buildings or wind parks, is time. And an investor that's Wall Street sensitive is more worried about things going wrong. And as you extend that 12, 18, 24 months, rules can change, laws can -- PTCs can expire, things can just go wrong. And the biggest risk we try to hedge is time. But unfortunately for our product on Wall Street you can't go buy that much time, so that's the development or venture capital risk you're taking in this business. The flip side of that is it causes your price to go higher and higher to recover that risk. And when that dynamic starts getting -- and that's why you haven't seen a lot more development in my opinion. I should say, in my opinion, we haven't seen more wind development in California in the last three or four years is the credit risk of the offtakers caused us all to think we needed to deliver a penny or two a kilowatt-hour. I'm exaggerating to make a point, not far from what we want. At that price clearing point, those utilities or those entities won't really matter. It was too rich, too expensive. So the risk of permitting time eventually gets back to the pricing decision. It's not likely we're going to see it go away. We certainly are aware of the environmental impacts, and we study them. We just need the process to be a lot more efficient and expedient. And it goes back to what Mike said about time as a reasonable manner. AUDIENCE MEMBER: You talked about gas prices several times and the fact that there's now a new terminal being built in Mexico that's supplying some gas in California. Does that give you any comfort to say they're putting it in, that means that gas is going to be a certain point? Or is that maybe some cause for concern to say that it's -- you know, the supply of gas is -- [unitelligible]. MR. O'SULLIVAN: I see your glass half full side. I would tend to acknowledge there's going to be competent gas levels for -- that's high enough. These guys, the L and G guys, their capital requirements and rates of return make us look like treasury bill salesman. AUDIENCE MEMBER: Okay. MR. O'SULLIVAN: These guys that invest in L and G, they're not at it for wind returns. As attractive as this stuff looks to a utility investor, you know, a couple hundred base points better, avoid taking risk motivates the rest of the cooperative where there's no rate of guarantee. The L and G guys are looking for returns. So, you know, if you generally subscribe to L and G needing a $3.00 or pick a number, $3.00, $3.50, $2.50, depending on the [unintelligible] three cents coming from it, that does feed into the $3.50, $4.00 delivered price by the time you stack in all the surcharges or interstate charges and then gets you to pick a heat rate, 7,000, 8,000, gets you to $30 or $40 megawatt-hour variable cost. Which I think if you're building decent-sized wind farms in California, you know, my guess is if you're in the mid to low 30's like David or Darryl here, capacity factor, you know, if you're in the 32-, 34-percent capacity factor, you probably need energy -- well, you know, a PPA price in the $35 to $40 a megawatt-hour, you know, range, non-firm, no crazy credit issues. So I guess, yes, that would give me some comfort. AUDIENCE MEMBER: What effect did the PG&E bankruptcy have on -- MR. O'SULLIVAN: His question was, what effect does the PG&E bankruptcy have on issues or existing agreements? I think it had more effect two or three years ago when they first filed. Today they've been honoring all the payments and agreements that we've had in place. We've had our nervous moments, but I think that's more historical going back months or years. We're optimistic they'll come out. We're optimistic when they do come out of it, they'll look at renewables and wind in general in a different light than they have in the last few years. And whether that's new contracts or repowering RPs, we're hopeful that -- under the state law out here it's 2017 or something, 2017, whatever the numbers are -- that they will be one of our, you know, bigger customers going forward in California. AUDIENCE MEMBER: [Unintelligible] in PG&E? MR. O'SULLIVAN: Have we lost any money in PG&E? And my answer is, not to my knowledge. AUDIENCE MEMBER: Has FPL developed a model program for repowering? MR. O'SULLIVAN: A model program? AUDIENCE MEMBER: A model program for repowering. MR. O'SULLIVAN: You mean taking existing sites and repowering them? Oh, we have a financial analysis or model and style or approach, but I don't think -- it's not a canned program or anything where we just dump it into the software package, if that's what you're asking me. Or am I misinterpreting -- AUDIENCE MEMBER: I think so. I think what I'm asking is, have you taken an old wind plant and brought in new equipment -- MR. O'SULLIVAN: We're in the process of doing that right now in California. Smaller scale, nothing like High Winds. But the challenges there are the same, permitting issues and time issues that I was just discussing with that gentleman a minute ago. But at the same time, you've got local land use constraints that maybe were designed or permitted for older machines 20 years ago that you got to go in there and get kind of changed. And then just the time factor. But we are looking at smaller ones. Our approach is to look at some smaller opportunities that we hope to do in '04, and the theory is, let's walk before we run. You know, let's do some 20-, 40-, 80-megawatt repowerings before we're doing 200 where we're getting a -- investing a lot more capital and time. AUDIENCE MEMBER: Can you use the cables? MR. O'SULLIVAN: Depends. Probably not, but depends. Depends on the technology you're putting in. Sir. AUDIENCE MEMBER: Given the problems cited with small developers overpromising pricing buys, can you provide any advice to small developers in terms of the timing and ways of getting involved with FPL or another [unintelligible] player to make sure that that price is right? MR. O'SULLIVAN: I think the first myth I want to dispell is we're not the answer to everybody's headache. We don't have the perfect model or solution or anything. I mean, I know in a lot of this stuff we might be the biggest, but we make as many mistakes as everybody else; we just hide them better. I don't know. Second, the little guy is necessary, because you can knock on far more doors closer to your home base than we can. You know, we've got a talented team back in Florida. Going back to the map, we're in the lower right. They can only get so many places. We lose a lot of time in the air. And I think it's the wind data. I think if people invest more time, and we get better and more access to the professionals that can analyze the wind data, we'll have less mistakes on the pricing decision. There are a handful of experts or consultants. I think they all work for us in some shape, manner or form, it seems. And that is why we're developing the in-house talent. We can't rely on this guy who's the outside consultant that has no money in the game, gets paid up front generally, doesn't have his salary at risk like the rest of us do if we make a bungled investment. If I -- if I had to do two things for the small guy, I'd say spend the money up front on wind data, and then spend the money up front on interconnection or transmission studies. Those are the two things that are expensive, tens of thousands of dollars, a hundred grand maybe for the two combined. The preliminary stage doesn't guarantee you've got a deal, but that's where we spend our money when we're greenfielding stuff now. I'd rather spend it there and walk from it then find out a year later, a million and a half dollars, there's a fatal flaw in it. AUDIENCE MEMBER: [Unintelligible]. MR. O'SULLIVAN: Yes. AUDIENCE MEMBER: [Unintelligible]-- wind data on that? MR. O'SULLIVAN: Yeah. When we approach a customer, do we approach -- the question was, do we approach a utility first with the land already under control? Often not. Now, we're going in under reputation probably. Okay. But we also have preliminary wind data or a year or two's worth of data. We won't make an investment decision unless we have a year or two of data, and our preference is going up. As we build more of these, we're realizing the statistical analysis is more robust if you have more data. We're probably leaning towards beyond two years, toward four years. Still the lull of PTC delays is not upsetting us because it's that much more wind data that's getting collected on all the sites. So we'll make a better investment decision in late '04, early '05. When we go talk to a customer -- and this is more in the Midwest when we do this, you know, in the central part of the -- maybe in the green and yellow ones on that map. We haven't had trouble getting land yet. And, you know, our thinking is land is easier to find once you have the siting. But you've got to have the wind data and a few met towers up on some land. But what we often do is we'll have met towers out -- we have many of them out around the country. We'll tie up those immediate landowners near the tower, not nearly enough to site a hundred megawatts or whatever you're trying to site. And then we'll go out quietly and think we got a PPA and tie up a ton of landowners. And then we do two things: We won't promise them all the deal until -- because what they don't -- almost in every -- I shouldn't say every. Some landowners want to get a cartel. They need us more -- excuse me. We need them more than they need us. And what they don't realize is we go get -- if we only need five, we go get fifteen. So if five or seven get a little smart, too smart, you know, we go to the other seven. So -- and the other thing is we try to spread it out. We intentionally try not to make one wealthy landowner in rural pick a state. Not good for community relations. One guy's getting all those royalty payments for the tower on his land. It's the best thing you've ever seen in dedication ceremonies -- we've seen dozens of these now -- is to watch 10, 12, 7 sets of families or landowners come to that ribbon cutting and thank the governor and thank the senator. And eventually they thank us, because the check doesn't bounce. But they are happy folks, and it's good for the community, both the property taxes and the royalty revenue. But we like -- it's the only socialist part of our capitalistic company that I subscribe to. I like to see the money get spread around just for that reason. It keeps the community happy instead of just one or two families looking like they hit the Lotto. That's not good for the community relations in our opinion. Sir. AUDIENCE MEMBER: [Unintelligible]. MR. O'SULLIVAN: We're very bull shy. We were very disappointed in late November when it fell apart. We are told that that was not the problem, as the popular press reported it. It was one or two other issues. For those of you that are Republicans in the room, or Democrats, I think everyone was disappointed from a wind point of view. And, you know, the Republicans probably packed a little too much stuff, you know. But both sides of the aisle agree that everything in the wind package, both the tax credits and some of the other what I call secondary wind issues that are hidden in different parts of the 1200 pages that are important, we're not contentious that any Congressmen had any back room, you know, argument. It seems to be something that will happen. It's just a matter of us getting it attached to the right -- like we had a few years ago, getting it attached to the right document that's coming out and getting it to come out of Congress in a timely way. AUDIENCE MEMBER: We heard some things about some of those NP rate [unintelligible] investment. MR. O'SULLIVAN: Well, to certain corporate players, which we'll keep nameless, at some point if you build enough wind, you hit TMT or AMT. All of us as individuals worry about AMT, right? At some point in life, if you make a lot of money, they're warning us from the front page of the paper that 90 percent of us are going to pay this in the next five years, whatever. The corporate equivalent is the tentative minimum tax. And some of the tax language in the energy bill, looking down the road, if you get big enough in wind, you're eventually -- no matter how big your corporation, if your taxable income growing in wind is fast enough to cross this line where you no long -- you can't utilize that tax credit as efficiently as you could if -- I think it's a 20-percent marginal tax rate minimum. You know, our corporate federal tax rate is like 35 percent, and we get the PTCs credited against that. But if we had too many PTCs someday, we would hit the ceiling or the floor depending on your perspective, whether you're the government or us, at 20 percent. And our -- our commitment is if we're putting this capital in up front, making these investment decisions up front, and we're taking the risks to get the tax credit, we should get that tax credit wholly if we make the investment. So it helps not just us, but a couple other players in the industry. MR. VAN DAM: I hate to do this, but I think we have to move on. So I would like to thank Michael O'Sullivan for an excellent talk and a very informative Q and A. Thanks very much, Michael. (Applause.) MR. VAN DAM: Just before we move on, a couple of -- a little more information about the forum and the way we got our information. You see that we have -- all the preparation material will be on line, you know, in the coming weeks. But secondly, we also will be getting all the text on line. And for that, we have someone here transcribing all the -- everything that is said here today and tomorrow. So that's the good news, but that's -- the bad news is that we all have to speak up as a result. And if you say something, if you question -- if you have a question for one of the speakers, please speak up so that we can record it. And it is -- I think in the long run it will be very useful for all of us to have that information. And, again, it will be downloadable from our web site in just -- in the coming weeks when all this information is coming back to -- coming together. So I'd like you to be aware of that. So the remainder of the afternoon, we have two more panels. The first panel is really focusing on the increasing wind penetration in California. And we have a couple speakers, but I'd like to introduce the moderator, and her name is Nancy Rader. And I think many of you know Nancy very well. She is the executive director of the California Wind Energy Association. And without further adieu, I give Nancy the podium. MS. RADER: Thank you very much, Case. It's nice to be back here at Davis, my alma mater. This building didn't exist when I was here. Before I introduce the panel, I just want to take this opportunity at the mike to say what a pleasure it is, then, to get to know the folks here at the Wind Energy Collaborative, Case Van Dam, Henry Shiu and Kevin Jackson this past year, in conjunction with their management and helping to conduct the RPS inter-operation study in the next panel. It just has been terrific to helping us tackle some of the issues that are facing the wind industry. So I just wanted to say thanks to U.C. Davis for hosting the Wind Collaborative and thanks to the Energy Commission for helping to fund it. Our first speaker this afternoon is Dave Herrick, also from FPL Energy. Mr. Herrick has been involved with renewable energy for over 25 years, joining FPL Energy in 1995. He now serves as director of wind development. While with FPL, Mr. Herrick has been involved with the development of 11 wind projects in Texas, Wisconsin, California and Pennsylvania. He's going to talk to us today about development of the High Winds Project just down the road in Solano County. Dave. MR. HERRICK: Thank you, Nancy. Welcome. Thanks for the opportunity to speak to you today. I think Mike gave you a pretty good idea of FPL and its goals and its objectives in the wind industry. I'm here to give you a little bit of background on a specific project, and that is the High Winds Project that is pretty close by to here. And, Case, the clicker. As Mike mentioned, the High Winds Project is located about 50 miles from here, near the town of Fairfield. It's presently the largest wind energy facility in the state of California that is also owned and operated by FPL. And also, just pretty quickly, as Mike was pretty thorough, but we've got 37 wind facilities in 14 states and over 2700 megawatts of generation capacity. This is just a quick map as to, again, the general location of High Winds. It's physically in the town of Birds Landing, but that's a fairly small place if folks haven't been out there. So Fairfield and Rio Vista is usually the closest geographic references. But as you can see, it's fairly close to the Sacramento River Delta and gets the winds that come up the Delta. Any of you folks who wind surf know that that area is pretty windy. The project was constructed in two what turned out to be essentially consecutive phases. The first phase was 145.8 megawatts or 81 Vestas 1.8 generators. The second phase followed along closely thereafter, which was another 16 megawatts, nine additional turbines. That all came to pass due to the availability of some additional land that became available later on in the process once we'd already started the project. So while we had things going, we were able to secure the land and construct a larger project for the state. The project sits on about 6500 acres of land but utilizes only about one percent of that, a little less than one percent of that. 60 acres is actually the footprint of the project. Therefore, the lion's share of this land is still fully usable for existing or previous uses, which was grazing and farmland. Just a little detail on the turbines themselves. As I said, these are Vestas V80's. These are not anywhere near like the wind machines that you see in the Altamont. These are of a whole different scale. They're 1.8 megawatts each in output. They've got an 80-meter rotor diameter, and they're mounted on the top of 60-meter tall tubular steel towers. And as anybody who has climbed one of them knows, that's a healthy heighth. It's a grand total of about 100 meters to the top of the blade from the ground, a little over the length of a football field vertically. So these are quite large, industrial size machines. And as Mike said, you know, this is a legitimate high-dollar business these days, and just buying several of those is testimony. A little bit more on the specifics of the turbines, then the cells, which is the, for those who may not know, rectangular-shaped object on the top of the tower which contains all the gear box and the generator and the mechanics that the blade -- that the rotor attaches to. They each weigh 125 tons. Each segment of blade is a little over seven tons, and the towers, all three -- they're three-section towers -- are 125 tons. The foundations for these are excavated using a 15-foot diameter auger. You can see a picture of that to the right. It's a pretty impressive piece of equipment. The foundations all range from 30 to 45 feet in depth and contain about 50 yards of concrete and a little over nine tons of steel each. They're actually designed as an -- as an annulus. There's a -- the concrete is essentially the ring, and there's compacted material in the middle. So it's like a long donut if you will. Project roads. There are about 23 and a half miles of roads that interconnect all the turbines and about 21 miles of 34.5 KV buried interconnection cable that take the output from each of the turbines to the project substation. The project substation is located immediately adjacent to a PG&E 230 KV line where the power is stepped up and then directly connected into that system. Project benefits. Obviously, clean -- clean, renewable, no emissions energy, enough to serve about 75,000 homes. I thought this was an interesting table. These are the offset emissions that, were this project energy to be generated by more conventional fossil fuel sources, using an average U.S. -- a mix of the average U.S. portfolio, which is the bottom line there, it offsets about 365,000 tons per year of carbon dioxide, almost 2000 tons a year of sulfur dioxide, and a little over 1100 tons a year of nitrous oxide, NOX. And this is based on some old data, '97 data that may be updated, but it gives you an idea. Some of the other benefits of the project. We're local in nature. There are about 250 construction related jobs created here. Most of them were filled using local union residents. Projects can pay, over the course of its life, about $24 million in property taxes and about 21 and a half million dollars in land lease payments to the landowners. So it's a good economic impact to Solano County, and hopefully they are as happy to have us as we are to be here. This project has been around for awhile. And as Mike had spoken of earlier, the PG&E bankruptcy, the California energy crisis and the Enron collapse all sort of delayed its construction. Once those things tended to at least see that they were on the road to being sorted out, things progressed for this project. A little bit on the schedule. As I mentioned before in answer to a question, our permitting schedule was roughly 17 months starting in roughly May of '01 and ending in September of '02. The EIR was prepared pursuant to CEQA requirements. We had a draft of that completed in June of '02, and the remaining time was used in securing our land use permit from Solano County. Obviously the prime document there was the EIR. Contrary to the permitting schedule, the construction schedule moves a lot faster. Phase I was started in October after the receipt of the conditional use permit with the County. We had roads put in through December; foundation started in January of this year and finished up in March. And the turbines were under erection in -- from February through July. We finished up with Phase I about -- the third week of July, I think, all those turbines were up in commission. As I said before, Phase II followed pretty much thereafter. Obviously we had a lot of common infrastructure. We used the same substation, and the collection system was all designed to handle it. So this is -- these were pretty much, if you will, a plug and play type of deal. We started the roads in August, we did the foundations in September, and the turbines are actually all up now. All nine are mechanically complete. My last information is five of them are fully commissioned, and the other four will be within the next week or two. And that's sort of the nuts and bolts of High Winds. If anybody's got any questions, I'd be happy to answer them. MS. RADER: We'll take the questions at the end of this panel. MR. HERRICK: Okay. (Applause.) MS. RADER: Our next speaker is Bob Gates, senior vice president of business development for GE Wind Energy, where he heads up sales for the Americas for GE. He's -- I knew Bob, met -- first met Bob in 1989 when I got involved, but he's been involved since early 1980. And he's served as president of Zond Wind Development and then Enron Wind Development, the predecessor to GE Wind. He is a member of the board of directors of the American Wind Energy Association and a past president of AWEA. He is based in Tehachapi, California. Bob. MR. GATES: Thank you and good afternoon. I'd like to talk about some advances in turbine technology, megawatt size technology that GE and its predecessors have been making. But I'd like to put that in the context of economics of wind energy, because I think by putting it in that context, it will make a little more sense. And on short notice, that was the best that I could do. We've said that wind has been growing pretty quickly, and that's because -- one reason is in the factory floors we have free coffee, and everybody is required to drink a lot of it. And we use the same protocol out in the field. FPL hasn't discovered the super Starbucks method of getting turbines built quickly. But FPL is a great company, and they'll catch on quickly. Seriously, folks. Wind energy has come a long way, as we said. How do I advance this thing? It's probably just push the button, right? Wind's come a long way, and we believe primarily because of the improving economics which are attributable in large part to technical innovation. I'd like to, as I said, frame this in the economics of wind and go through the four drivers that we see of wind economics and focus more than on the others on wind technology. We'll talk about wind energy cost of energy in a simplified form, where the cost of energy, COE, is equal to the recovery of capital plus annual operating cost divided by the amount of electricity. It's a simplified method, and we have some simplifying assumptions in there, and further on today we'll see some models of this. Let's talk about the first driver, as mentioned earlier, was that wind is really important. And it is the energy that's in the wind there, the cube of the wind speed. And so the siting and the wind and being sure of the wind is critically important. The most productive sites have high wind speeds, as you'd assume. A normal site, a normal very windy site will have the capacity factor of about 30 to 35 percent. Those not familiar with the capacity factor, it's what percentage of the full output all year will the project site average? 30, 35 percent would be Eastern U.S., Pacific Northwest kind of a site. The high end of capacity factors would be 40, 45 percent. That might be Hawaii and in the trade winds, on some of the mountain passes that were developed in California back in the 1980s, and we think many of the offshore sites. Let's talk about the turbine technology as the next driver. Whoops. I'm going the wrong way. (Brief interruption in presentation.) MR. GATES: Okay. The cost of wind energy has been reduced over the years through -- primarily through economies of scale, larger turbines and larger project size. Larger turbines have been enabled with technological advances. And the reason that the economies of scale affect the turbine that way is the energy that the wind turbine can make is by slowing down air molecules. And the air that it slows down is a property of the rotor diameter, right? So if you increase the size of the rotor, you pick up area on R squared, and it's the area, pi R squared. So if you make the rotor bigger, you pick up area or energy as the square. But if you can make the cost go up linear, because it's a longer blade, the differential between the square and the linear is the savings that has come with economies of scale. The tough part has been to make the turbines reliable while holding the cost increase to only linear, and that has been the challenge in materials and design and intelligence and intelligent control and so on. A couple of technological advances made this possible. One is variable speed constant frequency. We've described that. That has a couple of benefits, reducing loads and integrating into the grid. Next. As an example, from the early 1980s to now, turbines don't pay attention so much to the numbers because, depending on the assumptions, you can change them around. But the big thing is on the bottom, the costs have gone up, you know, like 50 times the power output for 10 times the cost. That's the square versus the linear relationship to cost. So that's the main reason that wind energy costs have come down over the years. Next. And this is cost of wind energy over the last 20 years, and you can see it's come down. The other thing you can see is that the curve is flatening out as mentioned earlier. We don't see -- we don't see a big drop in the cost of energy. There can be some marginal improvements, but we think they come as a result of economies of scale in the volume of the production of wind turbines. If you make a hundred units a year, it will cost less. If you make a thousand units, it will cost some percentage of X. Next. Here we talk about the technological advances, the variable speed constant frequency, VAR control and low voltage ride-thru. Three of them, we'll take them in that order. Next. Variable speed constant frequency. This is a key cost-reducing technology. On the little graph in the lower right-hand side, there are two lines, a black line and a blue line. The black line is the torque that the drive train in the wind turbine sees as it's operating in the wind. The wind speeds a signal to us, a microsecond investment factor is actually quite variable up and down. When you design the wind turbine, you have to design for fatigue endurance at the top of the black lines, because that's the torque the thing will see. So you have to design the machine and, therefore, the cost to meet the top of the black line. If you can electronically limit the torque, which is the green -- the blue line in the middle, then you only have to design to the top of the blue line. And that differential is a cost savings or, for the same cost, greater reliability that you can get from variable speed. The way variable speed works is when there is a gust like the top of the black line, that energy is stored by the wind turbine by accelerating the mass of the rotor. The previous speaker talked about the blades weighing, you know, 10 to 20,000 pounds apiece. You've got a 50- or 60,000-pound flywheel. It can absorb that energy by speeding up slightly. And then on the down side, on the bottom of the black line, when there's less wind energy, the electronics can pull that extra energy out of the flywheel essentially and give you a level output, which is the blue line. It's really simple. The technology to do it didn't exist 20 years ago. It's gigantic, the switch, but that's a key. And the other key improvement this gives you is it allows the turbine to intelligently set its own RPM. So that it will say the wind is X, go to -- look on the table and say the optimal RPM is Y, and it sets itself to that speed. It's converting to make variable frequency output. It has a power converter that converts that power to constant frequency to integrate with the grid. It's really slick. Next. It lowers the cost, increases your output, which we talked about. Next. The next one is VAR control. VAR is volts amps reactive. In the electric system, you have two things: Real power and I call it make believe power, but that's not what the engineers call it. AUDIENCE MEMBER: Active power. MR. GATES: The active power, thank you. And your typical older style wind turbine consumes VARs that lower -- that can vary the voltage on the system. One of the characteristics of wind is that, by its nature, it's sort of remote. And since the electric system in the United States began in the cities and worked its way to the hinder winds where wind is, the electric system that the wind projects go into are almost by definition weak. And so its voltage excursions are not very stable. By having the wind turbines able to vary the VAR output, it can -- it can support actually the voltage of the electric system, so that with this variable speed or VAR technology, the grid becomes more stable after the wind plant is in than before it was in. It stablizes weak grids, and, of course, then you can put in way more wind energy at a given good wind site than you could without it. And as mentioned before, the interconnect is one of the key drivers on can you actually make a wind project. Next. With the short time, we won't go through this grid, the engineering here. But it's in the thing if anybody wants to get the presentation to look at it. Next. It's a cheaper system. You can do this VAR control with switching capacitors and other kinds of technology. By using the new wind technology, it's all solid state, and it's way, way, way less expensive. So you can get the benefit for less cost, and, as mentiond before, cost is a big issue. You can see the graphs. You can control the voltage. You can control the voltage of each turbine by sensing the voltage on the utility line and sending commands out into the wind project to vary actually the relationship between the current and the voltage, to correct and bring the -- to keep the voltage on the utility system within a range that can be dispatched by the utility. So they can say, gee, we need more VARs, we need to consume VARs, whatever it is, and the utility can send a signal to the wind project and have it act as a VAR generator or a VAR consumer. Go ahead. Very clean voltage on the host. The host voltage bus, you probably picked that up already. Right? Next. Why don't we go through these things kind of quickly. Self contained -- not that quickly. Integrate -- whoops. Self contained. It's small. Go ahead. Integrate a lot into the system. Go ahead. Let's talk about the next one, low voltage ride-thru. As mentioned before, the projects are getting bigger. That's part of the economies of scale. One of the things that is changing in the wind industry, as wind moves from being sort of a neat and nice interesting thing to being part of the utility system, is the utilities begin to depend on the energy. Wind turbines are designed so that if there's a fault in the electric system in the grid, they'll disconnect -- the turbines will disconnect themselves so that they don't get damaged, say, by low voltage. Well, as you scale up wind, that turns into a problem because what the utility doesn't want is if you have 100, 150, 200 megawatts coming from wind, and there's a blip on their system, they can't lose that generation. So we had to change the nature of the protection of the wind turbines from disconnect on any kind of a voltage -- undervoltage situation to protect the turbines to do something more difficult, ride-thru and stay connected during the low voltage event so that the whole utility system doesn't suddenly lose a hundred megawatts. That's, like, a big amount of power. So this is a very important thing, kind of becoming critical as wind gets to be mainstream as opposed to an interesting thing that doesn't matter all that much in the electric sense. Next. Two graphs, and the long and short of it is, it used to be that wind turbines, if you went for, say, 100 percent, 101.0 is nominal voltage. If the voltage went down to 70 or 80 percent of nominal, the whole system would disconnect. The whole wind system would disconnect. And what we needed to do is get that down to 30 percent. It's a big, big, big increase that can -- and that's some of the newer technology that is allowing -- next slide -- allowing bigger wind to go onto the electric system and still have electric system reliability. And bigger wind projects gives you the economies of scale, which gives you lower cost, which gives you a bigger market, and it's sort of a self-fulfilling circuit. Getting bigger grid reliability. Go ahead. Uninterruptible service we talked about. And the transmission planning, which is a big factor. As mentioned before, the interconnect is a very important thing. And if the operating utility has a fear that wind can disrupt service, that can't happen, so it has to improve service. Go ahead. Next. Fault ride-thru. Well, there's the advertising for GE Wind on the bottom. They're good neighbors to the grid. The low voltage. You know, I think over time most wind turbines will have the same kind of capability. You just have to have it to be large and be in the integrated system. Next. Okay. Let's do the next one. Let's do the next. Then we continue with the economics of wind. Quickly running through, we went through the technical advances that allowed wind to take a bigger piece of the grid and to operate more efficiently, therefore, being bigger both economies of scale factors and to bring the cost down. Let's go to capital costs, run through that quickly. As mentioned before, about a million dollars of megawatts, actually a little bit more than a million, divide in your head -- or at least I can -- 70 percent of that is the wind turbine; others are the other costs. Next. Power savings, as mentioned, two and a half to four and a half percent production tax credit, accelerated depreciation. Next. That's old news. Long-term debt and equity. There we're 50/50, 60/40, something like that is about what it runs. Go ahead. Long-term debt gives you lower annual costs. Just like a home mortgage, like a 30-year mortgage is lower than a 15-year mortgage, although you wind up paying more interest. With a long-term PPA, you can generally get that at about 140-percent debt coverage ratio. That means the cash flow out of the project, after it pays its operating expenses, should be about 140 percent of the payment on the debt. So you work that backwards, and that gives you a principal amount which typically comes out around 60 percent. Next. The returns to equity. Wind projects, low teens. Earlier FPL described 9 to 13 percent. That probably is about the range. To give you a comparison of what that world is like, a housing kind of a project will give you high single digits, 8, 9 percent. Venture capital, it's, you know, 30 to 3,000 percent, or zero if the deal doesn't work out. Go ahead. Equity. You get a 50-percent bonus depreciation during '04. Go ahead. A lot of this has been covered. This is a typical finance structure for an individual project financing. We have the property debt and equity coming in. The parent company is getting the tax benefit coming in. This has a double loan structure with a PTC loan as well as a senior debt loan. We don't have to go through the whole thing. Next. Other costs are O and M, warranty, local taxes, land use payments, and power delivery costs. So an example of a calculation would be 37-percent capacity factor, 1.1 million total installed price, $45,000 per megawatt per year on O and M. These are all kinds of average figures. So, again, the object is not the exact figure but just to get a feel for it. And the production tax credit we have as one cent. But if you take it to 1.8 cents, that escalates over ten years and you levelize it over a 20-year lifetime, you get about a cent. Next. We'll go through the cost of energy math. Capital cost recovery when using a 10 percent per year as the simplifying assumption for capital cost recovery. If you run through all of the math, you get 4.78 cents or 47.8 dollars per megawatt-hour. If you subtract the one cent, you get 3.78. That's sort of an average figure, about four cents as the cost of wind energy today. Go ahead. Wind energy market. This is relative to new options for renewables primarily. And as mentiond before, wind is the most cost effective renewable where it's windy. It wouldn't be in Florida. It's a little bit more. And what I think is interesting, on the far right side of the graph, you can see wind over on the left and coal, combined cycle combustion turbines, nuclear and wind about the same. So when we say wind is becoming pretty much cost effective, that's what we mean versus new, newly installed capacity. Go ahead. Other values mentioned earlier, tax credit, maybe a green value, maybe a regulatory compliance value if there's an RPS and so on. Go ahead. So in summary, economics of wind. Pretty reliable because turbines are reliable. Wind is statistically predictable if you have adequate data. No fuel cost risk. It's competitive today. And technological developments. We probably can't take much more out of the cost, although economies of scale and volume probably can take another layer, but not a lot. Thank you. (Applause.) MS. RADER: Our next speaker is David Hawkins, who has recently arrived. However, he didn't provide me with a bio, so I'm going to wing it and just tell you what I know about Dave. I also need to stall, because Henry needs to put in his presentation. I know Dave as the guy who helps us figure out how we're going to integrate wind into the system and how to adopt Cal ISO rules to work for wind energy. So I first met Dave when we were hashing out what became Amendment 42 to the ISO tariff, which is the new forecasting and scheduling program for wind energy. More recently he's worked with folks here at Davis and others who you'll hear about in the next panel on the wind integration and other renewable integration studies for the RPS. So if you're ready to do a little stalling, Dave, I'll let you on. MR. HAWKINS: Thank you, Nancy. I'm going to talk today about what we're doing to increase the amount of wind generation in the grid and things we're trying to do to open up the market rules or make things less risky and more friendly, I guess, to have wind generation participate in the Cal ISO market. The first thing, of course, is that what we really want to do is to try to get the wind and all energy scheduled into either day-ahead markets or hour-ahead markets. If you can schedule into forward markets, then you can find a way to get all the energy lines up against load, and, you know, then you get the most benefit of all. If wind just shows up in real time, then, of course, then you have to displace other generators, and you already have other generators you've started up, gas turbines or whatever. And so, you know, if you really want to get the advantage of having a renewable resource, you want to get there early enough with the wind and forecast that it's coming so, therefore, you don't have to start the other type of fossil fuel units. In reality, all generators will deviate some from the actual schedule, and load deviates from schedule. There's never going to be a perfect hour-ahead, minute-ahead schedule that adds up. So there's always some deviation. And the issue, then, is how do you deal with the changes in actuals from the actual scheduled energy and how do you lower the cost of the scheduling corregators so you don't incur a major penalty for the fact that wind will obviously vary. (Brief interruption in presentation.) MR. HAWKINS: Okay. This is an example of what it looks like on a typical day where you're seeing that -- like in the early morning hours, often you'll see that the actual load itself, which is the heavy black line, is lower than the actual schedule. So we end up with an overgeneration condition and overscheduling so that we have to end up with what we call decking a lot of units in order to make room for or to actually balance the system. And then you can see during peak load in the afternoon or into the early evening this time of year, of course, we have a big peak that comes on about five to seven o'clock at night. This is where we have an overscheduling condition -- or underscheduling, excuse me, and more energy needs to be produced. You want to do the -- move forward. Thanks. One of the interesting things we've been trying to do lately is come up with how you measure the quality of control for a control area operator like the ISO. And one of the things we look at is, what is our interchange error, what is the frequency error, and what does the time error look like on the system? And if you put all those together and say each is about somewhere around 30 percent or 33 percent of your overall quality, the ideal thing, of course, is to be at 100 percent which you can see at the top. It's this point there [indicating]. So the ideal thing is to be up there. And you can see there are certain periods where things don't go as planned. And so as you look at the frequency numbers and the base numbers across the bottom, you can see that we get some major deviations as we go along during the day. And, of course, we will do a -- every four seconds we rebalance the system and send out control signals and dispatch signals to rebalance everything. So as a control area operator, these are the kinds of issues that we're dealing with all the time. And then the question is, okay, with renewable resources coming in, how can you fit those into this kind of a model and still control the system successfully? I'm sure -- Nancy, I missed your talk. You didn't talk about the fact that we have this new portfolio starting. And so what we're looking at is all renewables coming into -- becoming a large part of the overall energy mix in the state, about up to 20 percent by 2017, which is a major increase. So we're expecting probably wind generations which are currently at about 2000 megawatts or a little more to probably go to 44,000 megawatts or more in the near future. So the question is, that's going to make a major impact on controlling the system and making sure that we can forecast what it's going to do and how we integrate it. Our numbers in California, of course, are, as we said, 2000 or 2100 megawatts approximately now for some of the wind generation. And you can see, we certainly are the leaders in the country. Texas is coming along. And, of course, the Midwest now is growing in terms of the amount of wind generation. New England is probably one of the toughest ones to put in because, of course, land is somewhat scarce there and having the right sites in New England is going to be a challenge. But the Midwest looks good. In California, these are some of the local areas that we have that are very productive for wind. And, of course, the new one in Solano County is a major producer now of wind generation. More units are going up. That has been, from what we've seen now, quite successful. Next. One of the interesting arguments we always get is that people will say, gee, all the wind energy comes out at night, the wind blows at night, and we don't have anything that goes across the peak at four o'clock in the afternoon, and, therefore, will totally discount wind because it doesn't show up when the load shows up. And so what I was trying to show with this slide is that that's not exactly true. So if you do the cutoff at 8:00 p.m. to 8:00 a.m. and do the 8:00 a.m. to 8:00 p.m. type of slice, what you can see is we do get a considerable amount of wind energy production during the day as well as we get a considerable amount at night. pAnd also you can see what the wind variability is throughout the year. So as we get to the April and May periods, those are very heavy production months, and into June. And, of course, we see a drop off at this time of the year as we go into -- although when a winter storm is coming through, you will certainly get some major production during certain days through this period. But, of course, the big thing that you get in the summertime is a cold San Francisco at 55 degrees and a hot valley at a hundred and some degrees. And so it's that temperature differential that really makes a pretty good wind blowing through Tehachapi and through the Altamont Pass and other areas. So we get some pretty good wind production in the summertime. So, anyway, when people tell you there's no production at four o'clock, it depends on the particular wind farm area as to how true that actually is. But overall, if you look at the averages, certainly the averages at least support that there is pretty good production at least during the day. Our overall project objective at the ISO was to basically support the State's goal of increasing the amount of generation in the state. And in order to do that, we needed to do a better job of forecasting what wind production was going to look like, so that when the general -- the general dispatcher is going to see this thing, it's no surprise. Dispatchers hate surprises. They hate surprises when generators trip off, when units just show up, and when unexpected things happen on the system. So in order to be successful, we need to make sure that we take as many surprises and risks out of this as possible. And then, of course, we need to allocate the unbalanced energy as appropriate to the people who are doing the deviation. And, of course, if you're going to get financing for putting in a wind farm, you need to have the financial risk as low as possible in order to raise the money. Okay. So as we create what's called the Participating Intermittent Resources Program -- and this was a collaborative effort over the last couple years as we put this together. And I'm pleased to announce that after considerable work this year, I think we're finally ready, and we have built finally the settlements software. Because not only do you have to be able to forecast the energy and be able to see it and do it in real time, we also have to be able to pay it, you know, do the financial settlement so that they get the return on the scheduled energy that they did so that they make the money. And so we have basically put together a forecasting system that puts together an unbiased forecast for hour to hour to go into the hour-ahead markets. And then that schedule or that forecast then turns into a deemed delivered schedule. If the forecast is truly unbiased, at four o'clock in the afternoons, sometimes the generation is a little above, sometimes a little below, but basically even all over the whole month. And if you take the net deviations, the pluses and minuses, and multiply them by the hourly prices as they go through, when you get to the end of the month, you have a balancing act where you put all those in -- instead of doing a settlement every 10 minutes, you do a settlement at the end of the month. And all the net deviations, that amount, if you've done a proper job of forecasting, should turn into a very small amount. Again, this is the part that lowers the overall risk for everybody and doesn't end up with a big surprise on doing the settlements piece. And so in addition to that, then, because the owners of wind generation are the big stakeholders in the forecasting process, as we get the process working, then we also go back to them and they become part of the monitoring of whether or not we're getting accurate and credible forecasts that they can live with. Okay. Next. So to participate in the program, those generators that would like to sign up for the program sign a set of agreements. They have to install a set of telemetering out to the site. There's a small forecasting fee of about ten cents a kilo -- a megawatt-hour. And then we have to have at least an aggregation to get up to at least a megawatt. And if you'd like to participate, then you schedule it in. Then, of course, as I said, the forecast is going to become their actual scheduled delivery. Let's go to the next slide. And so the thing that looks -- this is from a recent day, and we have approximately 350 megawatts that are currently participating in the program. And as you can see, you get quite a bit of variability throughout the day, but we certainly get production at this point all through the day, even though it's -- even into a December period where energy production is a little bit lower. But -- so the question is, as you look at that curve and all of your good statistical capability, how do you feel you could do on forecasting? If you were standing at a particular point, you know, could you forecast which way this is going to go in the next hour? And that's -- that's part of the trick of this game. And, of course, the other thing -- if you go to the next slide. The one thing that we've learned, of course, in using this type of a forecast -- persistence type forecasting techniques, you need to have a lot of aggregation. So this is an aggregation for about 1200 megawatts, and you can see it's much more nicely behaved. If you're sitting at one of these points, you have probably a much better chance of figuring out which way things are going. The curve looks a lot smoother than what you saw on -- for just the 350 megawatts or so of net participating intermittent resource. So smaller group, smaller numbers of things, you get a lot more volatility in the forecasting, which is going to be part of the challenge to make the program work, which means all we need to do is get more generators to sign up. So -- but, anyway, this was part of the experimenting and figuring out how we could do forecasting. And -- go to the next slide. And what we discovered is that if you're doing short-term forecasting, you know, an hour or so in advance, you could do a statistical, mathematical forecasting technique using the persistence modeling which would give you pretty decent results. If you're going to go anything further out, three or four or five or six hours out into the future, or the next day, which is where we really would like to be, day-ahead forecasting, then you would have to really know a lot more about the meteorological data and what the weather forecast is going to be, and there's other things dependent on that. In addition to knowing what the weather forecast is a day in advance, you also have to know about what the D rating is on the plants. So if FPL Energy happens to have, you know, six turbines off for maintenance for that day or the next day, planned outage, you have to be able to know that so that you can have a D rating on the plant, and that's in addition to knowing what the weather is going to do and what the wind forecast is going to be. Next slide. So this is part of what our overall process looks like. And so what we're looking for now is the plant owner then has to be able to send to us in advance, through a system we call Slick, which is a web based tool that they can sign on and say, okay, my 100-megawatt capacity plant is D-rated tomorrow during these hours to 85 megawatts or 75 megawatts. And so on an hour-to-hour basis, they have a D rating so that we know that their plant is not going to be capable of producing 100 percent of whatever their nameplate is on their plant. We also have been putting together this data processing gateway which sends the actual production from the plant back to the ISO and again accumulates all of the data. The other part is we're looking for the meteorological data coming out of the wind, what do you call it, meteorological towers that are installed at the site. You would think that getting meteorological data would be a slam dunk. I can go down to Radio Shack, and I can buy a piece of, you know, weather equipment that says, here's the barometric pressure, here's the temperatures and so forth. It turns out that this is probably one of the hardest parts, surprisingly, is to get good meteorological data from these sites. And it's been true for almost all the sites. Part of the thing that's been interesting is that the new turbines that are going up, of course, have the wind indicators at the top of the turbine up in the housing area, and then they have a separate meteorological tower. And I think they actually are running the plants based upon what the wind equipment is saying at the top of the wind turbine itself. And in some sites where they actually have several towers, we have a differential in the -- what do you call it -- barometric pressure that is such that the numbers that you get in say there must be a 600 mile an hour wind blowing between the two towers at the same site. So obviously calibration of data and accuracy of some of this meteorological data is still yet to be achieved in order to be able to do some of this forward forecasting. It's interesting that this turned out to be an unexpected technical issue that we hadn't -- we have not yet totally solved. But interesting you always -- like most programs, there is always surprises along the way that you hadn't expected. We also have issues as we're trying to integrate this into our markets, and, of course, we're in the process of also changing the market at the same time. So we have our existing market, and we're going to this MD02 Phase 1B market design. And all of our people on the market side have been totally tied up testing all of the new market software and the new market structure. And so that's made it difficult to close the loop with the forecasting service and be able to forward forecast this stuff. So we have a temporary workaround where the forecasting service is actually getting some of its data directly from the wind generators and doing the forecast then and sending it back to the scheduling coordinators who put this in. So in the future, we will finally complete all the loops of this and improve the quality of the data in order to improve the overall forecasting techniques and make this a workable system. But at least at this point, now we finally have a settlements piece all in place and tested, and so we're ready to open the door finally for business under this particular program. We've been doing a lot of other work on looking at how much regulation services are required for handling the variability of wind. As you'll probably hear at this conference, there's been a lot of work on what is the methodology. We've been running through a couple different methodologies trying to figure out the answer of how much regulation is required. And, of course, it's going to be a variable number depending on how much wind production is going on at any particular time. And, of course, the amount that you have during this period of the year where we're down to loads around 30,000 versus the summertime loads where we're up to about 42,000, 43,000 megawatts, the number will probably vary as we go along. We have just finally finished going through a long computer program development process at the ISO for running through all the data for 2002 and finally have some results to look at for our method, too. But -- so, anyway, and we're still finally finishing up how much -- we have both the regulation piece, and then we have the five-minute, ten-minute dispatch, which is the load following piece. So the question is, does our energy stack have to change and get any bigger or smaller due to the load following techniques that we have to do? And we hope to have some information to publish probably in the first quarter of next year on what those are. Other issues are we're still looking -- you know, we published recently a report, with Henry's help, on capacity value. And then we're also doing work with EPRI and the CEC sponsored programs. We're doing forward forecasting, trying to improve overall energy forecasting techniques. And one of the interesting issues still that is outstanding is what do we do about contingency reserves or forced outages, and does the operating reserve numbers have to change? In some areas of, like, the Northwest, they are imposing a bigger operating reserve number due to the wind. We have not yet derived in California that we need to change what that operating reserve number is, but the Northwest is doing some of that. Okay. So, in conclusion, we see a lot of value from the intermittent resources from renewable resources. And, of course, like all things, wind generation, it's location, location, location, just like in all kinds of real estate. The right location helps a lot. A lot of work to do on forecast accuracy and improving our overall forecasting models, and also improving the meteorological data we get for those sites. And putting together -- making sure that the integration costs back into our market is minimized. And finally that we have to have the right kind of market rules to encourage the construction of new wind generation throughout the state. So I think that should be the last slide. (Applause.) MS. RADER: Okay. We have about 10 minutes for questions, and we need to speak into the microphone for the transcriptionist. We have about ten minutes for questions for all of the speakers. I have -- I'll start out with a question that kind of bridges two of the talks and maybe [unintelligible]. In the development of Amendment 42 and development of this forecasting program, it is imperative because the financing [unintelligible] could not -- you can't hear me? Is this on? Should I talk louder? When we started the down the path of Amendment 42 that resulted in the program that Dave Hawkins talked about, it was because we needed to curb the risk that these imbalance penalties were putting on wind projects, and we felt that was critical to financing. So I guess my question is for Dave Herrick, or others from FPL, whether the fact that these rules were written and the programs were being developed post-finance of your High Winds Project, or do we need a track record for this program to really see the benefits there? MR. HERRICK: High Winds in particular, at least from our point of view, we're handed over that risk to our offtaker. So I'm sure that's helping PPM immensely. No -- the program appears very valuable. You know, we're looking at similar -- similar issues in other states and sort of wish there was a comparable program in other states. So I do think the program is going to prove to be very valuable and quite a positive for wind -- for intermittent resources in the state. So I think as a general, it's benefitting the project, but it's benefitting an offtaker at this point in time. MS. RADER: Okay. Any questions for the speakers? And if you could introduce yourself and speak into the mike. AUDIENCE MEMBER: My name is Jeff Sharpley, Seventh Day Financial [phonetic]. I have a question for Bob Gates. Just in terms of -- you mentioned the number of technological innovations that you've introduced in your turbines. How do you decide which ones to do? I mean, some of them reduce the cost of your turbine, but some of them really affect the ability to integrate into the grid and really kind of help the PPA. So in terms of -- how do you sort of do a closed loop and know what's important, you know, three, five years down the road? MR. GATES: That's a good question. I think that it's largely in the -- in the macro sense, it's largely market driven, so there's always a cost of energy push, what can you do to lower cost of energy? The low voltage ride-thru came with a market imperative. That was very important to us in our VAR scheme, with the requirement for a very important project for them, for a very important customer, electric customer. And because of the situation on that grid, it -- the project really couldn't go forward at this scale without the low voltage ride-thru. And looking at a smaller scale, the economics didn't work. So, you know, at the end of the day, that was market driven. GE would not have gotten that order had it not been able to, in the time frame, make that go forward. So it's -- I think it's mostly market driven, what -- what they needed to do to stay at the leading edge. Does that answer the question? MR. HERRICK: I'll add a couple things to that, too, that just reinforces what Bob just said. Just the general tone of the discussion here today is showing that wind is becoming a larger and larger player in the energy business. Five, six, seven years ago there wasn't really enough of it, and folks that were running the grids, they could absorb wind and it wasn't a problem. Nowadays it's gotten large enough where it's not -- it doesn't fly below the radar screen any more. And you're getting more and more requirements being put on wind from folks like the ISO, and not just in California. Texas and across the country are becoming more restrictive in what wind can do electrically. Things that you could do five, six, seven years ago, they're saying, hey, you know, you guys are big enough now, you're causing us problems, and they're pushing requirements like low voltage ride-thru to us. And we -- and, you know, we have to, in turn, push the manufacturers and say, hey, if we want to continue to grow the business, we've got to be growing technically. MS. RADER: Mark, did you want to add to that or you have a question? MR. SMITH: In fear of piling on to the same question, Mark Smith, I'm also with FPL Energy. I think the question is ripe. It's very, very appropriate in today's market because a lot of the technologies that GE presented today may eventually become part of the standards that the American Wind Energy Association hopes to promulgate over the next six months or year, and particularly in order to allow wind penetration in various regions to move forward on a consistent and standardized basis. One of the things that we run into continually as we move from transmission owner to transmission owner, from control area to control area, is they all assume or imply or impose different standards on the wind generation community. So for those of you in this room or even the collaborative itself, if you would like to be engaged in the development of those standards and how they're going to evolve, I'm sure Mr. Gates would be -- because his product serves most of those standards, please let me know. I'll be here at least for the rest of today. Thank you very much. MS. RADER: Any other questions? People want -- are ready to break. We have a nice half hour break for schmoozing. So if there are no more questions, we will begin to schmooze. (Applause.) (Brief break taken.) MR. VAN DAM: I have a few comments before we get going on the next panel. There are a few pieces of information actually that are available in the back of the room, and actually I'd like to make you aware of it. The people from the California Energy Commission brought in some wonderful wind power maps of California. They're in the back, and please feel free to get one for your office or for your living room. They are quite colorful. I think there are two different types. One may be a power density; the other one may be wind speeds. I'm not quite sure. So that is one piece of information that you can take home tonight. The second handout there is transmission for renewables, and this is a conceptual plan put out by the CEC. So it's a little handout, and please look at that, too. There is a lot of talk about transmission, of course, and that is for your taking also. Last but not least, Dave Hawkins has a handout of his presentation, and that is in the back there, too, on increasing wind energy on the California grid. And please feel free to take a copy of that also. Again, in the coming weeks, we'll have all the materials that are being presented today and tomorrow. We'll have them available on our web site, and you can download them at that time, including all of the text. While everybody is still looking at the handouts, I'd like to introduce the next panel moderator, and that is Kevin Jackson. I have known Kevin for quite a few years. He has been a consultant in the wind energy industry since the mid '80s, mid late '80s, so he has quite a bit of experience. We enjoy working together. And he is also one of the key participants in the collaborative, a terrific person to work with, very knowledgeable. And the panel, the next panel is in good hands with Kevin. MR. JACKSON: Thanks. We're going to change the format just a little bit. One of our speakers got delayed, and so we're going to put him at the end. Tim Tutt was going to start things off and tell you a little bit about the RPS and how things fit together. Tim got delayed, but he'll be here, and we'll put him in at the end. We'll start off with Brendan Kirby. Since we don't have Tim, let me give you just a quick outline on the RPS. It was enacted I think it's been a year and a half or so, and there were a lot of things that had to be in order to make the legislation work, and one of those is integration costs. And specifically, we had to come up with some numbers for what different renewables would cost, what hidden costs would the grid have to bear for integrating those renewables. And so the Wind Collaborative got asked to participate and facilitate that effort, and so one of our tasks for this year was actually supporting the RPS integration effort, and so we worked extensively with Brendan and Michael on doing that, and also with Dave Hawkins and Larry from Cal ISO. And so Brendan is going to be talking a little bit about the regulation load following aspects of integration costs. And, again, these are costs that are hidden and that might have to be borne by the system that need to be somehow allocated. Brendan comes to us from Oak Ridge National Laboratory. He's a senior researcher there at the power systems research group. He's also a private consultant. He's been in the utility industry for more than 20 years and has done extensive work on the structure and ancillary services since about 1994 and the spot retail power markets since 1985. He recently participated in the investigation of the blackout and has got some good stories about what he found there. And he's been in lots of groups that are looking at utility restructuring. He's also spent an awful lot of time looking at how wind fits into utility integration. So with that, I'll give you to Brendan. MR. KIRBY: I'm going to talk about the load following regulation. What I'm talking -- Dave Hawkins showed a very similar slide. This is a daily load cycle for a typical utility. And I'm going to be talking about the two characteristics: One is these daily ramps that are the long movements, and then also these fluctuations. With a power system you've got -- you can't really store electricity practically so you have to balance the electric power system continuously and instantaneously. The only advantage we've got is if you balance it on an aggregate basis, you don't have to balance individuals, but you do have to balance. Failure to balance -- the system will balance. It may balance at zero, and that's not pleasant, but it will balance. So these fluctuations become important. You can take the -- the green line here is what the total system is doing. It's going through part of its morning ramp up from 7:00 in the morning to 10:00 in the morning. And you can split that into the blue line, which is the slow load following ramp up and these faster fluctuations. And the faster fluctuations are placed on an expanded scale so that you can see them more. And there's physical, practical reasons that you'd split them. You can be following these continuous random movements around a fixed zero amount with one type of resource that's very fast. And it's on automatic generation control, it's controlled automatically. And then these slower ramp ups can be followed by either a market or by slower moving units that are -- that know that they're going into a set trajectory. Okay. So we have these two services that are load following regulation. Both of them are addressing this time varying problem, and both generators and loads contribute to this. There -- the system only has to compensate for the aggregation. That's a very critical point. You don't -- you don't care that any individual is moving and you're going to track him perfectly or an individual is ramping and you're going to track him perfectly. No, you lump all of them together, and then you track the total. Now, the total aggregation is composed of individuals. And it is important to -- or it can be important to find out, well, who's causing what? Turns out in the -- in the vertically integrated world, we didn't really care. We just lumped them all together, and we provide the resources to track the total. So wind is kind of in a funny situation. It's -- it's coming in as being a serious -- you know, a viable resource. At the same time, we're doing restructuring and starting to split these things up. Wind is pioneering -- not only is it a resource that's different than conventional generation, but it also comes in at a time when we're first starting to think of, well, shouldn't we be looking at what individuals do to regulation and load following? And we'll see in a little bit why that's important. Okay. Regulation, that's looking at these fast movements. Well, what do you have to do to take care of these fast movements? You got to have a generator that's got to be on line. It's got to be not fully loaded. A generator that's going to be moving rapidly can't be maxed out; you've got back it off from the top. It can't be at the bottom; it's got to be moved up. Both those means that this generator is going to forego some opportunities in the energy market. If it has a good production price and you'd like to have it, you know, running flat out because it's making a profit, he has to back it off. So part of his cost is going to be lost energy sale opportunities. And also the fact that this unit is moving around a lot, it's heat regulated. So these are costs that go into it if you buy this service through markets in California. So -- but these are the cost components that go into it. If you want that automatic generation control, then you've got to have a unit that's capable of moving pretty fast. Load following, on the other hand, is this ramp [indicating]. It's taking care of the morning pick up and the evening drop off. It's generation that's going to move to meet the hour-to-hour fluctuations. Depending on the region and the speed at which markets clear, anywhere from ten minutes to hours. Interestingly, FERC didn't order that the load following service be provided in the market for it. The way that it comes about, the practice in every region that's done restructuring, is load following is provided by the hourly and subhourly energy markets, not specifically by the regulation market. And we're going to talk about that right near the end. Okay. The differences, the differences between regulation and load following. Again, regulation is going to clear through its own market. It's going to have a separate price for this service. Load following, it's interesting how it may or may not have a price. The differences are regulation is random. It's fast. It's a relatively small motion, and these motions are random; they're uncorrelated. Load following is the morning pick up and the evening drop off. You could follow regulation or load following manually. You could dispatch generators manually for ABC -- for regulation. It's got to be automatic generation control. The swings are 10 to 20 times larger for load following, but it is slow, and you have very few sign changes. Okay. And then you say, well, if these are services, are there any metrics for them? It turns out, yes, there are. For a control area that's got standards it has to meet, it's got to balance -- what it cares about is keeping frequency constant, as Dave Hawkins was saying, keeping frequency constant and also balancing your -- the entire -- the control area's interchange. So you don't want to have unscheduled floats. You don't want to be pulling in power from a neighbor when you're not supposed to or shipping power out. The metrics are two nerve metrics, Control Performance Standards 1 and 2. These limit the one-minute deviations, and CPS-2 gives you a statistical limit on one-minute deviations. CPS-2 gives you some ten-minute limitations. These metrics are all on the total control area. They're not on any individuals, not on individual loads, not on individual generators, even though it's what the individuals do that cause these problems. Okay. This just tells you what the exact formula for Control Performance Standard 1 is. It doesn't really matter. The important thing is that what it's looking at is area control error, how well you balanced your total area. It's looking at it on a one-minute basis. And it actually doesn't compare completely out of your control area. It does [unintelligible] when it's multiplied by the offset in frequency. What that's mean? If the system is running exactly at 60 hertz and it's scheduled to be at 60 hertz, then Control Performance Standard 1 couldn't care less how well the control area over or undergenerates. It doesn't matter. It's driving to try and force that frequency back to 60. CPS-2 says, well, gee, we can't have that. If it's -- it just looks at the over -- at the area control error. And if the area control error is a mismatch between total generation and total load, then it says, you've got to limit that against the statistical metrics. You've got to beat the metric 90 percent of the time, so it limits these area control error excursions. The important point is that it's limiting aggregate generation load deviations, not individuals. Okay. Here -- I'm a power system guy, and I'm a wind guy. First looking at the regulation metrics, what we did was to look at -- it turns out it looks at steel mills. Everybody, all the control area operators know steel mills are serious contributors to regulation requirements. And this is looking at an example of an aluminum smelter and a steel mill arc furnace. And when you normalize the capacity side, you can see that the aluminum smelter is a pretty dead constant load. The arc furnace is bouncing all over. In all of the tariffs, these guys are treated the same. Even though the steel mill is bouncing all over and the generation has to change that around, that guy doesn't pay any more. There's no -- there's no tariff that says we're going to charge you for the amount of volatility you're placing on the system. We've been doing it for a number of years, doing analysis, looking at what the impact of individual loads are. We've done it for quite a few utilities, and we came up with a metric for actually assessing how much impact does that have on a control area? So the point here is, the individuals can and do matter. It turns out when you look at these vary -- these fluctuations, because the fast fluctuations in the regulation time frame are uncorrelated, they tend to cancel each other out, which is a big help. You're looking at energy. If one guy requires 100 megawatts and another guy requires 150, the total you're going to supply is 250. For fluctuations that's not true. It goes up as the square root of the sum of the squares. Very important, it says that the regulation burden, you want to be -- you want to aggregate people together. You do not want to compensate individuals. You don't want to go and say, well, this guy is fluctuating, I'll do something to compensate for that fluctuation. Another fellow here, I'll compensate him for any fluctuations. You always wants to group them together and compensate for the total. It's -- for society it's better because the burden is much lower. Here is just showing that -- what that square root of the sum of the squares does. It's also why residential loads -- residential loads are very bad for regulation. You know, a hot water -- an electric hot water heater, it comes on and goes off. It's a very big step change. An oven as it heats, it goes on and off. It doesn't hit some nice even amount. But if you take a million homes, when you aggregate them together, the requirement is only a tenth of a percent of what it would be for the individuals. Obviously if it's just one guy, it's one to one. But when you get to a hundred, it's only 10 percent. It says, if I can join with a hundred other folks that are the same, I will only have to supply regulation equal to a tenth of what I would have to for one. Aggregation is incredibly important for regulation. And why do we care? We'll see why we care. Okay. If you want to now look at allocating a regulation burden, there are certain metrics. This aggregation benefit is highly non-linear, which says things like, well, if you just say, well, the increment, if I add a little more of a burden, I'll pay for that a little more. Well, if I'm the first guy, I really get nailed and the last guy gets a free ride. What you really want to do is make sure that any metric you come up with is independent of the order you put these guys in. You want -- you don't want to have, well, I just happened to analyze this guy first and this guy second; they get a different number. You also want to recognize positive and negative correlations. If I happen to build a generator or a load or whatever, if I manage the fluctuation in a way that reduces the overall requirement for regulation, the metric ought to recognize that and ought to pay me. It ought to say, hey, I've done a good thing. Well, we've built a regulation metric that does this, that is both independent of order and it recognizes positive and negative correlations. That's the formula for it. We won't worry about that. It turns out that it's a relatively easy formula to implement. It takes one-minute data, and you just collect a bunch of it. The only point is it is numeric, just like [unintelligible]. It calculates it; it doesn't take a whole lot. All it requires is one-minute data from the individual and one-minute data from the total control area, and you can figure out how much that guy contributed. You can just aggregate as few or as many as you want. And here's looking at a system, a power system control area in the Midwest that happened to have two steel mills, two arc furnaces. This is what the regulation requirement is if the steel mills weren't there. The red line is what it is when they are there. These individual steel mills each contribute more to the regulation requirement than the entire rest of the system, even though they account for something under a third of the energy. In fact, we'll probably see what it -- okay. I've got two different control areas. In one, we did this for -- well, actually for a number, but here are just two examples. In this case the industrials account for a third of the energy; they account for 93 percent of the regulation burden. In this other case, which I believe is the one we just saw about the two steel mills, account for 3 percent of the energy, but 44 percent of the regulation burden. So individuals can matter, and we have a calculation method that will find that. When we went and applied this to all the renewables that we could get data for in California, as well as looking at the amount of regulation, which what do we really care about that, you can take the amount every hour multiplied by the price every hour, because California clears regulation on an hourly basis, and you can then figure out what's the cost. And it turns it all into dollars, which is when we do care. And we find that the total -- now, this is in terms of dollars that you have to pay to pay for regulation service. When we look at total load, it's 20 cents on a -- on a megawatt-hour. That's pretty low. Well, but there's a whole lot of load in California, so that ends up being -- 20 cents ends up being about in the neighborhood of $50 million a year. The reason they're procured in total, you can -- in California, you can buy regulation through a market, and you can also self-provide, and it's about half and half. But it turns out that it's -- the total requirement for the total control area, it's about half self-provided and half procured. So if you take the price that's paid for the procured and then look at the amount that was needed for the total, you find it's 42. That's about $100 million a year. We went and -- it's hard to argue with the number on the top because that's just flat the amount that -- the total dollars that were spent and the total load, so that was an easy calculation. We then looked at these individual -- we used a gas unit, a gas-fired unit as a comparison, and then looked at various -- various renewables. And what we find is that when that biomass unit was run, it didn't fluctuate much; no cost. The negatives in this case, negatives like load, it's a -- build a positive means you get paid. It turns out the solar units, the way they were operated, they ended up contributing something. Very small, very small, but they did contribute, so they did get a credit. When you look at the wind guys, which you would expect, the wind fluctuates, it's puffy, so you would expect -- and what a surprise, it does indeed have a cost. It is a cost that's less than -- that is less than load, and that may seem odd. A very interesting thing to do -- and we hope we can do it. We don't know if we can. We may have problems with the proprietary nature of data. It would be very interesting to run this metric against a steel mill. And there is one in California, so we're hoping we'd be able to get that data. Alternatively we can run it against a steel mill, say, from Indiana, which we do have data from. And we'll be trying that and see what would -- just to make sure that we're doing all this exactly correctly. It would be very interesting to see what a large fluctuating arc furnace where we have good reason to suspect, you know, it's contributing a lot, what does it get out of it? We're going to make sure there's nothing funny going on and we're underaccounting. But the reason this comes out so low is even though wind is fluctuating a lot, it's fluctuating relatively slowly on a minute-to-minute basis. We won't talk about energy imbalance because Dave already did that, so that will save me some. Great. You say, okay, well, what about load following? What about these long ramps? And, gosh, that gets really interesting because, you know, our first reaction to that is saying, well, we're not going to deal with it. Because in California, the way the energy market clears, it kind of takes care of that. But we keep getting questions. Why are these numbers coming out so low? So it's very interesting. You go back and say, well, wait a minute, load following. How much time do I have? 35 seconds? Goodness gracious. What we find out is that no market in the country is structured to actually put a price on load following. Gosh, why is that? Regulation, very explicit. Everybody is restructuring. We need [unintelligible] not on individuals, on the total. We need to go and recognize regulation as a cost, and then we compensate the generator for providing it. We don't for load following. Instead we have energy markets. So saying that, we'll just scoot through and say, gosh, well, why would that be? One reason it might be is because there may be a tremendous amount of excess load following capability. There may be a tremendous amount of ramping capability. Okay. Well, how would I test that? Again, data is a problem. What we went and did is we looked at all the generators we could get data on in California, publicly available data. So Michael and I went and looked. The system peak load in California is like 42,000 megawatts. We looked at what kind of -- public information on generators. The place you get public information on generators is hourly information, because they're emitters. They emit pollutants, and they have to report hourly what the pollution is. You can back calculate that to what their production was. It turns out a third of the generating of the total -- of the energy in California you can account for. 52 percent of capacity, but a third of the -- so we can track a third. We can't get information on what the hydro is doing, what the nukes are doing, what the imports are doing or what the renewables are doing, but we can get a third of them. All right. A third is not so great, but at least -- so we looked at that, and we said, what's the generator's capacity? What range power, you know, it's total production, maximum, minimum? What range can it move in and what its ramp rate? How fast? And then we looked for every hour, what is the system requiring for ramping up, down, whichever? Which of these generators were on line and how much excess ramp capacity do they have? And then see what the -- and what we got was, you look over 8760 hours, this is the amount of ramping capacity. You can see an awful lot of hours. There's an incredible amount of excess ramping capacity. Well, that could explain -- and this is just looking at from 8500 hours out to 8760, and you see we have a grand total of 40 hours or so. That one-third of the generators can -- you don't have enough capacity to cover the ramping requirements. This is the whole rest of the time that one-third of the generators has got excess capacity. So that's a very preliminary look that says -- that may explain why no region in the country goes and charges for load following. And that's why, you know, it -- it may not be a surprise that load following will come out to be a very inexpensive or a free service that falls out of the way energy markets work. So there we go. I went over by a little bit. I didn't screw up on the button. (Applause.) MR. JACKSON: If you're interested in this in more detail, you can go to the California Wind Energy Collaborative web site, which I believe should be somewhere on some of the documents you've got. And there's a lot of information available. There's a lot of background papers that led up to this work, and there's a couple of presentations that were given, public meeting presentations that were given of this material. And there's a full report, too. It's like a 150-page report or something like that. That has all the details of the methodology of both the regulation and load following and also the capacity things which Michael is going to be talking about. Michael Milligan is next up. He comes to us from the National Renewable Energy Laboratory. He's been there since 1992, and he also works as a consultant. He's been looking at wind integration issues all over the country, especially capacity value, geographic dispersion benefits, forecasting benefits, and statistical forecasts and load following, and unit commitment decisions that utilities have to make. He's published over 40 papers and technical reports, and he's going to be talking about capacity valuation, because, as you know, we get paid for energy, but we also get paid for capacity. And the real question is, how do you pay for capacity for intermittents? What's the process by which you value that capacity? So now I'll give you to Michael. MR. MILLIGAN: I'd like to thank the rest of the team that I've been associated with on this project in California. It's been a really terrific experience. You heard from Dave Hawkins earlier and Brendan. Mr. Henry Shiu, who is running all over the place -- I don't know where he is. There he goes. Oh, that is not me. Okay. I was getting nervous here. Anyway, what I'd like to do is talk a little bit about what we've done up to this point with the Phase I results. Kevin mentioned that is posted on the web, and it makes for a really great cure for insomnia if you're having a little trouble sleeping. What I'd like to do is just cover some of the high points of what we've done. You know, why is it that we're looking at capacity analysis, the -- sort of the relationship between reliability and capacity. And we'll take a quick look at some of the Phase I results from the capacity analysis. And by the way, this project is not restricted only to wind. The objective is to take a look at all renewable technologies. It doesn't matter what they are as long as they're renewable. A couple of issues that we are still kind of grappling with, and we're sort of pushing those out in Phase II or Phase III of the project, and then kind of the idea of what we're going to be doing in the next step or two. The basic objective is to come up with a way that you can assess the capacity contribution that each type of resource has to the system and to put that into the bidding structure so that when you get a renewable developer coming in saying I want to build a wind plant or a solar plant, that bid is transmitted to the utility, the utility evaluates the bid, and there's some sort of scoring mechanism that results in the resource, you know, coming out either well or maybe not so well with respect to the capacity credit. There are other pieces to the bidding as well, but this focus here is on capacity value itself. So what we've done in Phase I is to propose and develop methods for doing the analysis, and we've done that. We've also applied that -- there we go -- applied that to the current renewables in California. Now, we've already heard this afternoon that the -- how shall I put this -- the technology that's in use in wind generation in California is not quite state of the art in most cases, and so that's something that we do need to look at more carefully as we move forward into Phase II and Phase III. The real objective is to say, what's going to be the impact of this renewable portfolio standard once you start getting 10 percent or 15 percent of the energy coming from renewables and a large part of that perhaps from wind. When you talk about capacity value, there are actually probably a thousand different definitions. So what we wanted to do is take a look at sort of a broad definition of what it is that you can do as a generator to help the system out when the system is potentially in trouble. And so the approach is to take a look at reliability based on some sort of loss of load calculation, loss of load probability calculation. And what you want to do is find what this resource -- whether it's wind or solar or whatever it is, how is it contributing to the system reliability? Well, when you talk about loss of load probability, sometimes people say, oh, my gosh, I don't want the lights to go out, so let's don't do wind. That's really not what we're talking about here. The lights aren't going to go out, I don't think. But the issue is not so much the actual failure, but you want to minimize the risk that the lights are going to go out as a result of generation insufficiency. And when you look at that, you say, well, whatever capacity measure I come up with, I want it to be as close to physical reality as possible. One of the problems with with markets, not just the electricity market but any market, can be that if you've got a set of incentives that don't reward the kind of behavior that you want, it's like with Enron and a number of corporate scandals that we've been reading about over the last year or so, sometimes you get the incentives wrong. So the objective here is to try to get the incentive right so that if I'm a developer and I have two or three potential renewable projects, I want to go with the one -- all other things being equal, I want to go with the one that's going to provide the greatest benefit to the system because I get rewarded for providing that benefit to the system. Well, the ELCC, the effective load carrying capability, is the metric we've been using. And essentially what this means is, you take a look at the entire system, the entire portfolio of the generators, and one at a time you can remove one generator and see what impact that has on the loss of load probability. And then what you want to do is to then feed in a benchmark unit -- we used a gas unit as Brendan mentioned -- and then see how much gas is it going to take to inject into the system so that I get back to the same annual reliability level. And that's what the ELCC does. This is not a new technique. It's been around for, I'm going to guess, 50 years. I know there was a real influential article published back in the '60s about this. It's been around longer than that, and it does apply to any technology you want, whether it's wind or coal or gas or nuclear, you name it. I'm not going to go through all of the words here, but the basic idea is that utilities traditionally and control operators worry a lot about the single hour that the system peaks, and that's probably a pretty good thing to worry about. But it isn't the only thing you want to worry about, because you've got a number of hours where your system is going to be stressed, and those hours can occur maybe several hours in one day. They could be spread across a season or they could be spread across the year. So the idea behind this metric is to say, let's take a look at the full year and identify those hours when we're at risk, and let's reward the generators when they can help mitigate that risk, during the times that we need them. And that's essentially what all this stuff is talking about. This metric can distinguish between all kinds of different things, a reliable unit, an unreliable unit. Small units are obviously going to contribute less to reliability than a larger unit. But if a large unit goes out, it could clearly put you in bad shape. Where if a smaller unit goes out, you may not notice it. You also can distinguish between different types of intermittent technologies, and this calculation will tell you implicitly that this is a really great intermittent resource because it shows up exactly when I need it, and it does a really great job of reducing the risk. Where maybe another renewable resource that shows up -- we were talking about I guess the misconception that all wind blows at night in California. If you had that, then the impact of such a wind generator is going to be pretty minimal, actually probably zero in terms of increasing reliability to the system. So the idea that we recommended, I guess it was in a workshop last April, was to go ahead and move in this direction. The ELCC calculation is somewhat time consuming, and so the idea is to come up with a simplified method that can do a good job of approximating ELCC and then use that as we go forward into Phases II and III. This gives you -- actually, I'm going to cut through this graph. This is a similar graph. This does show the California system. And what you see is we're taking a look at the reliability. This axis, the X axis, I either chopped it off or I forgot it, is 900 hours. It didn't get very interesting out there. But what you see is a tremendous concentration of risk in the top roughly 100 hours of the year. And then as you move down here, there's still significant risk. And so the system spends somewhere on the order of 570, 580 hours a year at some level of risk. That's -- if you look at the scales, it's not very high. This is a logarithmic scale. But we spend the rest of the time at a risk level that's near zero in terms of generation adequacy. So what this technique does is it says, if you've got a resource that's going to be around during these critical hours, we're going to reward it, and it may be a big time reward. Whereas if your resource is only around during these periods, we'll going to give it some reward, but not a lot. If you've got a resource that's only out here somewhere in the tail, out where we're looking at zero risk, it's not going to do much for you. It's not going to hurt you, but it isn't going to help you very much. This chart shows the sort of overall behavior of how the ELCC works when you apply it to a conventional generator. So the idea here was just an example to say, well, I've got a unit that's got a 10-percent failure rate, forced outage rate. What sort of effective load carrying capability would it have? Well, it turns out that in terms of our benchmark gas unit -- I can't remember the exact number -- we had a 5-percent forced outage rate or something like that and about a 5-percent maintenance outage rate. It turns out that if you've got a 10-percent forced outage rate, you get about a 100-percent capacity credit relative to the benchmark unit. Of course, no unit is perfect. And then if you simply increase this forced outage rate in increments of ten, what you find is -- for example, if you've got a conventional unit that's out 70 percent of the time, you ought to think about repowering, something -- I don't know, something else. But in any case, if that's what you had, you're going to get an effective load carrying capability somewhere around 30 percent of the capacity of that unit. Now, the numbers look like -- you say, well, if I have a 10-percent forced outage, then I get a 90-percent capacity credit. That's approximately true. It's not exact, but this is all based on sort of standard conventional technology which is more or less controllable. And then the obvious question is, how do you apply it to an intermittent resource like wind or solar? Well, it turns out that you can do it. I'm not going to tell you how, but essentially -- well, what you do is you take the wind generation over the year, you divide it by a whole bunch of statistical distributions, you feed it into a reliability model, you crunch on the data for awhile, and eventually you get an answer. So that's essentially what you do. On the Phase I capacity results, I'm going to spend just a minute on this curve, but there's a whole family of these that look more or less the same. This is biomass, and you can see that the number is not quite 100 percent of the benchmark unit. Basically what you do is you develop a target reliability level, and what we used is sort of the standard rule of thumb of one day in ten years of total inability to meet load. So maybe we only missed it by a little bit, but if you miss it, you miss it. Then you take out the unit. So in this case we took out the biomass unit and take a look at what the reliability of the system would have been. Well, we're measuring this as a loss of load expectation. In other words, reliability goes down whenever this number goes up. So then what you do is you start feeding a little bit more capacity factor into the system to replace the biomass, and you keep going until these two lines cross. And when those two lines cross, that tells you the capacity that -- the capacity of gas that you need to give you the same level of reliability as the biomass unit that you took out. And then we can figure that out and normalize it based on the size of the biomass unit. And that's where this 97, almost 98 percent number comes from. Did it for biomass. Did it for geothermal. Actually, a couple of interesting things with geothermal. We got a -- I think Dave Hawkins was pumping out data from -- if you ever noticed the Internet was slow back in February, it was Dave's fault. He had data pumping out like crazy, hourly dating from all kinds of generators and actually minute-to-minute data from the regulation analysis. When we got to the geothermal analysis, it wasn't really clear from the data set how much -- how many dispatch instructions was this unit responding to? And secondly, it wasn't clear what sort of fuel constraints, steam constraints there were. So we don't know exactly what this 72 percent or 74 percent means. But we talked about this in our workshop a few months ago, and the participants said, you know, this is perhaps real, but what about a geothermal unit where you do not have a steam constraint? So we ran through that, and it worked out, you know, pretty good if you're a geothermal generator. You get a little bit more than the benchmark. Solar came out to be about 57 percent. A lot of discussion of this when the report or actually the draft report came out. People saying, well, that's way too low. You take a look at the contracts that specify the capacity payments, it should be a lot higher than that. Well, we went back and looked at the data. And the the top -- what is this -- 200 hours of the year, we actually took a look at the data set, and what we found was a lot of variation in output. And you can see all these dots kind of scattered all over the place. Well, it turns out the capacity factor of the wind plant during this time period -- I can't remember the exact number. It's really great. It's upper 80 percent. And that would suggest perhaps a fairly high capacity credit. But as it turns out, you've got enough periods of time, for example here an hour, roughly 45, something like that, a couple of other hours here where you're not hitting the rated output of the plant, and, therefore, what you get is a big penalty on the capacity payment. Or the capacity value, I should say. We're not attaching dollars to this yet. So the points over here along the, you know, zero, one, two, three top hours get a lot more weight than the points down here [indicating]. Well, to cut to the chase here, we're not entirely sure what the data says about solar, so we're going to hold off on a recommendation about how to use this data as we go forward until we can get a better idea as to whether or not we've got gas assist in this, whether it's pure solar and we can figure out what this means. So we're looking at that one. The various wind resources. Again, this is not the latest and greatest technology. Altamont, we've got a capacity credit around 26 percent, and it declines about 2 percent at each of the resource areas. At San Gorgonio we've got 24 percent, and at Tehachapi we've got 22 percent. That's not great, but that's what the data suggests to us in terms of what sort of contribution and reliability we're getting. And this chart simply summarizes everything that I've just showed you in terms of capacity credit. Well, what about these simplified techniques? Can we come up with anything? Well, this is some data that we've worked with for a number of years from North Dakota, pretty good sites. And what we're trying to do here is to come up with a simple way of calculating capacity credit by using the wind capacity factor. We're talking reasonably well. It's nothing to get too excited about. But the red line here shows what you get if you calculate the cumulative capacity factor starting on the system peak and working your way out to about 30 percent of the hours, the top load hours. This is actually the same site in a couple of different years. And the important message from these graphs is that the red line and the black line, you know, they're on the same page. They could be a little closer, but they're not too bad. Well, so we thought, let's take this and apply it to California. Well, it doesn't work for solar. The ELCC comes out to be in the solid line there at about 56, 57 percent. The capacity factor of solar over the top roughly, what, 860 hours, top 10 percent of loads, it's up in here somplace [indicating]. It looks like these two lines are not very close. That's not good news. It only got worse as we looked at wind, and that's all over here for the first couple of hours, but then it -- you know, wind picks up. So you say, well, if you go back to the North Dakota case and you want to choose the top 10 percent of load hours and use that capacity factor as an approximation for the capacity credit, well, that's going to take you up in here someplace [indicating], and frankly that overstates the capacity contribution that you're getting from this wind resource. And it didn't get any better. San Gorgonio, Tehachapi just didn't work out very well. So we're still kind of scratching our heads trying to come up with ideas of how we think we can make this simplified method work out. Some issues that we're sort of grappling with, we -- some of the earlier runs of the modeling, we built in all of the maintenance schedules for the conventional units in California. What we found -- I believe this was 2001 data, if I'm not mistaken. We saw that there's a fairly high peak load in October. And at the same time, the wind generation was not doing particularly well. It turned out to be kind of an unusual year, and so we went back and we got a number of comments at one of the workshops saying, you know, that doesn't quite seem right. What you're doing is you're loading the wind capacity value based on what's happening in October. October can be an important month, a risky month, but it generally isn't. And so we removed the effective maintenance scheduling and recommended the Commission to at least consider taking a look at the -- forget about renewables, but take a look at the impact of maintenance scheduling on reliability of the California system separate from the renewables study. So we thought that might be something to consider. Again, we're not quite sure about the solar data that we got. Does it represent gas assist or is it some other combination of things? We're not quite sure. We need to work on that. Geothermal steam constraints, we've got to try to figure out how to -- how to parse the data so that we can take out any dispatch instructions, take out fuel constraints. What do you do if you've got a geothermal unit that is bidding in? You probably want some sort of insurance. I'm almost done. I need some of that caffeine that Bob Gates had this morning, and then I can finish this up real quickly. But essentially how do you evaluate a bid from a steam -- a geothermal unit if you're not certain about the fuel resource over the next 20 years or whatever it's going to be? And then we're still kind of working on a simpler method for wind. And that's essentially where we're headed from there. Thank you. MR. JACKSON: Next up we have Jeff Miller. He comes to us from Cal ISO. He has more than 25 years of experience in the utility industry, and he's currently the regional transmission manager at Cal ISO. He's overseeing the planning of the southern half of the Cal ISO transmission system that they operate, and he's coordinating the interconnection of new generators. Jeff Miller was one of the first employees hired by Cal ISO in August '97 and is instrumental in the start up of that organization. So now I'll hand you over to Jeff Miller. MR. MILLER: Thank you. Thank you very much. It's really a pleasure to be here. They called me up, and they said, well, we have a group of people that are interested in wind; could you come and talk to them? And I jumped at the opportunity. It just turns out that just a month or two ago a report was published on the study that I was deeply involved in, and it deals with a lot of different things, but one of the things it deals with is the integration of large amounts of wind generation into the entire western interconnection. So I thought I'd spend some time talking about that. So the title is Regional Transmission. I'm going to look broader than just California. If you want to talk about California issues, I'd certainly be glad to do that. We do integrate a lot of the generation in California, a lot of wind generation into the grid. (Brief interruption in presentation.) MR. MILLER: We'll keep it low tech here. I'll just do the -- I'm an engineer, I love gadgets, but sometimes they trip me up a bit. All right. I want to talk about a group that probably not many of you have heard about. It's called the Seams Steering Group Western Interconnection. It's kind of a long name. But what it is is it's a group of three proposed regional transmission organizations and California ISO being one of them, and there's one that kind of goes through the Northwest called RTO West, and one that covers the Southwest called West Connect. The Federal Energy Regulatory Commission, when they looked at these three RTOs, said, well, how are you all going to get together and plan as one RTO? So we formed this group called SSG-WI. And now that the RTO movement has sort of slowed down a little bit, we incorporated and we allowed anybody that was interested to come join us. So we had a lot of involvement from the wind community and others in our efforts this year. And this year was the first year that we published a study -- we did a study looking at the overall operation of the grid throughout a year's time. We looked at a couple different years, 2008, 2013, and we tried to identify congestion on the grid, and we tried to identify what would happen if we integrated large amounts of generation, where would the congestion occur, and then how would you mitigate that congestion? What transmission would you add? The general purpose of SSG-WI was to -- not so much to focus on what does it take to integrate a lot of wind, but how do you create a grid that works well for markets, that is efficient and economic to operate, that allows a lot of different resources to be integrated into the grid, and does that in a way that presents a low overall cost to consumers? The report is posted on this web site up here, just ssg-wi.com, and you can download it. There's a nice summary report that we sent on to FERC. You can get that off the web site. And, of course, as with any of these studies, there's reams of appendices that go with it. But it's a short read. It's worth your time. When we looked out in the future, we looked at the year 2013. We try to look ten years out, and we looked at two different -- three sort of book end generation development scenarios. We looked at, well, what happens if we kind of continue on the course we're on now, where all new generation pretty much is gas-fired generation? So we looked at that. Most of that we located near the load centers. As a result, we didn't see a lot of new transmission needs as a result of that. Then we looked at coal. And if you look at just dollars, it's hard to beat coal for cost. It's nine mills instead of 40 or 50 mills for gas. So we looked at a coal scenario. And if you're interested in the lowest cost, that one might interest you. And then we looked at a renewable scenario where we said about 72 percent of the new generation is from renewables, and most of that was wind. We actually looked at adding about 18,000 megawatts of wind generation across the interconnection. When we did the report, we really had three audiences in mind, and so we had three audiences and three different purposes. For transmission providers -- I work for the California ISO. I'm interested in, you know, okay, five years out, what transmission do I need to get moving so that the grid operates efficiently? So I'm looking at near term congestion based upon generation that's already planned to be in place. Energy policymakers are interested in, okay, if I make a decision to implement a lot of renewables, what sort of impact is that going to have on the grid? They're interested in that. So we tried to give them that information. And then generation developers, if you're a wind generation developer or coal, you need to have an idea of what it would take on the transmission grid to get your resource to load. We tried to help generation developers, and this is a graph that shows the different resource scenarios that we studied. You can see -- there it goes -- that little purple bar at the top is the wind generation. This is 2000 actual. So if you look at the overall capacity of the western interconnection, wind isn't really that significant a part right now. We've got a couple thousand megawatts overall. It's not that big of a chunk. And if we look out five years, we don't see it growing too much. I mean, there is definitely more, but not a lot. But if we look at 2013, we've added in about 10,000 megawatts of wind, where we've added enough so that we have overall about 10,000 megawatts. And this is for the gas scenario. We had wind in all three of the scenarios. And in the coal scenario, we also had about 10,000 megawatts of wind. And then in the renewables scenario, we bumped that up to closer to 20,000, 18,500 megawatts of wind. This map shows the general locations where we added in the model. You can see a lot of it was added along the Rockies, Montana, Wyoming and Colorado. This shows essentially the 10,000 megawatts in the base scenarios. When we bumped that up to 18,000 megawatts of wind, most of it was located up along the Rockies. And in the simulations, it's important to -- if we put in all 18,000 megawatts and it was all just operated at full capacity, that, you know, of course, would create a lot more congestion than would exist on the system. We used -- we assumed about a 34-percent capacity factor for these plants, and we gave them, as a credit towards capacity, 20 percent, which may be a little low based on the last presentation. Then we tried to develop, well, what sort of new transmission would you need to get all that generation to the major load centers? And, of course, we're in one of the major load centers in California. We just looked at the bulk transmission requirements. We didn't worry about the little stuff, mainly 500 KB lines, the big ones that you drove under if you came down -- if you came up or down Interstate 80 into this area, you passed under a 500 KB line. We saw for the gas scenario we needed to add about 1300 miles. That's just normal expansion planning, 1300 miles of new transmission costs, about six billion. For coal, now that's the big challenge. The coal plants we located near the coal fields. They're fairly remote. That's where the transmission costs and the distances were really large. They had 7600 miles, about 16.7 billion. The surprising thing with that kind of number was that, because of the low cost of coal, you can actually -- actually the study indicates that it's not -- it's not out of the question. It's actually cost effective. Renewables, somewhere in between the gas and the coal scenario. Now, this map is a little confusing, but let me try and describe it. This is a map of the overall interconnection. It's the western United States interconnection that ends in the Rocky Mountains. There's a natural division there. And the red lines that we show up here are necessary in all of the scenarios, gas, coal and renewables. So those are the major 500 KB lines: One coming down from Canada into the Northwest; from Arizona into Southern California; and a few others over by the Rockies. Now, when you start bringing in the renewables, you add on the black lines and the green lines. And what we did, since we had a large amount of renewables all on the Rockies in the model, we saw that we needed to bring some major transmission into the Northwest, along those paths. And then the transmission actually from the Northwest down into California was adequate to bring the renewables in. Now, if you look at all the yellow lines, that's what happens if you put coal in, and you can really see a lot of additional transmission. And those dashed lines are actually major DC intertie lines, long and fairly complex and somewhat expensive facilities. But they can bring remote generation all the way into the load centers in California. But for the renewables, you can get -- you can see, okay, the green and black lines, that doesn't look too bad. You also can see that if you're going to develop the coal, you need those same facilities anyway. So what we're trying to do is promote that to the regulatory entities, the energy policy people, the transmission developers, that, you know, there are a lot of these facilities that are common to pretty much anything you do. The red ones there need to go forward. Maybe we want to start on some of these black ones which are common to coal and renewables. Maybe we want to go a further step if you want to develop all that wind and develop the coal scheme there. And that's all I had on -- on the SSG-WI study. Are there any -- well, do you want to wait for questions? MR. JACKSON: We'll take questions at the end. MR. MILLIGAN: okay. (Applause.) MR. JACKSON: Next up is Tim Tutt, and he's going to be talking about how this all fits into the California renewable portfolio standard. I don't have a bio for Tim, so he may give you a little bit of background. But he works for the California Energy Commission where he's a technical director, and he's been knee deep in the RPS for a long time. MR. TUTT: Hi. I hate to crowd the reception here with another talk, but I'm pleased to be here. I welcome you to my hometown. I've lived here in Davis for four or five years now, and it's a really enjoyable place to live, so stay away. My name is Tim Tutt. I'm the technical director of the Renewable Energy Program at the California Energy Commission. And that program has existed for, oh, five or six years now, since 1997, and we've done incentive programs for renewable energy, both home and business, installing solar and small wind all the way up to bulk renewables across the state. And as of 2002, when the RPS was passed, we've sort of taken on a major role in trying to set up the implementation rules for the RPS. I don't know if you know much about the renewable capacity in California. We have a fairly diverse set of renewable resources, 7,000 megawatts today, a lot of it wind, but I saw an earlier slide from David Hawkins -- actually, I wasn't here, but I saw his slides in the back -- but it showed 2,000 megawatts of wind today. And it's true that we've added quite a bit in the last year, and this may just be different numbers, where we get the different megawatts of wind. But I am aware that we've added 150 megawatts at least in 2003. So the numbers are comparable. And a significant amount of generation, 28, 29,000 gigawatts. About 11, 12 percent of California's overall generation comes from renewables. Most of it in-state, but a very small amount of it imported from out of state at this point in time. But solar is probably the facilities that you guys have not been analyzing from the ISO data, solar thermal facilities down in Southern California for the most part that are gas assisted in general. I'm not sure how that affects the data. We have now -- I don't know if it shows easily on this chart, but we have now 15 megawatts of good connected solar installed in California. And at least 10 megawatts of that has been installed this year; at least 40 megawatts in the last two to three years. So we have been making great strides in grid-connected photovoltaics generation on people's homes and businesses. It's still a very small part of the overall mix, but fairly fast growing at present. This gives you an idea of the widespread diversity and scope of the projects that have participated in one part or another of our renewable energy program incentive program. The green dots that you see here are all the grid-connected solar that we've had a hand in providing incentives to get installed. Mostly, as you can see, in the load centers that grid-connected solar happens in. We have the wind areas and a variety of geothermal and solar and other things across the state, biomass. Most of the renewable projects in the state at one time or another have participated in the incentive program that we've been running since 1997, '98. This is a graph that we show about the RPS. Now this actually -- Dave also mentioned something in his slides about California's RPS. It was enacted last year. It requires the utilities, the IOUs in particular in the state to increase their generation of renewable energy until it represents 20 percent of their portfolio of energy resources by 2017. And it's expected that about at least one percent per year, one percentage point of sales per year would be sort of the ramp-up of that. Since we're at 12 percent now, or 11 or 12 percent, we don't really need statewide that one percentage point every year. But some utilities are fairly low on that percentage level, and some utilities are fairly high. Southern California Edison, for example, is already very close to 20 percent of their portfolio today, if not at 20 percent of renewable resources. I want to go back a little bit further, Henry. There. Thank you. As Dave's slides earlier showed, that far end on the RPS is constrained by the amount of public goods charge funds that will probably be available and necessary if -- if necessary to reach that level of renewable generation in the state. I can explain and I will explain how that funding allocation process works or at least has been developed to date. It's fairly complicated. I often say that California doesn't have -- hasn't -- isn't -- doesn't have the first RPS in the nation, but it does have the most complicated, and it's been very difficult for us to all work the whole thing out so far. This graph chart shows us reaching the 20-percent level by 2010, not 2017. And that reflects the State's Energy Action Plan, which was adopted by the California Energy Commission, the California Public Utilities Commission and the California Power Authority to accelerate the RPS from that 2017 date to 2010. As a goal. This is not in the legislation. It's a goal of the State's energy policy agencies. And given that we're at 12 percent today and we're supposed to get one percentage point a year, we get up fairly close to 20 percent by 2010 anyway. For some utilities it might be harder to reach there; others it might be easier. But that's the goal that the State is involved in and is adopted in the State's Energy Action Plan. Some of you may be aware that our new Governor, Governor Schwarzenegger has accepted that goal as part of his plank when he was running for Governor and went further than that. He suggested that he wanted to get 33-percent renewables by 2020. He also has some pretty advanced or hefty goals for good connected photovoltaics. One of his campaign planks was 50 percent of the new homes would have solar on them by 2005. And we're -- as energy agencies, we're still -- you know, Governor Schwarzenegger's new. We're still wondering exactly how we're going to figure out how to do all these policies, but we're going to be working on those policies with our new Governor as we move forward in the next three years. This chart shows you that today, as I said, we're about 12 percent, 28,000, 29,000 gigawatt-hours. 20 percent by 2010 would require 55,000 gigawatt-hours a year. 20 percent by 2017 would require 60 or 61,000 gigawatt-hours a year. The difference is just because there's no load at that point in time to get 20 percent of the loads. And it shows you that we've identified technical potential within California for renewables of 262,000 gigawatt-hours a year, ten times really our current level and five times the goals that we have in our renewable portfolio standard. So technically there's potential out there. Economically can we reach it? What are the costs? What are the benefits? What are the barriers? That's what we've been struggling with in setting up the RPS procedures. A lot of these charts are going to be too hard for you to read. I'm sure they'll be on the web site, and you can look at them there. I'm not going to try to go through them all. I'm just going to tell you that the roles of the California Public Utilities Commission and the Energy Commission are tied together. We're collaborative staff working on the RPS, and we each have roles and missions established in the legislation. We've been working fairly well together to come together to develop the rules for the RPS. The CPUC has to identify the transmission grid implications of the RPS, establish the initial baselines which the utilities start out from, and develop market price reference in collaboration with us and a variety of other things. The CEC, we have to certify what resources are eligible. We have to develop a tracking system which involves a western interconnect wide tracking system -- in our minds, that's what the legislation requires of us; and work with the CEC to allocate -- we have to allocate the public goods charge funds in the form of supplemental energy payments for renewables that need those payments as part of the RPS. I should explain a little bit to you, if you don't know, about the whole market price reference and supplemental energy price concepts. The idea in the RPS as it was established in California is that we already have a public goods charge fund that incentivizes renewables. And so to -- well, how do we use that to foster or further the RPS? Well, what happened was we decided we'd identify a long-term market price reference. Right now, this is likely to be the cost of developing a new natural gas-fired power plant, combined cycle for base load resources, combustion turbines for peaking resources. If we identify that with a fixed energy price component, in other words, something similar to a fixed cost renewable product, we establish a level called the market price reference. And then as renewables bid into utility solicitations, if their bids are lower than that, they don't get supplemental energy payments. They don't get public goods charge funding. If their bids are higher than that and they're still winners in the solicitation, then the public goods charge payments make up the difference between the market price reference and the renewable cost. Simple enough to explain perhaps, but challenging to put in place. How do you develop a market price reference? How does it affect bidding when you develop it? Should you -- are there enough public goods charge funds available? Should you cap them? Should you -- how do you allocate them between utilities or between utilities and other obligated entities? Lots of questions that we've been struggling with and coming to some decisions on. As I said, you're not going to be able to read any of this. This I've taken from presentations that others have done on the RPS. And I -- for the life of me, I don't know how they stand up and present it, but they do. And this shows you a chart which shows you where we've gone to date. This is a schedule we laid out at the beginning of the year of coming close to the end of the year with implementation rules for the RPS. We're going to move this, I think, schedule -- it's going to move into 2004 before we're done, but we have done a variety of things on this schedule. For example, we've adopted at the Energy Commission a renewable resources development report by November 19th as suggested. The Public Utilities Commission has adopted an RPS transmission plan by December 1st. And we've adopted decisions about eligibility for the RPS or what resources are going to be eligible, how supplemental energy payments will be established. The PUC has adopted a decision in June about how -- what flexibility and compliance mechanisms there would be, how the market price benchmark would initially be established sort of on a policy level with a lot more work to develop it further. What kind of standard contracts, terms and conditions would there be? More work has been done on that arena. There's been briefs and reply briefs on that. And least cost, best fit, meaning what kinds of renewable projects are the utilities likely to need? How does that fit in? The way that the process is supposed to be structured, you have bidders bid into a solicitation, and then you add in direct costs, which are some of the costs that have been talked about here today: Integration costs for renewable resources; transmission costs for renewable resources; bulk transmission as opposed to general transmission costs; and remarketing costs if you've added resources that don't fit within your current system resources easily and you might have to sell some of the power you've already contracted for. So that's the -- what least cost, best fit means, and that's a challenging thing to work out as well. Challenges to meeting the RPS. Maintaining the existing base of 12-percent renewables. We know in California that we've got this good diverse base of renewables, much of which was developed ten years or more ago. We know that, for example, the geothermal up at the Geysers is declining over time because of the resource running -- I mean, more steam being pulled out of it than is being put back in in the form of water. Some of the things have been done up there, there's been some wastewater injection projects that inject more water back down so we can get more energy out of the Geysers geothermal field. One was just dedicated last week taking wastewater from Santa Rosa and a bunch of cities along the -- I guess it would be the west side of the Geysers, piping it up into the fields and injecting it into the injection wells to get more steam out of that field. Okay. Let me finish up for you. A lot of renewables procurement has already occurred as the RPS was adopted and before the implementation rules had been set up, a lot of renewable procurement. In 2002, the CPUC required the utilities to procure at least one percent of additional renewables in 2003. And they all went out and solicited and at the end of 2002 got contracts for renewable resources of more than 620 megawatts capacity. Much of that is existing resources that they -- that weren't under contract to the utilities and now are under contract to the utilities. But there's a significant amount of new development there, too. A lot of gigawatt-hours. Biomass, geothermal, wind, small hydro and IOUs met that goal that the CPUC required of them at that time. Now in 2003, PG&E has signed up three existing biomass contracts, and SDG&E has submitted a couple of renewable products to the CPUC for approval. And SCE has two open renewable solicitations: One in general for all renewables; and one particularly for wood waste products or projects that would help them solve the bark beetle issue that's been developing in Southern California and that has been of such concern with the fires that happened there earlier this year. I'm pretty sure that the bark beetle areas really didn't get damaged much or burned much by the fires. Had they gotten into those areas, it would have been a worse conglomeration than we had. But it was a very tenuous situation. In fact, Edison at times shut down some of the transmission lines when there wasn't a problem on them as a prevention measure to prevent fires from happening in some of those areas. In the renewable energy program, we had previously thought RPS had some options for providing some incentives to new renewable developers. We've had a significant amount of projects come on line. Today, this year, we've had six new facilities totaling 161 megawatts come on line, bringing the total capacity that we've supported, new capacity, up to 405 megawatts. More than half of the projects in our option are now on line, 60 percent, and two additional projects are expected to be on line by the end of this year, another 28 megawatts. A lot of the projects that have come on line this year are wind projects, including 150 megawatts or so up in Solano. You might have seen the Solano wind area on one of the previous charts. And I believe those projects are participating in the FERC program at the ISO, so it's going to be a good start for that program. And that's the end of my presentation, and we can have some questions. MR. JACKSON: Yeah, 10 minutes or so. (Applause.) MR. JACKSON: Anybody have questions? It's the end of the day. MR. HAWKINS: I just had one question or two questions, really, to the last speaker. It seemed like, with having to give all these contracts, there would be a large incentive then for the utilities also to build the transmission out to these facilities. Are you seeing that net effect? Is the CPUC then giving them transmission recovery rates in order to go out and connect up all of this renewable energy? And the second question I had is, is there any like program going on for the municipal utilities? MR. TUTT: Okay. First question, the CPUC I think has sort of skipped over it by sort of action, ambient action in their presentation. The CPUC did come out with a transmission study where the utilities participated, and I think the ISO participated, and indicated a certain amount of transmission costs to reach the level, the plausible set of resources that we had identified in our renewable resources development plan. And that was about $2 billion of transmission investment. And the CPUC's transmission study also concluded that since it was sort of three independent utilities identifying these, that one step would be to have that be done more on an integrated basis so there wasn't duplication among utilities in developing those transmission facilities. Certainly, there is a lot of resources that we identified in our plan. For example, the Tehachapi area, there's a significant potential for additional wind resources. There's lot of transmission work going on about Tehachapi, and the PUC and others are working to get transmission in place for that area to get the wind out. So I think that those things are progressing. I don't have a real lot of experience or expertise in exactly how all that works, the transmission area, but I think that there are going to be transmission -- there is going to be transmission built to bring these renewables to market. The second question, yes, for the municipal utilities and customer-owned utilities in California, the RPS legislation requires them to adopt renewable portfolio standard policies sort of on their own initiative that meet the intent of the RPS law for IOUs. And for the most part, that's progressing I think relatively well, although we're not following it that closely. SMUD, one of the large municipal utilities, has had an RPS advocating 20-percent renewables in place for some time now. There's obviously -- and they have control over how -- how fast and how well they develop that. Los Angeles Department of Water and Power, another large municipal utility, has been working to improve the amount of renewables they have. There's been a consultant report that just came out regarding their renewable plans, I believe. And a third of the large customer-owned utilities, Imperial Irrigation District, has a large contract with Calpine -- no, Cal Energy to develop one of the largest geothermal plants probably in the world, about a 180-megawatt geothermal plant down in Salton Sea. So they're moving there. And I think that they will -- the municipal utilities will come along with -- for the most part, with the renewable goals of the State. MR. JACKSON: Any other questions? And the report that this came from is on the CEC web site, right? I remember I pulled it down about a week ago or so. MR. TUTT: The renewable resources development plan is on the CEC web site. I believe that it's under the portfolio standard proceeding, so it would -- I think it's keyword "portfolio" for that, to get to the documents in that proceeding. Other documents are the decisions that we've made in this year and notices of workshops and hearings and things of that sort. MR. JACKSON: With that, I think we'll pass it off to Case and finish the day. (Applause.) MR. VAN DAM: Right now we have some food waiting for you and an opportunity to buy some drinks. So please stay around for the coming hour or so just for talking. Tomorrow morning we start at a little past 8:00, but we have a continental breakfast here starting around 7:30. So you're very welcome to come early and again mix around, talk to each other. And then at 8:15 we start with the next keynote speaker. Let me get the information on that. You see it in your program. So that is Lewis Milford from the Clean Energy States Alliance, and he will start at 8:15. So we look forward to seeing you tomorrow morning, but definitely also in the coming hour or two here around to have a drink. Thanks very much. (Applause.) (Whereupon the presentation adjourned at 4:56 p.m.) WEDNESDAY, DECEMBER 17, 2003 MR. VAN DAM: Good morning, everybody, welcome to the second day of the forum and thanks for being here so early. We have put an appropriate slide on this morning, it was about 45 minutes ago that it was officially one hundred years ago that the Wright brothers flew the first full-powered flight in Kill Devil Hills. It really is one of my main loves, flying airplanes, so I thought it was kind of appropriate to show the slide. But without further ado, I would like to introduce the keynote speaker for this morning, Mr. Lew Milford. He is the president of the Clean Energy Group, a non-profit based organization in Vermont. It works to accelerate commercialization of clean energy through innovative advocacy finance by private/public partnerships. He also manages the Clean Energy States Alliance, and you will hear more about that today, an association of twelve states that manage the clean energy funds throughout the US. Lew is a lawyer and a long-time energy and environmental advocate. He is a graduate of Georgetown University Law Center. He also published a book, the Wages of War, in 1989. So he is a published book author. He now lives in Vermont, and I think he has been shoveling a lot of snow lately, so that is the advantage here in California, no snow. So without further ado, please welcome Lew Milford. MR. MILFORD: Thank you. Good morning, thanks for being here. We had about three feet of snow in the last ten days, it's just been unbelievable in Vermont. We are supposed to get another one, I guess, Thursday, so it's very nice to be here for a short time to see what the weather in the rest of the country looks like. What I want to talk about is states, particularly state activity. I'm not going to talk about wind very much or at all actually. Dora said that was okay, although Terry Surles told me I guess he talked about things other than wind here last year and wasn't invited back. So we'll see how this turns out. What I want to talk about is where we are in a number of technologies, but particularly talk about what I think is an interesting development in the last several years, and that is the activity of states around the U.S. on these issues. Obviously California has been in the forefront of many of these, but I think the interesting development has to do with what many of these states are doing on these technologies around the country. Just a couple key points about where we are today. If you look at clean energy today, it's certainly growing, and I think these are some of the statistics that are actually quite interesting. These may not be absolutely accurate, it's tough to get sort of snapshots of current technology states today, but it appears that we have had somewhere in the neighborhood of maybe 28 percent or so wind growth in the last year alone. If you look at fuel cells, install base about 75 megawatts. It's hard to get the baseline of that last year. These are stationary, the larger plants particularly, but if you look globally, small scale, 5 kilowatts, in that area or above, something like 400 percent growth over the last two years alone. Obviously solar, pretty significant growths, about 35 percent growth. So those sound good. Obviously if you are operating from a fairly small install base, the percentages look very high. The real news is that the actual levels are quite low when you look at total consumption three, three and a half percent. The question obviously, nothing new to you folks, is an issue of scale. How can we accelerate scale of these technology developments over time. You know, there is some good history of this. In the plane ride out, I watched for a second time Seabiscuit. It's a great movie, I think. I actually read the book. The first chapter, I think, is one of the most interesting chapters with a short little history about the development of cars in the U.S. If you recall, the owner of Seabiscuit actually got started in San Francisco as the owner of a bicycle repair shop, and who then became the owner of a car repair shop, as most bicycle shop repair people became, and then he eventually became the largest General Motors dealer in the western United States. And it was a question of scale, use of cars actually in the San Francisco earthquake. If you looked around 1900, there were about 1,600 gasoline-powered cars registered in the U.S., the entire U.S., 1,600. Obviously the scale of that accelerated very rapidly within a very short period of time. It can be done. Every report that you have ever seen about clean energy technology basically lists these barriers, these are the big-five, business-as-usual barriers. High capital cost, nothing new there, particularly when it comes to solar, fuel cells, other technologies. Technical constraints, a whole host of interconnection issues. A laundry list of technical issues that are out there that people work on day to day. Information gaps, you know, a lot of arguments, obviously these have been made in every technology, including energy efficiency programs, customers simply are unaware of the benefits, don't make rational choices. We need to provide better information to customers in order to make more rational choices. Immature market infrastructure. For every one of these technologies, basically the lack of a real installer base. If you want to buy solar, you generally can't go to Home Depot and do it, maybe increasingly you can with some of the new piece systems, but for the most part these are one-off installations where you need customized activity. And a very very immature market infrastructure at this stage. And obviously an un- -- they call it an uncertain regulatory environment, it's probably being more positive than it deserves. A quagmire of different regulatory processes state by state, whether we are talking about stand-by charges or a whole host of issues that arguably serve as a barrier to significant growth and development of markets for any of these technologies. So those are the standard tools, but the question this all raises then to me, how do you create scale. Basically these are barriers to the opportunities, how do you overcome these to create scale. A little finer grain on the trends that, I think, underlie the discussion of these conventional barriers. I think it's fair to say that obviously the debate in the last couple of years about energy security, at least at the federal level, increasingly is turning to a pro-fossil-fuel based solution to those problems. So I think we have a tilt certainly in that direction, which tends to make it difficult to argue for these technologies as alternatives. Certainly in the U.S., not -- I'd say in Europe certainly, perhaps in Japan, regardless of what Russia does, that climate change, I think, at least at the multi-state federal level, does not yet operate as a significant market driver for technology development. And, again, I'll talk about this state by state, but I think on a larger scale if you are a major investor, it's very difficult to see how climate change is a direct driver yet for justification of major investment. Certainly in the last two or three years with the Enron debacles and every other major energy company, you can imagine the tremendous amount of insecurity in terms of what the future holds for many of these companies. It's difficult for them to make major investments in many of these areas. I have philanthropy up there because we, as others, who make arguments and argue and deal in these areas depend on foundations in a large part for support, and if we or others like us aren't around and folks like Energy CDF, then in many cases you can argue some of these issues don't get moved as quickly as they should. Foundations, again, because of the financial problems in the last couple of years are sort of facing a period of some constraint. Perhaps that might alleviate itself as the economy goes up. And also a lot of capital now is going to basically picking up a lot of assets of energy companies, basically the Warren Buffet-type pick up very low-valued assets rather than capital moving into some of these new technologies. So those are all, you know, not a good picture. Those are sort of negative trends you can argue that are out there in addition to this top five. Now, I think the more interesting story here, and I think these not necessarily are overwhelming yet, but are some very significant possible trends. I'm going to talk principally about this topic, the top topic, but I'll just touch on this today -- touch on this now. There are twelve states, and these are growing, California obviously has the largest, but of states that are dedicating public dollars to projects, companies, marketing infrastructure for these technologies. These technologies are the conventional renewable technologies, biomass and hydro and wind and also fuel cell development. I'll touch on that as well. And I think these are -- this is what I'm going to go into in some more detail later, but I think these are really critical new developments that could be very important to accelerate market activity over the next four or five years. Very new sources of money, new types of activity, and I think really needed at that level. You can argue that some of these markets are in a critical mass in that -- you folks are the wind experts, I don't have to tell you that, but as you have companies like FPL, you have Fortis Bank and others seeing wind development as a conventional profit center, then you are reaching critical mass in that technology, I would say, than the others. Obviously more states in specific more difficult to make that case than others at this stage. Potentially for some niche markets in solar you could make that case as well. But I think approaching -- you know, obviously with the scale of cost reduction approaching some positive direction there. The third point, and this may be a little contradictory to what I said before about energy security, I think increasingly, given the historical environment in wind, that energy independence, I think, is increasingly becoming an organizing principle for much of this activity, separate and apart from any environmental arguments one would make. Just to give you an aside, jump ahead a little bit, but as part of the state work we just hired an ad agency, five states in the northeast funded us to hire an ad agency to essentially try to develop and think about some new messages around clean energy. Our sense was and the states' sense was that a strict environmental message simply has not been very effective to get customers to want to buy green power, other power, to basically develop support for many of the state programs. And if you have ever seen the television Bank One ads, you probably get plastered with these credit card ads you see on television, this is the ad agency that does the Bank One ads. Bank One doesn't know it, but they are basically cross-subsidizing the clean energy project as well with all the hundred million dollar revenues that are coming through the ad agency. They did some focus groups for us and asked some pretty straightforward questions about environmental messages around these issues. What they basically came back and told us is that the environmental messages do not work, that they are seen as basically old news. And it wasn't that it's not a good thing, it wasn't that any of these guys -- you know, there was no principle involved in these ad agencies whatsoever, but their basic view was this is simply old news. That unless there are dramatic effects that you can present to a typical customer group, this simply doesn't resonate. Now, it may be different in California, but this was the case, you know, pretty broad cross-section of people in the northeast. The other thing that they found through this work is that the sense of the industry as a whole was that people didn't believe that these technologies were real or substantial in any significant way. That they believe that basically at best these technologies, meaning renewable fuel cells, the whole group, probably constitute no more than a percent, half a percent, can't be more than that. In fact, one of the people basically said that this is some sort of Gilligan Island thing, you know, you are off on an island and you make your own power. That was the general view of the current picture. When they were presented with some other facts that actually look at -- just use some typical EIA numbers, you can put those numbers to say renewables provide about 10 percent of residential load in the U.S. You can use those figures and show that it can power all Chicago. Basically you present them with a number of other images, folks are just stunned. They just have never had any sense that you can actually get to that scale, that there is a scale issue there. So the question wasn't real. The third thing that they said is that what really resonated with them was the sense of self-sufficiency. That that was really what would move them to act was a sense of self-sufficiency, not the environment. And under self-sufficiency, perhaps economic development, a few other things under that. It was very, we thought, pretty interesting. So they are developing some new ads for the states. But I just want to underscore the independence issue, I think it really deserves a lot more thinking and a lot more work to figure out what's really underneath that today. Another point, I think, in terms of the positive trends, increasingly is more cooperation, I'll talk about this a bit, between the U.S. states and Europeans, and I see a lot of experimentation. So let me shift to the next one. So the question is, I guess, in part, with the growth numbers I talked about, some of this activity I'll talk about more, is this a real shift, in the old classic term, paradigm shift, or maybe just another failed promise as we thought fifteen, twenty years ago? Is there some tipping point here? If you are familiar with Kuhn's work in paradigm, the structure of scientific revolutions, paradigm shift, everybody overuses that term. What he means by that is that what happens is that the facts on the ground are inconsistent with the conventional prevailing view. So there is what he calls a failure to fit, that there is a tension there. That increasingly you have a prevailing view of something. Right now you can argue the prevailing view that virtually everybody has, except for the insiders, is that the big power plants, whether it's coal, oil, nuclear, central generation, utility control, that is the current paradigm, the conventional view, you flip on a switch, you never think about this, it's simply invisible. But that paradigm may not be quite a good fit with the facts that are beginning to change on the ground. Some tension starting to grow there. The question is is it sufficient that at some point you actually might find a tip, are we really at the beginning of what could be this sort of next fifty-year transition, and I think we are, but that's the issue that we address. So how do we think about this? You have probably seen this quote time and time again, but I think it's really telling. I think the reason to start thinking much more positively about this is the level of activity at the states or around the U.S. This is the classic quote, about states being laboratories of democracy by Lou Brandeis, "It is one of the happy incidents of the federal system that a single courageous state may serve as a laboratory." What is interesting about this case, is that this case came up in 1932. This was a depression era case, and it was actually a utility case as it turns out. I just read it this week, and what is interesting about it is it was a case, of all things, about making ice, and this is 1932, came up in the 1920s. And think of the new innovation at the time in the 1920s were refrigerators, new refrigerators. Basically the model that we had in the 1920s was central manufacture of ice. There were companies that made ice and then had distribution systems for ice, and there was this upstart technology called refrigerators that began to challenge, you know, the existing systems that are basically ice systems, ice manufacturers. The issue here was whether the state could regulate the manufacture of ice, because ice was seen as -- by the states as impressed with the public good. You needed ice for food, for the obvious public purposes that were there. So a number of states passed laws to regulate ice manufacturers as public utilities. Sound familiar? So the conflict in the 1920s had to do with whether these states in fact could regulate this manufacturing activity to protect the public good. The opposing view at the time was the 1920s sort of laissez-faire attitude that states could not interfere with the economic system. That was the issue in this case, that was the conflict. And he was in the minority, he lost. The prevailing view in the case at the time by the majority of us that, I think it was Oklahoma, had no power to regulate the manufacture of ice for the sake of the public good. There is a funny little discussion in here about this new technology, refrigerators, at the time five or six or seven years old, and how that was sort of -- that you should allow innovation to occur and shouldn't regulate this technology. In any case, the point is that I think what is increasingly happening is that you have many many states beginning to follow this approach, that innovation and technology development, market development. States are really the key, and particularly around climate change and greenhouse gas emissions and clean energy technology and that's really what I want to talk about. In fact, it was sort of ironic, I don't know if you followed any of the press from the Kyoto discussions in Milan last week, but the Bush administration's position is that the states are really doing it all. The states are really in the lead on climate change, and so it was an argument in why they felt that they could stand back and let the states rush ahead and solve the problem. You can have a different view on that, but it was a sort of interesting point that I think highlighted, even at that level, that states are in fact taking the lead on many of these issues as they do and as they did in Brandeis's time when the federal government basically is not stepping up to the plate. You know, at that time, in the 20s, was not stepping up to the plate on economic issues, and today you can argue on environmental issues. Flip to the next one. The way this is starting to happen, I think this is sort of the context that I'm really getting to, is through increasingly networks of innovation. This is actually a quote from a professor that teaches here that you will meet later, named Hargadon. It's a very interesting book about what he terms networks of innovation. His thesis basically is that many of us think of technology as sort of lab venture activity, this is all science, this is all R&D activity. His point is very different and his point is that technology basically moves from the lab to the marketplace through social networks. It moves -- and you are a social network around wind, obviously. This is sort of a conceptual framework for this kind of collaborative activity to identify barriers, identify problems that exist and then work together to overcome them. This basically is the framework through which most every technology makes its way from the lab to a commercial state. And I think it's a very telling way to start thinking about clean energy technology as well to move to levels of scale. You know, they talk about a couple of things that we are doing sort of background to this that California is actually a part of that I think, you know, could be an interesting way to begin to move these technologies in a more accelerated fashion. The first is something called Clean Energy States Alliance. Many of the states -- California, you've had your system benefit charge and your funding in place for some time, but for many states this is a pretty new endeavor. And for the most part, dedicated funding for clean energy technologies was a result principally of restructuring legislation in the northeast. If you look to states like Massachusetts, Connecticut, Rhode Island, Pennsylvania, New Jersey, dedicated funding for these technologies came expressly out of restructuring negotiations. I did a lot of these negotiations when I was with a different organization that basically, as an environmentalist, agreed to many of these structures in exchange for public extraction of dollars, and public extraction of dollars had to do with creation of system benefits when I was there, and obviously investment needs as well. And I want to touch on the fuel cell alliance, another of -- you guys are going to be talking a little bit about storage, I guess, and maybe hydrogen later, so I want to touch on that. I'll go to the next one. If you look to -- you can't read this very well, but I assume you can make these available. There are about twelve states now that have benefit funds in the U.S., and these are typically the states that have always done some progressive energy work over the years. They are concentrated in the northeast, in the upper midwest and in the west and in California. These are the states that have these funds and that are now -- we have created this -- in effect it's a trade association of all of the states that have these funds. And the thinking behind this is that, you know, each state alone can do extraordinary work, but if we could actually begin to work together on common issues, on joint projects, sharing information, developing new approaches to move these technologies, that we can actually start acting as public investors, just like private investors. And private investors, VC investors, never, ever work alone. It's too risky, and basically you, again, don't get the scale of investment. And so the thinking is that the same kind of approach should be thought of when it comes to public investors. Because after all, these public funds, system benefit charges here and in other states, are public dollars and one of the best things you can do with those dollars is to leverage them so that you are not individually, state by state, trying to solve the problem that is common to every state. And I'll talk about some of the specific projects, but that is the basic thinking here is that don't duplicate, try to leverage these dollars so that you can solve these problems in common, but then perhaps more importantly, think of these challenges as national challenges, which they are. These are regional markets in many cases, but they are national problems in the sense of building solver, of accelerating activity, dealing with fuel cells. I mean, the companies look at these certainly as national markets with individual state players, but their view is to accelerate these markets wherever they can. So if we can start moving, getting the state players to start thinking along the same lines, I think we can actually start accelerating activity much faster than we can if we were inside working individually in insolation. So that was the basic thinking. So these states came together and actually now are funding this activity as an alliance, and we'll talk a little bit about just background, how much is there and what's going on here. Just to give you a sense of scale, this is from an article we did with Ryan Wiser at LBL. The dollars are pretty significant. If you put all the states together over the next seven to ten years, the scale of money is about three billion dollars, and these are just the renewable dollars, the clean energy dollars, not the efficiency dollars. As you know, many states have dedicated energy efficiency dollars as well. This is simply on the renewable fuel cell, quote, clean energy side of the house. So the dollars are quite significant. You can take the next one, I'll just break these down a little. You may not be able to read these very well, but this is a state-by-state breakdown. Obviously, you know, as usual, California, the largest, tends to skew the total numbers, but the others are not insignificant. If you look to a state like Massachusetts. Massachusetts will generate about 25 million dollars a year through their system benefit charge. Connecticut, a little bit less. They took a bit of a hit during the budget crisis. Some of these states there is a little bit of pressure to go after some of these funds for these purposes. New Jersey is actually the largest. New Jersey is up in the 30 million dollar range or so, 30 million a year, and others you can see, you know, different numbers in the remainder. But for the most part, these are not time limited. That is, they don't terminate by legislation. It's interesting, in California you have to understand that it's a ten-year legislative extension of your SBC, in -- I want to say in virtually every other state they have passed their approval date. That is in Massachusetts where we set this up, is that if the legislature did not say no after five years, it continues indefinitely, which is the case, and they didn't say no. And it's the case in Connecticut and, I believe, in New Jersey. So for the most part, legislatures in most of these states would have to affirmatively reduce these numbers or discontinue these funds. So there is at least some sense of continuity here, which is pretty important. Let me tell you about what they do, a lot of the same things that you do here in California, but just to give you a sense of what I think is a diversity of activity here, which I think is most interesting to me, when people think about these funds, typically they think that the dollars go to subsidies, and many of them do. You know, that it's simply, you know, kilowatt hour buydown and that's the beginning and end of the game, that's all they do, but they will actually do a lot more. This is where I think there may be some interest in modifying many programs that are out there. Certainly there are subsidies, give you solar for example. Typical, there are capital buydowns, there are production incentives for solar. But if you look at a place like Massachusetts, it's also funding the trade association and it is also making actual investments in companies. And this is the interesting development that I think is really worth looking at much more seriously by many other states. Increasingly what these funds are seeing themselves as is economic development agencies that have, you know, an environmental mission in part, but also have a mission to build a local industry base, whether it's manufacturing or installers or anyone in the value chain for the technology. So states like Massachusetts and Connecticut and Pennsylvania are actually making equity investments in companies with these public dollars. And we wrote the legislation to make sure they could do that. So it's actually perfectly above board to do it. And they have hired -- and you will see in some of these states more MBAs on staff than environmentalists. That's increasingly sort of the trend you're going to start seeing in some of these states. Not all of them, I think it's the minority of them, but I think you'll start to see more of it. New Jersey doesn't take an equity stake in companies, but it has a loan program for companies, and other states are beginning to look at this. So I think it's worth -- just you should know this, and I'm not sure what the opportunities are here, but that's what's happening. If you look at technologies like fuel cells, some of these states are actually funding feasibility studies, economic feasibility studies, typical feasibility studies, preinstallation-type activity. There is a lot of green building work, and I'm sure you guys are doing that here as well. Massachusetts, for example, actually pays for the incremental costs for all architectural and design work over and above conventional architectural design costs for non-green building, and then picks up additional costs for capital installation for those buildings as well. Lot of public education work, fair amount of kind of strategic market analysis, where are the markets, how to overcome the barriers to those markets, a lot of niche-market work, and, as I said, a lot of basic business development activity. So if you start to look at some of the programs in many of these states, they start to look more like your economic development agency that happens to be focused on clean energy rather than your typical state agency that supports environmental technology. But as I said, if you do it alone you could have some very good success, you may have much more success if you actually work together. What we found in the last two or three years is actually very little multi-state coordination on serious deployment issues. There is a lot of activity multi-state on policy discussions, you know, NASEO groups and NARUC and other organizations that basically are regulators, that deal with policy issues, and there is a fair amount of coordination and activity around R&D, but not very much on straight deployment. By deployment I mean real projects, financing problems, real barriers to deployment of technology and also, obviously, company and market development work. I mentioned the public education piece, I'm going to talk on fuel cell alliance. We are going to go across. We're doing basically a multi-state project, just hired a consultant, Firms Energy to try to do a generic monitoring evaluation piece. It turns out that each of the states has done some monitoring evaluations, basically developed metrics for its own programs, and some -- California has done a lot, New York has done a little bit, many states have not done very much at all. Our sense is that this may really require a different set of metrics to judge success. It may look more in some states like economic development metrics and less like environmental metrics or some combination of the two. Not clear how you judge your success in this area when you are really talking about market transformation. Not like market transformation energy efficiency side, but with very different types of technology and supply side. A lot of very complicated issues about how one uses state dollars to finance projects. There are a lot of options out there in addition to straight subsidies, debt equity, if you have the ability to do that. And this is all a new game and how you do it in a way that actually attracts rather than detracts from the project financeability. Lot of issues with green tags that cut across multi-states, how tags actually work, how it could be used, how you could accelerate those markets, how you can overcome a lot of the barriers that now exist with different technology eligibility standards that tend to log transfer tags across state lines. Offshore wind, there is a lot of interest in the east because of the shelf with offshore wind developments, and very controversial projects out there as well. One in Massachusetts in particular. One piece of advice is probably don't try to cite a major wind project near the richest people on the planet. That is probably not a great opening strategy. They tend to like hiring lawyers, and they are very creative in raising a whole host of issues. So the Cape Wind Project, which I'm sure you folks have followed, is quite a case study in siting offshore wind projects. But having said that, there are a lot of other states, New York, Carolinas, New Jersey that are very interested in this. And, again, it makes little sense to simply go off on your own to figure out all of these issues, whether it's siting and finance and development, you name it, a laundry list of issues. So we are trying to bring together all the eastern coast states, and maybe some west coast states, depending on the opportunities here, much like is happening in the UK, much more coordinated set of activities in the UK, people are thinking about these issues on a coordinated basis. A lot of fragmentation it seems here in the U.S. Community wind the same way, a lot of the efforts in the northeast, because it's very hard to site large projects, to do smaller scale European-type projects. Obviously the issues have to do with finance and siting, you know, you name it, but they are all very generic-type problems bringing a couple of states together. STAC homeland security. I wanted just to touch on this, and then I can go through all of these a little more. With California and New York, Massachusetts and Connecticut we had a proposal in to DOE to take a look at critical public facilities. That is, to look at the opportunities to use clean energy technologies, whether it's solar or fuel cells, in critical public facilities. Meaning 911, telecommunications-type support, emergency preparedness, you know, a whole range of things that -- facilities that are key to emergency preparedness. In fact, there is a wonderful little report that came out of the New York City mayor's office on the effects of the blackout in August. It details a whole litany of failed diesel generator situations, from hospitals to 911 facilities. For a time one or two of the boroughs had no 911 calling capability because the batteries for the repeater stations failed. So there are a whole number of ways that these technologies could make sense. They actually were suggesting perhaps using solar for traffic signals, because one of the other problems that happened there was that when the traffic system failed, hospitals could not get delivery of diesel fuel for backup generators. They almost just got to the point of going through their existing supply, and that would have been pretty disastrous if that happened. So a lot of interesting opportunities here that folks like homeland security and state homeland security folks are looking at. One of the last things is solar. We met with a lot of the solar industry folks a couple weeks ago when we met here in San Francisco, all the states, and we are beginning to pull together all the key solar industry players, BP, Shell and others with the state funds, a whole host of issues that if you dealt with the industry as a whole -- states as a whole, you might be able to overcome much more quickly than you can in kind of a state-by-state knock-off situation. Let me just mention one spinoff of this, and I know my time is up pretty soon. MR. VAN DAM: You are okay. MR. MILFORD: I'm okay? We spun out another effort to pull together states that have fuel cell and hydrogen infrastructure programs. I know folks here like Joan Ogden and others are interested in this. If you look at this map, you know, it's an amazing array of states that have either existing programs, dollars for fuel cell support or hydrogen activity or want to. And, you know, a number of these are want-tos without any real money, but there is interest in trying to do something, whether it's Montana or New Mexico or others. This is an effort that has been funded by actually the DOD and DOE will be funding this to start pulling together all of the states that -- on the public side, basically the public managers of these programs. Again, it makes little sense to try to create the hydrogen economy state by state by state without a much more coordinated activity. You know, you guys have done a lot of good things here, but think of the capabilities that are out there if you could actually work on a larger scale and leverage each other's dollars. If you'd hit the next slide. Just to give you a sense of money, this isn't much, but it's hard to get this data, this is as of last spring, I guess, spring, early summer, somewhere between 100 to 200 million dollars nationally just at the state level going to fuel cell and/or hydrogen structure activity. That probably underestimates the number. It's not insignificant, particularly when you look at DOE budgets declining it's a fair amount of dollars here. Just the next one, I'll just quickly go through this. We developed a business plan on this, feel free to take a look at it, sort of an information clearinghouse, a number of joint projects, partnerships with industry, and I think an awful lot of international networking opportunities as well. And the next one as well. One last point is that we have also begun to bring together a lot of private investors. You know, this is a big capital problem as well. If you are going to get scale here, we need to have a tremendous amount of private capital moving into this industry. And there is not enough public money to subsidize your way into the commercial scale. So you have got to figure out a way to leverage the private sector. So we are beginning to bring together venture capital firms with the state funds, discussions with foundations, maybe foundation investments and endowments and some international funds as well. We'll see where that goes, but there is also a pretty nice report that was done based on that as well, nonetheless. You know, we have been here before. I mentioned, you know, I think in 1903 there were two million horses that were the main mode of transportation and something like 1,600 cars. 1890 when Edison -- if you have ever read Edison's history of developing central electricity, we all now today think, well, it must have been pretty easy, he came up with a great idea, electricity was wonderful at the time. Well, in fact, what his general counsel said at the time is that no one wanted electricity, that we had to create customers because they were perfectly happy with what they had, basically gas, oil, other methods of providing illumination, and that they faced a huge challenge to convince people that central electricity was a preferred alternative. And at the time, 1888, 1890, his power cost 22 times the cost of the -- basically of gas, of local gas that was provided. 20 to 22 times. Sound familiar? These are comparable challenges you can argue. And think back at that time, you know, much less sophistication about how these things actually occur. It was much more difficult, you could argue, to accumulate capital to move these technologies. And much less -- you can also argue, I think very strongly, that the social reasons and the environmental reasons for doing it just weren't present that are present today. So there are many other reasons to argue for much more accelerated development of technology. But I think scale is critical. You know, bottom-up implementation, multi-state activity, that that's how it's going to happen. And then eventually the feds will come along, I think as they have with all kinds of other activity, but I think we are going to have to prove the case at the state level that there is money to be made, benefits to be had and eventually the feds will come along. It will tip over at some point, and that is probably how this will happen. And it may not be a bad thing that given what we have operating in D.C. that you have a lot of incentive for a tremendous amount of state activity at this point. It may be a good thing. It may be a small silver lining in this. So, sorry not to talk about wind, but I hope it was helpful. Thank you. (Applause.) MR. VAN DAM: Questions for Mr. Milford? Again, because we are transcribing everything, just please mention your name. MR. SMITH: My name is Don Smith. In your talk you mentioned, you and I know a lot of other pro-environmental people making alliances basically with the restructurers because of the inclusion of clean energy funds. Now, in California the deregulation has been a major setback for renewables, and even with recent gains, the percentage of renewable energy is still lower now than it was ten years ago. And of course R&D for renewables was gutted, although it's being replaced by CEC, and I wonder if you see a logical reason for making alliances with deregulators or if it was more of opportunism since you thought they were going to happen anyway, and do you still believe that's a good strategy? MR. MILFORD: I do, and it wasn't opportunism at all. You know, we did it a little differently than you did. In fact, we looked at California and said we are not going to do that. If you look to how we restructured it in the northeast, we didn't basically throw customers to the spot market. I mean, it was a conscious decision to structure those markets quite differently. But I don't want to get into the restructuring thing, that will get us into a long discussion. The main reason we supported it, I was in an organization called Conservation Law Foundation where we renegotiated all the restructuring laws in New England. The basic thesis was this: the utilities in our view cannot, at least would not, innovate. That basically every decision that had to do with clean energy technology was a political decision, and if we were to be successful at all to encourage greater investment in clean energy, it had to be done through utility rate cases, which typically we lost. So the bottom line was -- and I did a lot of rate cases over the years, and, you know, for the most part the utilities always had the upper hand on those issues. It may be wildly different in California, but basically we couldn't get much investment through utility regulators because rate impacts always trumped new investment, and the utilities simply couldn't innovate. So our view was blow it up. That you had to create new avenues for capital to move into clean energy technology, and that you had to get new investment. Every dollar of new investment basically was a dollar in clean energy technologies because we were stuck with the incumbent system and we were never going to get change through the regulatory system. So that was the basic thesis that we had, and I think that it is still a valid one. It hasn't worked out as well as we hoped, particularly in the northeast, but I think the premise is still valid. The activity that you see in the last three or four years, I think it wasn't just politics, you know, I think it has -- restructuring in fact has opened up many many possibilities, and I think there is an argument to be made to sort of reshuffle the deck, and I think what restructuring did was reshuffle the deck and created more political and other opportunities. You know, it hasn't solved all the problems, but I think directionally it has opened up the game. Whereas before, everything had to be done -- if your utility said no, it was a no, and that was the end of the game. And if you have ever done rate cases, they are the most frustrating exercise in the world to get anything done. At least that is my view. But that's a big discussion. MR. VAN DAM: Any more questions? UNIDENTIFIED SPEAKER: I really appreciated hearing your concept of aggregating regionally on issues of commonality related to market development and your matrix there and multi-state projects, and you almost indicated there is something like that in the northeast, seems like many of the states, they work together, I don't know if there is a regional group. MR. MILFORD: It's actually through us. It's the northeast states and the western states, the upper-midwest states, they are all working. And what is happening is that for some projects, some efforts, there is a subset, you know, that has an interest in something that others do not. For the public education pieces the northeast states came together for that because there was a sense that they all had an interest in coordinating some kind of activity. What is happening there is that they share media markets. In New Jersey, New York, Connecticut, typically the television, radio, media markets all spill over. The sense was that it doesn't make any sense if the states were going to do public education efforts of any kind, and some had done a little bit and are thinking of doing it again, that they had different messages that would spill over and basically counteract each other, it would be very confusing. So we said, look, let's -- you know, let's at least see what the right messages might be, and see if we can develop a common set of messaging and media materials. So this ad agency is actually going to develop a generic set of print, radio and television ads. And it may be that the states will go ahead or they may not, I don't know. We are only at the point of developing materials. I don't know if that answers your question. SAME SPEAKER: The concept I think is wonderful. The whole thought of western states aggregating or organizing a regional group that would address issues similar to what you're doing. MR. MILFORD: Yes. SAME SPEAKER: I have -- not that I agree, but I have heard that there is concern that it would usurp state authority, that the states would begin to lose some possible influence, that they would start to lose control over a lot of what might occur within their given borders, and that would make them feel uncomfortable. Would you see a role for the state governments? If so, would they all sit on this board? What do you envision that -- you know, I'm kind of asking for a vision of what you see might happen here in the west. MR. MILFORD: Just as a practical matter, what is happening is California is a part of this, I guess it's held up a little bit through some of -- you have a few budget problems, I take it, out here, so some of the contracting issues are taking a little longer, but CDC is going to be an active player in this in Oregon. I'm going to actually be in New Mexico tomorrow to talk to those folks about it. This can work any number of ways. What we have done is basically created -- it's a spinoff NGO that is kind of an umbrella for all of these state funds. So what we are doing is trying to get as many of them in that umbrella as possible. Then once they are there, there are some projects it makes sense to do nationally, like the monitoring evaluation piece. Everybody has got those problems, there is nothing terribly regionally specific about that. So that is something that could cut across all of the states. Public education is different. There may be other western -- and I know there are, western issues that are specific to this region, that if you could actually combine them on a much more practical deployment market development side, you could develop a plan of activity there. So it's a very flexible process and there is nothing rigid about it. Maybe the undercurrent to your question is a number of states are always concerned about giving up autonomy or in other states there is a concern about economic development interests. You know, once you start talking about economic development, often states tend to be pretty competitive -- or they can be pretty competitive, but I think overall the consensus so far is that the generic issues dwarf the competitive issues. There are so many problems that you have to address that you should be addressing together, that they overwhelm the smaller subset of potentially competative issues where you shouldn't be working together. So it's wide open. I don't have a specific answer, but I know, you know, CDC folks, I think, are intrigued by this a little, as well as I know the folks in Oregon are. MR. VAN DAM: One last question? Questions? UNIDENTIFIED SPEAKER: Back when we were starting the Public Interest Energy Research Program at the energy commission, we were looking at what happened in Europe and how much money goes into deployment and research compared to the gross national product, and then we looked at what was happening in California, we said there was vast differences. I'm curious about, first off, having looked at how your -- you put it on a per capita basis, it would be very interesting to see how the investment total for CESA compares on a total or cumulative state gross product for those states. MR. MILFORD: Yeah. SAME SPEAKER: And then secondly, is there something prohibiting CESA from acting as a proponent for renewable interests in Congress? I think we have seen a lot of individual states or private industries needing earmarks from DOE, and I'm wondering about the capability for Susan Ashe (phonetic.) as a proponent to carry a full renewables portfolio? MR. MILFORD: Good questions. On the first question we haven't done that, but it will be interesting to do. I'll make a note of that on gross product. On the second, I think we can. Some states have begun to ask us to do that, to see for some projects if we can help get earmarks for certain efforts, and I think it's worth trying to do it. We just haven't been scaled up to do it. Trying to avoid doing too much lobbying. We don't really have a lobbying arm so we have got to be real careful with that with restrictions. But I think in terms of the funding issues there is a real potential, I think, once you have a group of states working together. What we are finding, for example, on the fuel cell piece, that DOE really is very interested in this because they see it as kind of a distribution arm to get to the states on some common issues where they don't have the capability to do that. So I'm hoping that we can grow into that. It's a good question, thanks. MR. VAN DAM: Thanks very much. I hate to cut it off at this point, but we have to move on with the program. Thanks very much, Lew. MR. MILFORD: Thank you. Thanks a lot. (Applause.) MR. VAN DAM: Without further ado then, I would like to introduce the next panel moderator, it's Dora Nakafuji. Dora is the lead for R&D for wind at the CDC. She wears two hats, she wears her CDC hat this week, she is also a research engineer at Lawrence Livermore National Lab. She received her PhD from U.C. Davis two to three years ago. Without further ado, Dora. MS. NAKAFUJI: Thank you. Do we want to first introduce the panel? MR. VAN DAM: Yeah. MS. NAKAFUJI: We have three speakers today that covers the topic of wind and storage and integration issues. Why don't I first ask them to come up into the panel, and then I'll have a couple announcements before we get in to the actual presentation. The first speaker we'll have is Alan Lamont from Lawrence Livermore National Lab. The second speaker we'll have is Joan Ogden from the U.C. Davis Institute of Transportation and also the Department of Environmental Sciences. And our final speaker will be Scott Flake, superintendent for project development engineering at SMUD. First off, I would like to compliment the SeaWest staff for organizing this excellent forum and program. We have some high-caliber speakers and I think the program is arranged in a way that we have ample time for interaction and discussion. So that is very important, sometimes we feel so rushed in these conferences you don't really get some face time. Last night's activity was a very successful event. I feel I'm still kind of wired from the four brownies that I had during that. Anyway, from the commission and the PIER perspective, this collaborative serves as an important extension of our activities, and it provides a two-way communication conduit from the states' perspective and also from the industry really to provide interaction with what is important with the industry and to provide that feedback direct to the commission to better help and focus and align our R&D programs that will help R&D research and also market penetration issues. I just have a couple of announcements that are more related to the PIER Program before we get started. One thing, I don't know if you are aware, but early or late last summer there was a solicitation of energy -- electric energy storage solicitation that went out, a 3.5 million dollar solicitation released by the PIER Program on storage and demonstration, and I'm happy to announce that early December the NOPA, the notice of proposed award, was released on the bulk solicitation storage and the contract manager for that is Pomona Carney. If anybody wants to find more information on that, come and see me. The bulk solicitation award is three program proposals, and that includes the City of San Francisco, City of Palmdale and the PG&E utility applications. And out of the three and a half million dollars, a million dollars went to the City of Palmdale directly for a demonstration program for an ultracapacitor switching technology. It's a storage -- it's a pseudostorage kind of that allows wind integration at the BG level, and it basically allows for uninterrupted transition from a microgrid wind-supported system to connection on and off the grid. So keep an eye on that application, in the coming year we will be providing some status and update on their performance. We'll also be releasing a low-wind speed solicitation. Low-wind speed technology coupled with a storage component early next year. So keep an eye out for that, that will be coming up. Without further ado, let's get back to our wind and storage panel. The problem with integration and wind intermittency, you can't continue to ignore that problem. It's becoming a bigger issue, and with the increasing wind penetration throughout the nation, as well as our California RPS within the state and our off-shore accelerated integration of 20 percent by the year 2010, the community really needs to start addressing some of these issues. The challenges upon us at the wind community to evaluate this situation, the problems, really to understand what the integration issues are. Expand and build on their infrastructure, learn from other industries and also start beginning to take some action for strategies and formulating a plan to take the next step. I don't know about you guys, but I think I'd rather be on the leading end of things than left in the dust of following somebody else's footsteps. And I think California is poised to take the lead in some of these actions. So today's panel, we have gathered some experts and they are here to provide some insight on some of the relevant obstacles that the research industry is facing in terms of integration of storage technologies, and more importantly, identifying some strategies and leaders in the direction that this technology is going. So I'd like to introduce Alan Lamont from Lawrence Livermore National Labs. He works in the area of decision sciences and he will be presenting on the economic perspective on backup generation and storage on improving the economic value of wind. Now, this will provide some perspective on how these technologies can be integrated and also to identify some R&D aspects for development. So cost is definitely an issue and we are not saying that, you know, we are ignoring this. So definitely we want to raise the issue and throw it out to the communities and what can we do next. MR. LAMONT: Good morning. I want to report today on some white paper work that we did for the wind consortium trying to understand the extent to which backup generation or storage could improve the economics of a wind generator. And we are basically trying to look at how this would benefit a wind generator operating under a firm capacity contract. Now, I'll compare that to operating without the backup or the storage facilities, and we also need to compare the economic performance of this backup or storage arrangement to the economic performance of an intermittent resource contract. Now, just to set the framework here, we evaluated these things from the point of view of the owner of the wind generator, and we're basically going to look at this as a rate of return problem and trying to understand whether or not adding these additional facilities to a wind generator would improve the rate of the return to the wind generator. I have to warn everybody that this analysis is fundamentally optimistic. We used assumptions throughout which tend to favor the backup or the storage and make it look a little better than it might actually perform in real life. We did this, as you'll see, because the performance financially is pretty marginal and so we are trying to see if there is any way that this can be brought up and made to be a significant benefit to the owner. I'll talk a few minutes just about the basic data and then we'll talk about the financial performance of the intermittent contract, because that establishes the benchmark for the rest of the analysis. Then we will go and talk about the backup generator and storage. And the backup generator has two basic questions, and that is, how should it bid and then we'll look at the financial performance of a backup generator as a function of the capacity that is installed to try to understand a combination of the optimal bid and the optimal amount of capacity that might be installed. Then we'll look at storage. We have a few questions about how does it actually work and how do we actually do the financial accounting for a storage facility to try to make sure we are comparing apples to apples. Develop an analytic framework, which is more or less technology-neutral. The results of the study can be used to evaluate other kinds of storage, not just the few kinds we looked at here. Then we also found that the value of the storage capacity is definitely a function of the capacity or the size of the storage facility. So we'll look a little bit at that. The intermittent contract is really the benchmark that we are looking at here. Under the intermittent contract, the intermittent generator bids the expected power and he is paid every hour for the power that he generates at the current system price. Cumulative discrepancy between what he bids and the actual settle up periodically. I'm sure you are familiar with that. We did a quick analysis of the intermittent contract basically taking wind generation from a sample wind generator hour by hour, taking the corresponding price every hour, looked at the revenues that wind generator would earn under the intermittent contract, looking at the capital investment and other costs. Trying to come up with this, for the purposes of this study, if you invest in a wind generator under an intermittent contract you would have about a 14.1 percent rate of return. So this is the benchmark that we are going to compare everything to it consistently with the way this analysis is done. When we come around now to firm capacity contract, we are going to evaluate storage and backup generation under the firm capacity contract to try to understand how all that works. We have to have sort of a simple model, and keep a simple model in mind here about how this is going to work. And the way we model it, the owner bids a power level each hour. When the wind blows and you get some level of power from the wind, if the wind power is greater than the amount that was bid, the owner is paid for the bid. Simple. When the wind power is less that what was bid, the owner under the rules is paid for the bid, and then a penalty is subtracted off of that. So that's the basic model here. Now, our question then is basically given this kind of framework we're operating, can this kind of contract work better when one has backup storage or an intermittent -- backup generation or storage. So we want to look up at the backup generation and look at how that works, and how that fits into the analysis. Our decision process is slightly different. The owner bids power, the wind blows, the wind is either greater or less than the bid. If it's greater than the bid, he's paid for the bid, that's fine. If the wind is less than the bid, the owner runs a backup generator to generate all or part of the shortage. Now, if the backup generator is small, there may still be a shortage and the owner may still pay a penalty, but if we look at this way, the owner has a couple of questions they have to answer before they get started on this thing, before we can really analyse this. And the first one is what power level should the owner bid every hour, and the second question is how big of a backup generator should the owner buy. Now, you have to adjust these two questions before we can really correctly analyze the economic return of this kind of an approach. So first question, we'll just turn to the optimal bidding strategy. Now, an intuitive, reasonable strategy is to just bid your expected power each hour. You know, I think that people immediately think it's got to be somewhere around there, and in fact it isn't too far from that, but that is not really an optimal strategy. We look at this problem, it's really a decision problem under an uncertainty. You have to decide what you are going to bid and you are uncertain about the power level that you are going to realize from the wind, and therefore you are uncertain about what you are going to get paid, you are uncertain about the penalties and so forth. But this can be worked out in an analytic framework. And we found the analytic framework that gives you a set of decision rules that will maximize the long-term expected revenue from the operation of this plant. Now, I won't go into the details of it, but the level of the bid each hour depends upon the probability distribution over the wind power that you are going to actually realize. It depends upon the cost of running a backup generator. It depends upon the price of electricity in the following hour. That determines both your revenue that you are going to obtain if you do generate, and that also governs the penalty you are going to pay if you don't generate. So to do this in the study, we developed a simple statistical model of wind and wind forecasting, and then developed the analytical equations for the optimal bid and applied those throughout the analysis. Just a few pictures of how this thing turned out. One question was looking at, you know, something -- a backup generator that looks something like a combustion turbine. That is probably the most practical sort of thing for a wind generator to have on the site. Capital cost, cheap; $3 a kilowatt, pretty high operating costs. So we looked at the rate of return here on this system as a function of backup capacity. So here is our backup capacity on this axis, and the rate of return on this axis. Our target or benchmark is about 14 percent. This is what you could get if you operate on an intermittent contract, and if you are working with a backup generator that doesn't reach that level, then probably you would just prefer to have an intermittent contract. And this example, it doesn't reach that level. The green line here represents the rate of return if you bid expected power. You know, this is -- as I said before, this is fairly reasonable, but it's not quite optimal. If you bid expected power, you know, your best thing to do is to have no backup capacity at all. If you have backup capacity, your rate of return declines. That is more or less the same story if you bid -- make an optimal bid, except that you are sort of indifferent between having no backup generation and having a 10th of a kilowatt of backup generation. I keep forgetting to mention, this whole analysis is done in the context of looking at an owner that owns a 1 kilowatt capacity of wind generation. So it's a 1 kilowatt system. So a 10th of a kilowatt then has a backup capacity of about 10 percent of the peak wind-generating capacity. This graph down here looks at the fraction of energy that is bid which is not actually delivered. So if you bid over the year, you know, 1,000 kilowatt hours, this would say that with no backup capacity he would fail to deliver 20 percent of that or 200 kilowatt hours. Now, as you add backup capacity to this system, the fraction of energy bid that is not delivered declines, but we notice here it doesn't go to zero. Now, under this circumstance, even though he has enough backup capacity to cover the entire wind-generating capacity, it doesn't go to zero simply because there are many hours during the year where it's just cheaper to take the penalty rather than run that generator because that generator has a pretty expensive operating cost. So that comes out of the analysis. This combustion turbine, you just may not ever cover all of the bidding that you made. Another example is taking a generator with different characteristics. This is something that looks more like a combined-cycle generator now. Let's leave reality aside for a moment, in principle the generator should be co-located with the wind farm. It may not be likely that you are going to build a combined-cycling generating plant at the wind farm. You probably could put in a combustion turbine. This may not be that realistic, but nonetheless, we wanted to explore the way this might work out. So taking an example like this, a higher capital cost, again this may be optimistic, but a cheaper operating cost, four cents a kilowatt hour. Here we find that the installation of backup capacity does improve the rate of return on the whole thing, and adding a backup capacity of about .2 kilowatts or 20 percent of capacity does seem to beat the benchmark. Not by a lot, but it does seem to beat it. Adding too much capacity gradually hurts you. The optimal bidding strategy, expected power bidding strategy doesn't help much. The other thing to look at here is the reliability of this system, and it's not too bad. If you install about a half a kilowatt of backup capacity, you essentially cover all of the bid energy, and you could be viewed as being a very reliable generator. And now half a kilowatt of backup capacity is more than your optimum, but it's not -- but the difference in rate of return is not very much. So you are not giving up very much to install that much capacity. This suggests -- and I don't really know the realities of how regulation and so forth works, but this suggests that the generator might be eligible for capacity payments, which obviously would help quite a bit. So we just threw in arbitrarily a series of capacity payments, and a person could argue about how much the capacity payment could be, and I can just go to the chart and look up what the rate of return would be as a function of those capacity payments. The bottom line is zero capacity payments, that corresponds to the line we just saw, and then at $10 a year per kilowatt of installed capacity here. Your rate of return might increase to close to 16 percent and on up. This is $50 a year, which I gather is, you know, unrealistically high, this bounds the range of capacity payments one might talk about. And again, we note that, you know, you do have to add more than the optimal amount of backup capacity in order to achieve a really high level of reliability, but it doesn't really hurt you too much on the rate of return. So it sort of looks like this optimistic view with a combustion turbine, you know, has a chance of giving -- being favorable compared to the intermittent generator. So we move on and talk about storage and trying to understand the benefits of that and how a system might be configured. You know, some people have promoted this as a long-term solution to the intermittency of a wind generator or something else. Storage has two roles really; one is arbitrage, buying low and selling high. So whether you are connected to a wind generator or not, you can use a storage device to earn a return on buying wind energy and selling it, and one would naturally do this if you own a storage device connected to a wind generator. And then of course obviously you would use the stored energy to cover any shortages in the wind to make your wind generator really reliable. The question is is it really a good solution. We looked at a couple of different things. One is we looked at a storage system that looks like a battery storage, and then one then that looks more like a pumped hydro storage. These have very different capital and operating cost structures. Then we also looked a little bit at large and small storage systems, and it turns out the rate of return does depend on the size you are assuming. In structuring this analysis, you have the storage and the wind generator actually working back and forth, working together, and the benefits and costs are accruing in different components in the system. You have to be careful that you don't double-count or leave something out. Basically the wind generator operates -- it sells power to the grid, it pays the system marginal costs. Whenever it's generating more power than it bid, which you would normally have to dump it, passes that to the storage device, and within the internal modeling here that goes to zero cost to the storage device. The storage device does arbitrage buying and selling, but also it covers the wind generation storage whenever those occur, provided it has energy in storage to cover it. When it does cover that, it charges the wind generator the penalty. So the storage device captures the penalty. Now, the reason for structuring it this way is to make sure we get everything straight. And basically under this analysis, the wind generator is left in exactly the same situation financially as it was without the storage. So all the benefits and cost this thing accrues goes to the storage device. So what we are going to compute is the rate of return to the storage device. And basically we are looking at this as an owner might look at it who has a set of wind generators, and, you know, one way of framing the question is to say, well, I have a set of wind generators, the next thing I can do is either buy another wind generator or buy another storage device and which one would give me a higher rate of return. And if the storage device gives me a higher rate of return, I would favor that, and if it doesn't, I would buy another wind generator. So framing it that way, we can go on and we can start asking, well, how do we structure this storage device to maximize its rate of return so that we can make a proper comparison. We have to remember that the storage device can be thought of this way: here is the grid or power load or whatever, and the storage device consists of a storage vessel, tank. You know, if it is a hydrogen system, it's a tank of hydrogen, if it's a pump storage, it's a reservoir of water, if it's a battery, it's electrolyte and plates within the battery. It also has a charging device and a discharging device. And so the charging device can take energy in and convert it to whatever form of storage it needs, this could be a pump in the pumped hydro system, in a battery this is really a set of wires and maybe electronic controllers and things like that. Similarly, it has a discharging device, which, again, in a battery this is wires and controllers and so forth, and in a hydrogen system this might be a fuel cell. In the pumped hydro this is a turbine -- you know, turbine generated. It's perfectly possible for these to be the same physical unit. You know, in a pumped hydro, you can have a pump/turbine combined. In a hydrogen system you can have an electrolyzer fuel cell combined. The question for designing this whole thing is to ask two things: one, is what should be the capacity of these guys, and what should be the capacity of this. We need to optimize those. In conjunction with optimizing those, you have to optimize the operation. When do we buy it, when do we sell it, so much and so forth and how much do we earn. So this is the basic framework that we have to first ask. So we did this, and this is rather complicated actually, and it's all within the report, but I'll just hit the highlights here. What we are looking at is we tried to develop an analytic framework, which is what I call technology neutral. That is, we looked at the economics of a storage device all by itself and tried to understand how much would the storage device earn in its operation. Get a net operating revenue of that storage device, without worrying about what kind of storage it was, what its capital costs and so forth were. Once you know how much it earns as a function of its size and so forth, you can turn around and look at different storage technology and look then at the capital costs and other costs associated with the storage technologies and ask whether or not it earns or compute out what kind of rate of return that particular storage device would earn. So this is the framework to develop these technology-neutral results, and it's based upon an optimization program within Excel. As inputs we have hourly electric values, we input the charge and discharge capacity and we input a storage capacity, and so to do this analysis, we basically set these things and varied this thing over a series of analyses to develop a curve. But for a given storage capacity then we run through an optimization model. We optimize the hourly purchases and sales for this device now to maximize the net operating revenue. That's the amount that it costs to take energy in and the amount that it earns by selling energy. And what we get out of one run of the optimizer, is we get the net operating revenue from buying and selling, which also includes payments or penalties and so forth, and we get the marginal value of storage capacity. So if we know the net operating revenue from the storage device, we can then compare that now to all our capital cost to get an overall rate of return from the whole device. So to do this analysis we also considered large and small systems. A large system has a large charge and discharge capacity, so we fix that capacity, then we look at now the benefits of different levels of storage, storage capacity. We looked at small systems and basically a large system can purchase and sell more energy, it can provide more power to the grid. A small system, again, basically operates by selling at exactly the right time and buying at exactly the right time. So it really optimizes the difference between the sales price and the cost of taking energy in. So if we look at a large capacity, large system, and we now look at the rate of return for battery storage and for pumped hydro storage, salient features, these are not very good. Either one of them is above zero, but the battery storage, you'll notice adding a little bit of storage capacity to the tank increases the rate of return a little bit and then it declines rapidly, that is because adding storage capacity to the system is very expensive, battery systems take a lot per kilowatt hour. The pumped hydro system is different behavior. Adding storage capacity is relatively very cheap and so it does improve the return, but it never gets above zero in its analysis with this large storage capacity. And here the charge and discharge capacity is double that of a wind generator, 1 kilowatt wind generator, you can take in or produce about 1 kilowatt of power. Small system, where the charge and discharge capacity is about a 10th of the wind generator capacity, starts looking a lot better. Battery storage seems to approach the kind of return that we saw for the intermittent contract. Doesn't exceed it, but starts to approach that. Pumped hydro isn't looking very good. Now, the dilemma here, however, is that, sure, that the storage device does in fact perform reasonably well financially, but it's very small and really has not much of an impact on the system so it becomes almost just an afterthought to a system of this size. So conclusions are that while intermittent contract seems to be pretty good for the system, the backup approach might be practical. A little bit of the information coming in the report is encouraging. You would have to have the favorable capital cost structure for the backup generator, something more like a combined cycle, but if you are operating that way, something with low enough operating cost, you can hit high reliability, you can be eligible for capacity payments and that would make this thing more favorable than an intermittent contract. Storage seems to be pretty problematic. A large system that would have a real significant impact on operations doesn't seem to be financially very viable. A small system is possibly financially viable, but would have a very small impact on operations. Do we have time for questions or do you want to do that later? MS. NAKAFUJI: Actually, I think we are going to do that at the end of the panel so we can get all the speakers in. So thank you for your insight and trying to understand some of these technologies on wind. Our next speaker is Dr. Joan Ogden. We are very happy to have her. She is considered one of the country's premier researchers in hydrogen energy and recently joined the U.C. Davis campus as an associate professor in the department of environmental sciences and policy, and she will be playing key roles in policy analysis and making key decisions on the issues of integrating the hydrogen and infrastructure issues of U.C. Davis Institute of Transportation studies. So please help me welcome her. MS. OGDEN: It's a pleasure to be here. I'm going to talk a lot about hydrogen and a little about wind. I'm going to basically put these on people's radar screen and maybe stimulate some discussion about the possible role of hydrogen in the future of the energy economy, renewables and hydrogen and wind in particular. So really just to set the context, as we all know, projections are that energy use and emissions of greenhouse gases and air pollutants are going to rise by half over the next few decades, especially in developing countries. This causes a lot of challenges. One is a secure energy supply, especially in the transportation sector. We're almost entirely dependent on crude oil. Air pollutant emissions, although there has been a lot of progress, it's still an issue, especially in developing countries, and greenhouse gas emissions. The fuel sector is very important. Direct combustion fuels for transportation and other uses account for about 2/3 of primary energy use and greenhouse gases today. So although much of the work presently going on in wind and other parts of the energy economy is focused on zero emission electricity, really we will have to eventually tackle the fuel sector as well. And as I mentioned before, we are heavily dependent on one primary energy source really for transportation fuels at the present. These are some simulations that were done as part of some scenarios for the Governmental Panel on Climate Change. This IS92A is a sort of business as usual scenario. What's shown here are kind of projected emissions of CO2, and this is in gigatons of carbon per year. This goes from about roughly 6 or 7 gigatons today and then looks at projections under different scenarios of energy use going into the future about 100 years. Here is business as usual. Because of population growth and increased industrialization in the developing countries, we see a pretty rapid growth of carbon emissions, almost three times what it is now by the end of the century. If we track this to what this means according to climate models for atmospheric concentrations of CO2, preindustrial levels are down here, less than 300, we are already up over 350 now and these levels are projected to more than double if we follow a business as usual scenario. Many people who study climate, although there are certainly a lot of uncertainties about this, think that if we can stay at the 450 to 550 part per million range we may avoid some really nasty irreversible effects. But most people think going up to 700 would not be a very good idea for the climate. What does this mean about CO2 concentrations? This is the same type of graph, it shows gigatons of carbon per year. Again, here at present we are at about 6. This shows the carbon emissions you would have to have in order to stabilize atmospheric concentrations at different levels. This shows 700 parts per million, this curve, we would have to -- we would allow things to rise, eventually we would have to begin a decline. But to get into this 450 to 550 range we are talking about, we are talking about a pretty sharp departure from business as usual. This red line is that IS92A scenario. Starting really within a couple of decades, and by the time we get to about 2100, we are talking about a very large reduction in what business as usual carbon emissions would tell us. In fact, if we are going to stabilize CO2 concentrations, we are going to need to decarbonize the energy sector. Historically this has been going on -- the units of carbon per unit of energy has been going down historically. We are going to have to do this seven times the historical rates. Even if we completely decarbonize the electrical sector by 2100, if we want to reach 450, 550 PPM, we are going to have to face something like a three- to five-fold reduction in carbon emissions from the fuel sector. But this is just all to highlight that reaching goals, at least according to the present model, where we can stabilize the atmospheric concentration of CO2 at possibly acceptable levels, it is going to really mean a very strong reduction in the fuel sector over the next couple years, as well the electric sector. Turning to the vehicle part of this direct fuel use today, about half of that is for transportation and about half for other use in buildings and so on. There are a number of possible technologies that could address these concerns about carbon emissions and also air pollutant emissions and so on. Starting here with primary sources, the route we have mostly today is oil to gasoline to an internal combustion engine or ICE, or ICE hydrogen are becoming popular now too. But there are many other routes too that could involve making carriers such as liquid fuels, like methanol, Fischer-Tropsch or DME, hydrogen or electricity from fossil fuels like natural gas and coal or from renewable sources like biomass and wastes, wind, solar, hydro or nuclear, and there are a variety of energy carriers that you can make here and a variety of types of vehicles. If you go the electric route you could of course have battery vehicles, although with present technology there are limitations in terms of cost and range. If you go the hydrogen route, you can also go directly to a fuel cell, there is a lot of work going on in that, or you can go to an IC engine. Work going on here at U.C. Davis on this. If you have a liquid fuel, you could go to a fuel processor and make a hydrogen-rich gas on board for a fuel cell or any number of advanced ICEs. So out of this whole huge possibility of future transportation fuels what are the potential benefits of hydrogen and why would somebody look at this? One is that you have zero or near zero emissions at the point of use. Really the only thing that is in the same ballpark are battery electric. You can also have low to zero full fuel cycle emissions. By full fuel cycle, it just means all the emissions involved extracted feed stock, using the fuel, transporting the fuel to a refueling station, if you need to compress the fuel, if it's a gas and electricity compression, all those things. And you can bring emissions, both air pollutants and greenhouse gases, essentially to zero with hydrogen. Not all hydrogen generators do this, some -- you can have zero emission vehicles, and you have a lot of street emission production. If you make hydrogen from coal, for example, and didn't try to capture CO2 you would have a lot of emissions. But with renewable routes like solar, wind, biomass, with fossil fuels, if you can decarbonize them, that is, capture CO2 and store it underground or with nuclear routes, in theory you can produce and use energy with zero emission. And finally you can make hydrogen from a lot of widely available primary resources -- fossil, renewable, nuclear and there is rapid ongoing progress in hydrogen and fuel cell technology. Maybe some of you have seen some of the announcements from General Motors that have shown high-wire skateboard concept cars that have fuel cells and hydrogen storage all in kind of a common platform. You can put any kind of car on top, it's a fully electrified vehicle, you can drive by wire, you can just program in softer, what you want the car to feel like, what you want the response to be like, you can run your GPS, you can tap into intelligent highways. There are a lot of people that think these are potentially, you know, so-called disruptive technology, they might enable some new products that we don't have now. A lot of people are trying to wrestle with the ideas of what these might be, the possibility of plugging this car into the grid and using your car as a generator while you are at work. Maybe you can get free parking in New York City. Any city would be a plus. These are all the reasons hydrogen is being considered. Just comparing now hydrogen vehicles with other kinds of vehicles, this chart shows various air pollutants, sulfur oxide, particulates, and so on, different kinds of fuel/engine combinations, and I've normalized everything to projections for an advanced gasoline internal combustion. This is based on some designs of engineers at Ford, they looked at a vehicle that was very efficient, 45 miles per gallon equivalent, and very low polluting. And then we compared -- that's obviously a lot better than what we are doing today with current gasoline cars. Then we looked at advanced hybrids using different fuels, compressed natural gas, hydrogen, diesel, and so on. And the fuel cell vehicles, how much could you reduce emissions. So you see with some of the fuel cell options particularly, you can bring this down very low. I didn't show wind here because it's essentially zero, but we can do a lot better with advanced IC technology than conventional fuel, what we are doing now. We can do even better with fuel cell vehicles that run on hydrogen. Similar story for greenhouse gases. This is a current internal combustion car, it's run on gasoline, this is an advanced one. We have advanced IC hybrid vehicles here that represent a pretty good improvement over what they are doing now. But you can go even lower with fuel cells. Here I show wind, I don't show it quite zero because I'm assuming you are using wind electricity to press hydrogen at various points along the way. Some of that comes from nonrenewable sources in this model, but you can in theory bring this down to zero. I haven't put battery electric cars on here, in part because the present projections for those technologies and limitations, the range and recharge time, that make it a little bit different animal than the rest of these. All the rest of these essentially have the same performance and characteristics and range. So what are the barriers? There are some reasons why you might want to consider hydrogen. You really have the possibility for radical reductions in externalities associated with greenhouse gas emissions and pollutants. There are a number of really serious barriers, lack of widespread hydrogen infrastructures. You can't get this at your corner gas station today. Hydrogen end-use technology, like fuel cells, hydrogen cars, cost an awful lot today. Their projection costs will come down in mass production. It's going to be a while before we have enough of these out there to know if that is true. There are a number of technical maturity issues. There are hydrogen technologies today in the chemical industry, but we need to adapt these for an energy support system. And also to develop emerging technologies for hydrogen vehicles, notably things like fuel cells and hydrogen storage, which are not quite ready in terms of costs or in terms of some of the technical performance yet for widespread use. And also we need to develop a zero-emission hydrogen supply. We know how to make hydrogen today, we make it from fossil fuels. If we are going to really get the benefits, really bring those cost emissions way down, we need to go to zero emission route for producing that. There is a chicken and egg problem. More generally if you don't have fuel stations people won't buy cars. If you don't have a lot of cars out there, fuel suppliers won't put in fuel stations. You need to build up the market, match supply and demand carefully along the way. This is going to take coordination of fuel suppliers and energy companies, oil companies, automotive companies. This is beginning to happen through efforts like California Fuel Cell Partnership and others. There is a lot of discussion about this, but it's got to be kind of at a level that is unprecedented in previous alternative fuel ventures. And then finally, at present there is a lack of policies reflecting external costs of energy. There probably won't be a strong economic driver, even if you reach mass production goals and everything for fuel cells, unless these externalities are valid. So I really see a pretty strong role for policies. Hopefully reflecting future societal successes that we need to move toward a lower energy system. It will be important in bringing this about. This is a picture of current hydrogen infrastructure. Just to let you know, there is a current hydrogen infrastructure. About 1 percent of U.S. primary energy today gets used to make hydrogen. A lot of this is used in chemical applications like refineries. And there is also a hydrogen delivery system today. Hydrogen is liquefied, delivered in trucks and pipes. The current system that is here, although it's used for chemical reasons today, if you converted this all to fueling vehicles, you can fuel over a million, two million vehicles, something like that. So we already have a hydrogen distribution system at about 1 percent of scale of what we would need in terms of serving all the light-duty vehicles in the country. So these technologies do exist, but currently we make hydrogen almost exclusively from fossil fuel, about 95 percent of it in the U.S., so 90 percent of it comes from natural gas. As we saw before, if we are going to get the full benefits of hydrogen we need to go to zero emission. Very important. Near-term supply options, lots of ways to make hydrogen, most of it is made from natural gas today. Liquefied to 20 degrees K, shipped in trucks. These are different pipelines, we can connect refueling stations to this. There is a refueling station that uses this route, liquid hydrogen route, on campus here, it's down by the trans yard at U.C. Davis. Sometimes you get byproducts of chemical operations. You can also make hydrogen from natural gas and at electricity right at the refueling station. There are a number of people looking at these approaches as well. All of this stuff can be done with commercially available technologies. These are undergoing some pretty rapid improvements, but we can build this stuff today. In fact, there are many hydrogen demonstration refueling stations around the world, about 60 at the present time, something like that. In the longer term, if we really want to get to zero emissions, we can decentralize production of electrolytic hydrogen from some kind of a zero emission electric source. Solar or wind electrolysis is used to run an electrolyzer and then use that to power vehicles. Another idea that has come up is using fossil fuels, but in the process of making hydrogen from hydrocarbon, separate out the carbon, store it underground and send the hydrogen off to do work or use nuclear solar heat in advance thermochemical water split cycle. These are less mature than the rest of what is up here. Most of these you can build today, although it would be rather expensive. And I might mention, the CO2 sequestration. The idea there is you pressurize CO2, pump it down underground and store it under pressure. This is really a waste disposal scheme on a grand scale. And there are a lot of questions about whether this would work or not, but this is also being investigated. Just to talk about some wind hydrogen systems. Hydrogen is sometimes proposed as a storage medium for wind electricity, and now I'll touch on this kind of idea. Here you use -- you might send some power directly off to the grid, but you can use some of it to run an electrolyzer, to make hydrogen. You store that, when you need power, you could then put this through a generator, which might be a fuel cell, might be the same as this electrolyzer, send it back to the grid. This is a somewhat expensive way to store power. Another possibility is thinking about hydrogen not as a storage mechanism for the electricity system, but thinking about it as a storage mechanism using the transportation system, and that's what we have really been talking about this whole time. Here you store hydrogen and use it in cars. I think an intriguing idea though is making both electricity and hydrogen from wind power and you can do some analysis on this. One possibility for this is you make hydrogen, say you are distant from a city, you pipe hydrogen a long way, you might then reconvert it to electricity and use some of it for cars. Or another interesting idea is having some form of electricity storage nearby, sending this out on the grid and having electrolyzers at refueling stations and a building uses the rest. This approach avoids the need to build hydrogen pipelines, which is really a good thing because they are pretty expensive and they don't exist at present. Just some rough costs here. How much would it cost to put in a hydrogen refueling infrastructure? These near-term fossil-based options, maybe 500 to $1,000 per car served. Getting to the longer-term zero emission option, up over 1,000, over 2,000. Interesting to note, the black part of this is the production and the red is distribution of hydrogen and yellow is refueling stations. And the production is actually not that big of a chunk, the cost for piping hydrogen around and putting it in compressed gas refueling stations is quite high. Liquid fuel is a small fraction as opposed to hydrogen, it's not a big deal. So hydrogen infrastructure costs quite a lot. How much is this in dollars per gallon of gasoline? 1 kilogram of hydrogen is about the same energy content as a gallon of gasoline. Again, showing the components in terms of production, distribution and refueling. The near term, and really we are ranging between about the equivalent of two to three and a half dollars per gallon of gasoline, and these are based upon future projections for these technologies, including long-term technologies, including wind here, coal with sequestration and nuclear. So if you think of this in the context of a future car that uses hydrogen probably two to four times as efficiently as current gasoline cars, then our cents per mile might actually not be that different than what we are paying today. We get gasoline at $2 per gallon today, we use it 25 miles per gallon. The equivalent car can do twice as good as that in terms of fuel economy. Fuel cell car in that range of projection you can afford to pay $4 a gallon or $4 per kilogram and have the same cents per mile. So these are not outlandish. Where will all this hydrogen come from? What are the resources for making it? I did a little calculation here on demand. Today we have about 200 million light-duty gasoline vehicles in the U.S., that may go up to about 300 million by, say, a century from now. Current gasoline use for the average light-duty vehicle fleet in use gets about 20 miles per gallon, counting all the SUVs and everything 11,000 miles a year, you can calculate in gigajoules per year, what that comes to be. If you look at the future, hydrogen vehicles might be two to four times as efficient as the current gasoline vehicles. You can calculate how many exajoules. This is 10 to the 18th joules. For 100 million vehicles, let's say you are doing half the fleet or a third of the fleet with hydrogen, that is how much you would need. Looking at supply, assuming you make all the hydrogen from one source. Natural gas, if you did it that way, you would have to up the use by about 10 to 20 percent. Coal, on the order of 15 to 30 percent. From off-peak power you would have to use somewhere between 18 and 36 percent of the installed capacity off-peak. With wind, estimated about 8 to 16 percent of the class four, five and six wind power sites in the U.S. until you get hydrogen and electricity. So you could do a significant amount of fuel for light-duty vehicles with renewables. Biomass gas, a recent study by NREL showed you can be right in the middle of this range if you used about 170,000 kilometers of energy crops plus residue and other wastes. So there are lots of different possibilities for making hydrogen, including a number of zero emission routes here. This shows a map that NREL put together as to where renewable resources are in the U.S. The purple wind resources show a lot in the upper midwest. Biomass shows in green, and solar down here in kind of red. So there are good resources for producing hydrogen pretty much everywhere in the U.S. from one resource or another. Just talk a little about a transition. How we can move from our present system to one that uses such a different fuel? Let's think about going from the first applications, which are likely to be something like buses and fleets, general markets, and assume all the vehicle owners have to have great access to fuel. We want to design a low-cost electrical fuel delivery system and supply hydrogen. Could be in the public refueling stations like we do with gasoline today, but also possibly at other locations like work or even at home. This is what we are shooting at, this is the current number of gasoline stations in the U.S. and you can see they are pretty dense. Each dot represents ten stations. These are other alternative fuels, CMG, methanol and ethanol, and even the nearest one, CMG doesn't have anywhere quite near the coverage. With hydrogen if we apply this, it would be on the order of ten stations. So we have a long way to go to be able to offer this to mass markets. How soon would this take place? There are several scenarios that the Department of Energy developed, and this shows the fraction of hydrogen in light-duty fleets, and we see basically we just don't know. By 2050 these range between 1 percent and 100 percent. There are a lot of very uncertain factors that will go into how fast this ramps up. One is just the technology itself, are fuel cells going to prove to be low cost for hydrogen vehicles to happen. Are we going to have a value in society on externalities that will bring us in that direction, whether we think it worth it in this society to bring down, achieve these really radical reductions and get on a stabilization path in the fuel sector. A lot of questions we don't know the answers to yet, but this is very intriguing because you do have this possibility. Just a picture here of hydrogen infrastructure growing over time. These represent some cities. This is a primary resource like natural gas, which might already go there, another primary resource like wind. And over time you might have onsite plants for hydrogen first, big plants distributing hydrogen, maybe capture CO2 and bring on some other sources as well. So there is a lot of questions about how you can locate plants and where the resources are and so on. It's a very complicated problem, and one that we are going to be working at here at U.C. Davis as part of the research program I mentioned. Study the possible transition to hydrogen and looking at possible benefits of hydrogen to other alternatives to meet environmental needs. In conclusion, we have multiple benefits with hydrogen that are possible in terms of greenhouse gases, security, air pollutants. You have lots of different ways you can deliver hydrogen. It's probably going to be regionally specific by the -- say, multiple sources. It's more like the electricity system, thinking about the current transportation fuel system. I don't think we are going to see the very long supply lines that we have today of about 75 percent of oil traded very long distances. Technologies exist to produce and store hydrogen, but they would need to be adapted. End-use technology and zero emission supply technologies are developing, but they need more work. In the near term, fossil hydrogen is probably going to be the lowest cost option, although there are local cases in places like New Zealand and Tasmania where renewable hydropower and geothermal could play a role. But in the longer term it's important to bring in the zero emission technology. There is a lot of uncertainty about the timing of a hydrogen economy. Depends on a lot of things we don't know the answer to. We are rather uncertain about technical and economic progress of these technologies. But maybe even more importantly how we as a society value externalities will determine whether or not we bring this in. But even under optimistic scenarios, it will take several decades before hydrogen vehicles will impact emissions on a global scale. So while developing hydrogen vehicles over the next couple decades and finding out whether they are going to meet their technical and cost goal, it will be important to develop these zero emission high technologies. Obviously, wind energy is a key kind of enabling technology for zero emission. And finally, although these things are very long term and high risk, there is potentially huge payoffs. So I do think they do deserve the government support they are receiving at present. Insurance policy, I think we need to decide 15 and 20 years down the road and decide as a society to move this way. We won't be there unless we start work on it now. We need consistent policies for cleaner transportation, to lower our emissions, ICEs will be really important, things like gasoline hybrids over the next couple decades. And the continued development of hydrogen would start to play a role in the second quarter of the century I would say. We really need a comprehensive strategy to encourage the clean internal combustion engine now; hydrogen in the long term. We need to address the externalities head on; I believe this is the best way to do this. I'll end there. Thanks very much. (Applause.) MS. NAKAFUJI: Again, we'll have questions at the end of the last presentation. Again, the perspectives, I think, are important for building a new infrastructure and challenges and the transition strategies that will be needed for bringing an emerging or enabling technology into mainstream. And our next speaker is Scott Flake and he is a superintendent and a project development engineer at SMUD, and he is here to talk about the Iowa pumped storage project that SMUD is looking into. It's a 400 million dollar projected investment. And I asked Scott how long he has been involved with the utility industry and he says, oh, tremendously long, many years. So I'll let him go ahead and start his talk. Thanks. MR. FLAKE: Good morning, I'm again going to talk about something other than wind, but we'll see how they kind of work together as we go through the project. Again, this is a proposed project. The entire SMUD's relicensing process now for the Upper American River project has been going on for about two years, this project is a part of that overall relicensing. It's about a 688 megawatt hydro project that was developed about fifty years ago. So we are going to do just an overview talk about the project first of all. Pumped storage units are kind of a strange animal. We'll talk a little bit about where it is and how it's going to operate, some of the benefits for energy management and how we kind of justify building one of these things, and then some questions, I guess, at the end. This is an overview of the entire Upper American River project. You can see it stretches from Desolation Wilderness up near Lake Tahoe, all the way basically down to Highway 50 near Placerville. And the location of this pump storage project is right in here, and it's going to be fully integrated with the existing project and take advantage of the existing infrastructure to lower costs. Here is a -- we're zooming in now on the actual location of the project. This is called Slab Creek Reservoir. It's just outside Camino off Highway 50 on the American River. You can see the canyons for the streams coming out of the Sierras of Carson, very deep, very steep canyons, which are potentially very good sites for the pumped storage project. This is the actual project layout and the location. The upper reservoir here, subterranean tunnels, subterranean powerhouse and tie-in to the existing reservoir. So the actual project consists of the underground powerhouse, water conduits and the upper reservoir. And we would reuse the existing lower Slab Creek Reservoir as the lower reservoir so we wouldn't have to build a second reservoir, nor would we have to build any new dams or use any new water sources. The upper reservoir is about 6,400 acre feet of water, so it would be not a long-term storage reservoir, it would be used for daily cycling, weekly cycling. The total footprint of the reservoir is just a little over 100 acres. This is kind of a plan view of -- an elevation view of the project. It has the upper reservoir, the vertical shaft about 1,200 feet down into the mountain. Three turbines here, about 400 megawatts of power and discharging into the reservoir down here. In the evening or off-peak hours the idea is that you would pump water out of this reservoir, pump the other reservoir and then release it during the daytime or primarily super peaking capability and SMUD has a particular cycle of power usage, especially during the summer where the usage can spike very quickly, very rapidly during the summertime when the temperatures start heating up in the late afternoon. And its actual primary role is for ancillary services, for balancing transmission usage and for managing the water and thermal resources within the overall SMUD power generation mix. Currently the primary benefits from this unit would be that it can operate, it -- it's very flexible, it can operate with the supply energy market. It helps to optimize, again, thermal plant operation, and it does not cause a loss of water out of the Upper American system. So this project is very flexible and it helps primarily manage the energy delivery system for the operations of the grid. Which is kind of the tie-in to wind energy, because wind, as we talked about earlier, is a very dynamic source of energy and very difficult to schedule. Specifically, again, peaking capacity, we talked about that earlier, as temperature goes up, the air conditioning load rises, in fact sometimes rises very rapidly, and this project would help shave these peaks. We would pump with off-peak power, and that is how the wind energy comes in. And then ancillary services, the primary roll of a pump storage is actually not generating electricity, it has the potential to generate electricity and the ability to provide services to the grid like support, and then operational flexibility, balance loads within the transmission system. And things like wind energy come into the picture there as well. So that's how the wind energy ties in. And then specifically for wind energy, SMUD relies heavily on a hydrosystem right now for balancing the overall transmission system. SMUD is not part of the California ISO, they have their own system. So they are responsible for the real-time balancing of energy, supply and demand. And so we currently use primarily the hydrosystem, and we have large storage reservoirs that we saw earlier and we balance the system using hydroplants, using long-term storage systems to release water so that we can actually balance in real time the energy delivery. We have a limited amount of long-term storage. As we all know, in California water is a critical issue always and so that becomes more constrained all the time. So this is going to be an important asset to help manage that limited resource that we do have. And then, again, it's the ancillary services that this unit provides and our ability to manage water and also thermal plants. Right now we do a lot of balancing with thermal plants as well, cause them to operate off peak, increase O and M costs, decreases efficiency. So this project does a lot for a lot of internal costs that the district currently incurs due to ancillary services and system balancing. Again, this is some of the environmental aspects of this project. It doesn't divert water from streams, it does not place any new dams on existing streams, which are, you know, critical issues these days. It uses existing infrastructure. We are not going to build a new reservoir at the bottom end, we are going to actually reuse a current reservoir and it's a non-polluting generating resource. It uses water power to balance system loads. And with any hydroproject, the timelines can be a little bit long, so we have been working on the project now for about two years. We are going to put an application into the Federal Energy Commission sometime in the middle of 2005. We expect a license in 2007. If the board approves the project, we can start construction after the project is issued, maybe in perhaps 2010, probably on-line 2013. So it's a long-term goal and a long-range project. And that's the overall overview of the Iowa Hill project. (Applause.) MS. NAKAFUJI: Thank you. Actually we have about 15 minutes for some questions for the panel. UNIDENTIFIED SPEAKER: I have a very specific question for Scott. What's the energy and capacity of the proposed storage project, and how does that compare to regulations and requirements that are currently available? MR. FLAKE: The project as proposed is 400 megawatts. We currently use about probably an equivalent amount. We have one of our powerhouses at White Rock at the lower end of the system, it is used a lot for both energy and balancing, ancillary services. It's about a 200 megawatt power plant. The ancillary services you can almost double that capacity because you have capacity as well as energy production. So it would essentially be our main provider of ancillary services, voltage support, spinning and non-spinning capacity and then system balancing as well to manage water in the project and then manage our thermal power plant dispatch. SAME SPEAKER: In terms of megawatts hours, I mean, are -- MR. FLAKE: In terms of megawatt hours? SAME SPEAKER: Yes. MR. FLAKE: Its actual capacity for production of energy, probably only around -- the capacity may be 15 percent. It's not really -- that's why pump storage is kind of strange, it's not really -- its primary function is not actually to produce energy, it's to balance the system, to provide ancillary services, and so that is how the wind energy comes in. Actually, you know, during wind energy times it pumps water up, so it's actually a load on the system, it's not actually generating electricity. That is, however, in the benefit category. If you look at just on an energy basis, then a pumped storage doesn't make any sense at all, but if you fold it in the ancillary services, voltage support and balancing from a systems operations perspective, that's how you get above the bar on the pumped storage unit. MS. NAKAFUJI: Since we are transcribing some of this stuff, if you could state your name. MR. EHRLICH: I'm Norm Ehrlich from Six Rivers Solar in Eureka, this is for Alan. I have got a project planning underway, there is an existing 18 megawatt biomass plant, and the wind -- around it is an excellent wind site, at least I'm taking data now. I would like to know your thoughts on if we are going to put a 50 megawatt windfarm added to this 18 megawatt biomass plant, what are your thoughts on something like that? It's kind of a hybrid situation as to where we already have an existing facility and we are going to expand it, so kind of -- they already have a PPA for 18 megawatts right now through the year 2017, something like that. Biomass plant also has natural gas capability as well. MR. LAMONT: I'm curious, is that a Pacific Lumber site? MR. EHRLICH: It's not Pacific Lumber, but it is close to there. MR. LAMONT: First of all, I think that winds up being evaluated pretty much on its own terms like any other wind site. I'm not sure backup or storage, if you are going to use -- you can conceivably use the biomass as your backup there, depending upon whether or not your fuel supply is limited. If your fuel supply is relatively limited so that you could actually operate that at a high capacity factor, then maybe one can consider saying, well, I'll operate it, the biomass, at a lower capacity factor over a year, bringing it on when the wind is relatively -- when there is less wind and firming up my wind that way, and therefore using all of your fuel -- using it in the most advantageous way to you. If you have plenty of fuel, you have a high capacity factor anyway, there isn't much benefit to that approach. I guess the only other issue that would strike me is if, in that region, it has relatively weak ties to the rest of the grid. It does raise some questions about just the cost of wind power in that area. If it has to be balanced from outside of Humboldt County it might be actually a little more costly than other approaches. So it gives you kind of a vague answer. These are the things that come to my mind. MR. RUSSELL: Question for Mr. Flake, Rick Russell speaking. It could be I just didn't understand, but the Upper American River Project is a relicensing effort; is that right? MR. FLAKE: That's right. MR. RUSSELL: Is the Iowa pump storage part of that relicensing effort or is this a new license? MR. FLAKE: It's part of the overall relicensing effort for the Upper American River. MR. RUSSELL: Follow-up question then: the problems associated with piggy-backing a new problem on a relicensing effort, could you elaborate on that, if it's not a thirty-minute answer? MR. FLAKE: Oh, my. Just relicensing is hard enough and then incorporating a new project into it, especially the size of Iowa Hill, just creates pretty large problems from an environmental studies point of view. But generally the Iowa Hill project is not a new project, it was initially proposed in the early 70s, so it's been kicking around quite a bit. And it's a pretty well-known site, it is pretty well defined. SMUD actually owns most of the property they are going to use for the project already. Because this project is off-stream and because it is primarily a subterranean project, and they do own the land for the upper reservoir, it -- the problems that Iowa Hill creates are primarily ones related to how you are going the manage the water within the whole system. And so we have -- just to kind of shorten my answer, we have a variety of computer models that we are using to simulate the water flow into the system and how Iowa Hill would integrate into that and how it might not integrate into it. We are working right now with a variety of federal and state agencies to try to determine how best to manage water within the entire project, including Iowa Hill. But because it is a proposed project, we are looking at it both with and without Iowa Hill. It does create quite a bit more work for the whole licensing process. MS. NAKAFUJI: One more question over here. UNIDENTIFIED SPEAKER: This is a question for Scott: since you are going to use wind for essentially firming up your ancillary services, what do you value the wind at? Is it valued at ancillary services prices? MR. FLAKE: The wind actually doesn't provide a lot of ancillary services to SMUD, but we use a lot of ancillary services to support the wind. We just brought the first 10 megawatts on line. Our project manager is right back there, Dick Wallace. Ahead of schedule and under budget, I might add. The ancillary services is used for wind energy because it's non-firm, you know, SMUD uses the -- we measure these costs in terms of water usage and thermal power plant balancing to support those and that's what we are using to justify the Iowa Hill project and even -- it's pretty -- it's right on the edge, as Alan noted in his presentation, it's pretty sketchy economics. SAME SPEAKER: When you look at the wind alone, the point was that you had to purchase less pump storage capacity, and your pump storage is really what provides your ancillary services, correct? MR. FLAKE: Right. SAME SPEAKER: So the economics on the wind side, it would seem to me that really by cutting down you have to value that the savings of that reduced capital for the pumped storage, that has got to be a higher value than system (unintelligible) cost. That is actually why I asked the question because otherwise it wouldn't make any sense at all to use wind. Is that what you are finding? MR. FLAKE: I really don't know what the economics are of the wind project, so I can't really comment exactly on the economics of that. The only thing that I've been looking at primarily is, you know, the -- is how the cost to the district on what that -- what some of the costs of the wind delivery into the system are for balancing costs. And that's kind of what we are looking at. We are not looking at the wind, we are just assuming the wind was there and it's coming in. MS. NAKAFUJI: Maybe that's something that we can have the SeaWest group take a look at. MR. FLAKE: I would say SMUD is committed to a 20 percent goal of renewable energy, and they are very aggressively pursuing that. This wind project could be expanded to as much as 100 megawatts in the coming years. So that is also a factor that is being folded into it, but I think the overall goal of the district is 20 percent and they are actively pursuing that. So we are trying to develop our resource mix so we can support that goal. MR. CARVER: Hugo Carver from Knight and Carver in San Diego. There is for Dr. Ogden, I'm curious if I can convert my current ICE to a fuel cell -- excuse me, a hydrogen-powered car and for equivalent range about how big is my gas tank going to be? Thanks. MS. OGDEN: The answer is you can convert existing ICEs, gasoline ICEs, to run on hydrogen. You have to change a bunch of things, the fuel delivery system, the compression ratio, but people have done this sort of thing. You also have to take the gasoline tank out and put something to store hydrogen in. And if you wanted to get an equivalent range with a conversion of a present-day car, you would have to have a station wagon, fill up the entire back area with compressed gas tanks. That is one reason why people are talking about redesigning fuel cell hydrogen cars from the ground up. And it really makes a whole lot more sense if you have a much more efficient power plant up front, engine up front, so that you don't require the same amount of energy per mile. To go alone with hydrogen, to make the design of the car work, you have to put in a more efficient power plant. This can be an internal combustion hybrid or it could be a fuel cell. And with those sorts of systems, people project you can do maybe two to four times better for equivalent performance, you know, power to weight ratio, all that sort of thing, as current as light-duty vehicles today. And there is a big spread in what you do, depends on whether you hybridize the fuel cell with a battery plus some other things and how much you light-weight the car. There are a whole -- if you go the route of efficiency, so you start with your average gasoline car today, average light-duty vehicle, 20 miles per gallon, not counting SUVs, you do a lot better than that, make the car more smaller, lighter weight, more streamlined, you can do a factor of two from that 20 to 40 already. With a fuel cell power plant you can take that up, maybe another factor of one and a half or something. So when you do all that stuff, then your onboard storage volume shrinks and eventually you get to a point where you can look at something approaching a 250- or 300-mile range with maybe 150, 200 liters of hydrogen storage capacity, which is like about three or four standard CMG, small CMG car, CMG-type tanks. MS. NAKAFUJI: We plan on taking a ten-minute break. Some people have been asking about presentation slides, they will all be made available on the SeaWest website after the forum. If there is any feedback on the benefits or the impact of this forum for the commission, send them to me. If there is any problems, please send them to me too. MR. VAN DAM: Let's take a twenty-minute break. (Applause.) MR. VAN DAM: Before we get going with the fourth panel of this forum, I have a little information about us and actually some of the previous talks. Alan Lamont, his report is available in draft form from our website. The 2002 forum proceedings are available from our website. Again, that is all in -- mostly in PDF format. The 2003 proceedings or the presentations and the full transcript will be up very soon, may take us a few weeks to pull everything together. You will see bit by bit the information coming on line for the 2003 forum. You see some e-mail addresses there, you can always reach me. You send it to info@cwec.ucdavis.edu, to myself, Bruce White, as well as Henry Shiu, and one of us will respond to your questions. Okay, let's get started. I don't want to make us run too late today. So we have the fourth panel today. The title is Living and Working with Wind. Rick Russell is the moderator of that panel, and he was actually very helpful in getting this together. It was kind of a little bit of a new direction for us and we look forward to working with Rick in the future to move this effort ahead. Rick is a landowner in Solano County. I think he has firsthand experience in terms of working and living with wind energy, and without further ado, I would like to give him the podium. MR. RUSSELL: I'll do my best to get us out of here by noon or so. I'd like to orient all of you on where we are at, and I was hoping Mr. Herrick, Dave Herrick, from yesterday would still be in attendance. I was going to ask if I could borrow one of his slides, but he is not here, so we won't tell him. Henry, if you can put up the second panel from his presentation. The purpose of this -- maybe it was the third panel then. That is it. If any of you are trying to get back to the Bay Area today and want to take a little detour, if you drop off of Interstate 80 and jump onto Highway 113 South, when Highway 113 crosses -- you will be on that for about 30 minutes or so, but when 113 crosses Highway 12, it turns into Birds Landing Road. And prior to getting to Birds Landing there is a T, it's Montezuma Hills Road, and it would veer off to the left. I point this out because this general area is what we are -- the property area that we are talking about. I own property here. Ian, one of our speakers, owns property in here. And what's significant about this, if you looked at the wind maps that the CEC, I think, provided, that sort of dark pink, light purple area is really about where that star is. The Delta, as you know, is relatively flat through here, but you have an area in here known as the Montezuma Hills, and the Montezuma Hills are a kind of a unique geologic feature. It's a very asymmetrical syncline, which has been basically fractured and tilted up on its side. Over here is the largest drygrass field in the world in Rio Vista. In the Montezuma Hills area you have a mix of projects. The property I own is actually an old U.S. Wind Kenetech project, it's about 60 megawatts. These machines now are about 14 years old. That property is really on the inside of the horseshoe of FPL's projects, which is 115 megawatts. And then to the south is SMUD's project. And SMUD's project -- is Dick here? Dick is not here. SMUD's project, I believe, right now is approaching 40 megawatts, and they are trying to go to 100 or something like that. The operators of the Solano project, the one on my property, is UNESCO, and if you do get down there, I don't think you can do much more than just kind of wander around and take a look. Roger, Dennis, if someone were down there, could they swing in and ask John for just an orientation? Let me introduce Roger and Dennis, they are with UNESCO, they are operators of that project there. You might want to catch them afterward. I don't see anyone from FPL. If anyone from FPL is still here, same sort of thing. There is other activity in the area, I think when it's all done, over the next five years you might have 1,000 megawatts. I'm just not altogether up to speed on that. On our panel today we have -- and I want to emphasize the fact that I'm really just a property owner. I don't have to live with the turbines. This property has been in my family for well over 100 years. The relationship with the Anderson family goes back that far as well. I think we are into our fourth or fifth generation now of -- you know, the Andersons are ranchers, farmers. And I'm going to let you decide do you want to hear from the taxman first or do you want to hear from the farmer first? It doesn't matter to me. But Ian Anderson is here representing E.A. Anderson and Son. I'll read a quick bio for him when I introduce him, but I think what we'll start with is with Mr. Rick Roberts. He is a senior appraiser with the Solano County Assessor Reporter's Office. Rick is dealing now with a lot of issues relative to the Williamson Act, relative to wind power now coming in on what has been traditionally farm and ranch land, and how the assessor looks at that issue and how the assessor's office also deals then with these owners that are dealing with that issue. So the whole point of this presentation right now is to really start talking about some of these concerns that property owners have, not just living with it, but then after the project has been permitted, built, is up and operating, you know, what it is to live with that. And then these lasting, lingering sort of things that we as property owners have to deal with. It could be taxes, could be a number of issues. With that I'm going to let Rick Roberts take over. MR. ROBERTS: Thank you. Thank you, Rick, and I appreciate your invitation and the time to share the concepts of how we look at this from the assessor's office standpoint. My discussion today will pertain to wind farms within the agricultural preserve and related Williamson Act assessment. The panel was asked today to speak for about 15 minutes, so I would like to spend about ten minutes of disclaimer, and about five minutes of actual information. Just like a real estate multiple listing, quote, the following information is deemed reliable, but not guaranteed. But I'm sure many of you are familiar with the Mission Impossible series. Skip Thomson, our elected Solano County Assessor, said to me, Rick, your mission, should you choose to accept it, is to fill for him on the panel today. Of course, like Mission Impossible, he will disavow my presence here today. Seriously speaking, the California Land Conservation Act was established in 1965. And the purpose of the law was to preserve agricultural and open space lands and to avoid or discourage premature development and conversion into non-agricultural uses. The landowners enter into a contract with the county which limits the land usage to open space purposes or agricultural usages. The contract itself has a rolling ten-year term, which automatically renews for an additional year, and the recorded contract remains with the land and therefore it is binding upon the heirs, successors, assignees and parties of the contract. To get out of the contract would require filing a notice of nonrenewal, which takes place over a ten-year period. The other alternative if one were to choose not to be in the Williamson Act would be to file for cancellation, which involves approval by the governing board and also a 12 and a half percent penalty of the fair market value of the property at the time. So there is -- those two, the latter part of that is more expense for the property owner and one has to look at the viability of getting out under the cancellation process. In exchange for imposition of these restrictions, the property owners are assessed using the highest and best use under prudent management for some type of agricultural or related or compatible use as opposed to -- and not a speculative or future market value potential concept. The majority of the owners located within the High Winds Power Project, at least, have Williamson Act contracts and are restricted as such. The High Winds Project consists of approximately 6,000 acres as part of the larger Collinsville/Montezuma wind resource area where Mr. Russell was pointing to on the map there. Agricultural practice in the area is typically dryland farming in conjunction with sheep grazing on a three-year rotational basis, which is historically what has been done there, and the land is assessed each year based on the income from this dryland farming practice according to laws governing parcels restricted in the Williamson Act. A significant reliance is placed on both the quality and the number of responses that we receive from property owners. We mail out questionnaires each year and we determine crop production and price and grazing rents from these questionnaires and use the extracted data for assessment purposes. So it's important that we hear from all the landowners that have received questionnaires. The responses we get are confidential and we do appreciate when we get these responses from the property owners. In addition, the land is further assessed based upon the income received by the property owners from the wind farm income -- or wind farm operation. The land value is determined by capitalizing the income at an overall rate prescribed by law, which has an interest component as part of it that changes each year. The interest component can rise and fall and is based on the average of long-term U.S. government bonds as reported by the Federal Reserve Board. The interest component has declined over the past four years due to recent economic conditions resulting in higher restricted land values in the Williamson Act. You know, we have been at historic interest rate lows recently in the United States. Under the law, Proposition 13 established a base value for property in California subject to an inflation adjustment each year so it doesn't exceed 2 percent of the prior year's value. So in the case of the Williamson Act, if the Williamson Act restricted value calculation any particular year exceeds that Proposition 13 value, the property owner gets the benefit of the lower of the two numbers, and since by law we cannot exceed the Proposition 13 value adjusted for inflation, can't exceed that by law. So for example, if the restricted value for a particular year was 300,000 value on a property and Proposition 13 was 250,000, we could not exceed that $250,000 ceiling under the law. Conversely, if the Williamson Act says it was 200,000 and the base year 250, the owner gets the benefit of the lower number and gets the $200,000 assessment. So in the near future many property owners that are associated with the High Winds Project will probably see their Proposition 13 base year values enrolled as a result as wind income farming increases and the units come under production. In this situation, the owner may question the benefit of being in the Williamson Act and there are some issues associated with that as to, I suppose, long-term viability of income and what they would want their heirs to have in the future as far as whether it would benefit them to remain in the Williamson Act. Another issue is the impact the wind farm will have on all agricultural compatible uses, and the compatibility of the use under the Williamson Act restrictions themselves. The law under Government Code Section 51238.1 states in part that, quote, "Uses on contracted land shall be consistent with the following principles of compatibility; The use will not significantly compromise the long-term productive agricultural capability of the subject contracted parcel or parcels. Number two, The use will not significantly displace or impair current or reasonably foreseeable agricultural operations on the subject contracted parcel or parcels. The use will not result in significant removal of adjacent contracted land from agricultural or open-space use," end quote. The issue was addressed in detail by the High Winds Project Environmental Impact Report. Essentially the project was considered a compatible use since the law authorizes the county to approve such a use on non-prime land, and the zoning permitted commercial wind turbine generators within the project location. The report stated that, quote, "The proposed siting of the turbines and other project components would allow for the continued use of the remaining land area for dryland farming and grazing. Farming operations would be adjusted to accommodate new access roads and this was not considered a significant impact," end quote. According to the EIR, the wind farm project would be consistent with the purposes of the Williamson Act to preserve agricultural use, as less than 2 percent of the total project acres would be permanently removed from agricultural use, and yet it would support the continued agricultural use on the remaining 98 percent of the project site. And finally, I'd just like to make a couple comments about how the assessor's office treats secured and unsecured property. Real property improvements are normally assessed on the secured tax roll, which is collected via the normal secured tax roll each year. Anyone that lives in California receives one that owns a home. Typically when the real property improvements are owned by a third party, not the landowner, the improvements are assessed on what are known as the unsecured tax roll and are billed separately. Also, in addition to that, our business division assesses business fixtures and equipment as personal items, so a level of coordination needs to exist between what is personal property and unsecured real property to avoid duplicate assessment in our office. So with that, I'd like to thank you for your time and attention and conclude my remarks. UNIDENTIFIED SPEAKER: Can we ask questions or should we wait until the end? MR. RUSSELL: Let's wait until the end. Unless it can't wait. UNIDENTIFIED SPEAKER: It's fresh in my mind right now. MR. RUSSELL: We'll make an exception for you. SAME SPEAKER: So are you assessing additional taxes because of the actual physical wind turbines? MR. ROBERTS: Yes, both from the standpoint of the owner of the wind turbines and also the income that is being received by the property owner. SAME SPEAKER: It's my understanding that -- because I've had calls from a few landowners, that you are assessing extra additional taxes due to just a lease on the property. MR. ROBERTS: That is correct. Under Section 423 of our Revenue and Taxation Code, most of the properties in the -- should I be up there? MR. RUSSELL: Let's get you on the mike. MR. ROBERTS: Most of the property owners in the High Winds Project are restricted under the Williamson Act, and Section 423 of our T code deals with taking a look at the highest and best use and also the wind farm itself is considered compatible use, therefore we are looking at the leases that are typical for that project and we are assessing the income derived from these leases in addition to the dryland farming operation. So we are looking at the whole income being derived from the land as the highest and best use. SAME SPEAKER: Do you assess oil and gas leases the same? MR. ROBERTS: Currently we are not doing that; however, there is a provision in the code that allows us to do so. Especially for these properties that are in the Williamson Act. Part of our problem is somewhat involved with the reporting that we receive -- or don't receive actually, and so that hasn't been implemented at this point. It may change. But this particular issue, the wind farm, has taken quite a bit of my personal time. I've inherited the Williamson Act program in the last couple of years and trying to be a little more accurate in our assessment in the office. So that's an issue that will probably be addressed. SAME SPEAKER: Well, my concern was -- MR. RUSSELL: Let's move an. We'll pick up some questions after the -- SAME SPEAKER: It's just like one more question. MR. RUSSELL: Okay. SAME SPEAKER: On an oil and gas lease there is a promise of drilling a well, there is no guarantee that there is going to be no minerals found underneath there, and there is no guarantee that an actual well will be drilled. The only promise you have is the first year rental. There is not even a promise of going to the next year rental. It's the same with a wind lease. The only promise they have is the first year rental. You know, the next year rolls around and the wind company may or may not choose to extend that lease for another year. So I was just wondering -- it just seems to me odd that the law would allow an increase in taxes just because of a one-year lease. MR. ROBERTS: Well, we are looking at the income that is reported to us on a year-to-year basis. The parcels that are currently being assessed, it's my understanding, have a long-term lease at a minimum of $20 an acre. SAME SPEAKER: Right, but they only get a year in advance. There is only a promise of -- you know, but the only guarantee is the income they have received for that year. So it just seemed odd to me that the county would be allowed to increase taxes. I can understand the increase in taxes once there is a wind farm on the property, but up until then, there is no guarantee that that wind farm is ever going to exist until they actual start up construction. So that was my concern. MR. RUSSELL: Thanks. Thanks, Rick. First, before I introduce our next speaker, I want to let you know, Ellen Bastier, an attorney with Thelen, Reid & Priest, was scheduled to be here today and she was unable to make it, and I'm not prepared to talk about contracts and that sort of thing, so we are just going to have to pass on that discussion. But our next speaker today is Ian Anderson. Ian is a fourth generation farmer rancher in the Birds Landing area. I can remember as a kid going down to Birds Landing, and I just figured everyone knew where Birds Landing was. It wasn't until probably just in the last ten years I realized -- I think there was an international news crew sent down to Birds Landing because it's the smallest zip code -- I don't know if it's the United States or the world, something like that. I mean, they really pinpointed that Birds Landing was unique for its smallness. But Birds Landing is very unique. If you continue down the road to Collinsville, you really can see how time has stood still in some respects. But Ian has lived there all his life. He is a fourth generation farmer. I mentioned that his family's relationship and my family's relationship extends over most of that time. His primary commodities are dryland grains, wheat, barley and oats and lamb, which is a niche market through the Neiman Ranch. Because of economic pressures in agriculture, Ian has created greater diversity in his farming operation than was necessary in the heyday of his father and grandfather's time. He has added a small flock of -- is it boar? Meat goats. There is a market out there for meat goats, and maybe you can ask Ian what that's all about. And he has created a successful oat/hay operation, and I think a lot of that is related to erosion control and that sort of thing. He is a graduate of Cal Poly. He has brought in all the modern farming techniques during the last 20, 25 years that he has been actively farming down there. Sheep ranching and farming in general, it's a rough environment. I don't know how anyone can survive down there, but Ian has definitely shown to me that he is the man who can do it. He has two teenage children, a son and a daughter. I know they keep he and Margaret very very busy. And with that, I'll ask Ian to come up to the podium. MR. ANDERSON: Thank you, Rick. That was more bio than I really needed, but thank you for overdoing it. I don't know if there are any of the SMUD people here still, but I was -- I'm a tenent farmer, we farm about 9,000 acres, which about 40 percent is planted each year. But on the SMUD property I had a heck of a volunteer hay crop. So below the wind generators there are people doing things and I'm one of the people doing that. In fact this coming year through another relation we are actually on the SMUD property again planting some more oat hay. As Rick mentioned, I have been farming for a long time. I'm very proud of what my profession is and part of what I really wanted to say today is really as much about farming and the need for society to have people in my profession, versus just looking simply as a global commodity, because the vast majority of our citizens really don't have much of a feel, other than going to the grocery store, realizing there is plenty of food and it's always going to be there. I believe that may not be true for another generation, between the world economies, possible -- the potential of not having an abundant food supply exists. How does that relate to the wind farm? I just wanted to bring in, in my mind, and I have this deep heritage of what I do, what my great-grandfather did. I sit at the same table that my great-grandfather did in the same house. It's really quite something. When I go out to plow a field -- we can't use plows, they don't let us use plows anymore, but when we go out to cultivate on the same fields that my great-grandfather was and turn up a horseshoe every few years, and it's kind of neat. I go, was that a horseshoe that my grandfather put onto a horse for his teams? It really is kind of unique. A lot of us in this society don't have it anymore, but I'm fortunate to have that. How I relate that to a wind conference, in my own mind, in our own area in the Montezuma Hills is that our society is really driven by economics, and economics of agricultural versus economics of almost any other enterprise, related mostly to housing in Northern California, it's pretty simple. If you can get housing in, it's going to come in, there is going to be a lot of potential profit throughout society, which is not a bad thing, but what comes at a large cost is mostly the ag land. The ability for our society to respect the land and to save some of it, set it aside for future generations. And in fact, a few things that I'm doing these days, I am on the Solano Land Trust, because I really do have a deep feeling that we don't -- this generation is not putting enough energy into that endeavor, and we aren't. Our own county is doing a fair job, some of the other counties I'm thinking don't really care anymore. How does that relate to wind? My thoughts were our land is on a thirty-year wind farm lease, which pretty much guarantees that that land is not going to have any conversion. We have Wind SAP, we have some of these other tools, but it's kind of a lock in for ag in the Montezuma Hills, which is not a huge area, it's fifty square miles, but it does -- it's good for society. It's sort of like the hydrogen, we are low energy input, we don't use any urban water, we are dryland farmers, that is a good thing for society, but we still produce food. On our farm we produce about the equivalent of six million loaves of bread, that is how much wheat is produced on our farm that goes out to our society. And about 500,000 meals of lamb, and it's mentioned goats, I don't know, not too many meals of goats. So what I was going to talk about was the good, the bad and the ugly of being a farmer on wind farm land. And the only really topic that I had was I can promote in 1981 my father and I each put in a little 10 kW Jacobs wind generator trying to be self-sufficient. I don't know if we were the first ones in our county or not, but we are very proud of that and they have actually worked out fine on our farm and produce enough electricity for our household. So I'm a net consumer and I kind of like the way our energy commission has made annual metering so I can produce it in the summer, use it in the winter, and at the end of the year if I break even everything works out. It was a large cash investment, and the government was involved, but it was a good thing. But as a tenant farmer there is some good, as a landowner there is a lot of good, because there is a huge cash flow relative to what comes off on the farming area. As a tenant farmer and as a person who lives in the Montezuma Hills, I'll start with the ugly. The ugly is simply wind farms that aren't planned out well enough, and if they fail what happens. And we have probably -- I don't know, it's not a horrid situation, but of the 14-year-old wind farm, 14- and 13-year-old wind farm, I would say 15 to 20 percent of these machines are not viable and will not be because of economics, but they still hang there. And I farm underneath it, so it's really quite a hindrance. I don't like blight. I don't like the look of having unutilized hunks of metal up there and falling on the ground. In fact, I had one employee who made one round one night. On the next round, the wind generator had fallen right where he had been on that last round. That technology of ten, fifteen years ago really may have been what it was, and most of us know that it probably, and I certainly hope, the next generation is where it needs to be. But it still needs to be dealt with as far as bonding, as far as the need to protect -- you know, to stop any of the blight of the old machines. I think to get a new permit, the companies there, I think the company should be at the same time made to make plans on what to do with the wind farm that is not running at high capacity. The other and the good side, as a tenant farmer that is fairly small, because what used to be my domain is growing a crop, there wasn't anyone else out there, and it was fine. A good would be that there is a road to get me out at the back end of the 160 acre field, that's good. But on the same side, on the hill here, and we are on the steep side of the hill, on the old wind farm there is quite a few roads on every ridge, they are every quarter mile, the banks of the wind generators. My equipment is made to go around and around the hill, if this gets to the side, it has to turn around and go back. It causes inefficiency, it's hard on the equipment, hard on employees, lots of double fertilizing and double spraying. So that's -- I would say the cost to me personally is a little bit more, it's more costly in loss. The gain of the road doesn't really equal the losses in being harder to farm. The newer wind farms that are much farther apart and fewer roads are much more convenient for me and probably more favorable because of less roadways. The present companies putting in the roadways are actually doing an excellent job of good quality roads, which is kind of nice for me. But the down side -- what else was I supposed to come up with for the good side? Let's see here. That's strictly speaking as a tenant farmer, which I was asked to do. I own property where there are about a dozen machines and it's a really strong cash flow for me, and I'm very happy. So I'm really a thumbs-up person related to the whole thing. The other small -- the problems as a tenant farmer relate specifically to the increased activity of humankind on that property. It's very destructive. It's a thousand-fold increase of people, and basically it's easier for me to move my livestock off the property. Cropping is not so hard, although we are having problems with -- mostly relates to the livestock industry. Getting the proper gates, getting secured property. This year I've had significant problems, both on the old wind farm and the new wind farm, trying to keep my livestock in. It seems like small issues should be dealt with, but it still needs some improvements, because the last thing I need to do to 250 lambs in a two-day period is going out and separating too much sheep. I'm trying to do my own economic business. So that's probably the biggest hassle that I face being a tenant farmer. I probably had some other notes, but that basically covers the major aspects of being a tenant farmer. I support the idea of renewables and it's a great thing, but it brings challenges as a farmer. (Applause.) MR. RUSSELL: We'll take questions. MR. VAN DAM: I have a question for Rick Roberts. You were very specific when you mentioned the High Winds Project, you said the roads they put in was about 2 percent of the property -- you lost 2 percent as a result of roads, et cetera, is the Williamson Act -- does it put a limit to that? Is 2 percent okay and 5 percent -- for instance, if you would, say, occupy 5 percent of the property with roads, is it an issue or is it completely separate? MR. ROBERTS: I guess when you look at the larger picture, the area the wind turbines -- the roads, the maintenance buildings, whatnot, have taken up have been insignificant in comparison to the project as a whole. A lot of the different agencies were involved in looking at the project itself. Environmental management of course in the county was -- that department was involved with -- specifically with approval of the project. And the local agency, i.e., the County of Revenue Management, had the prerogative to go ahead and approve the project. And, you know, taking into account the restriction of the Williamson Act, however, they are allowed under the law to approve that project, and that's such a minor consideration considering the overall project size. MR. RUSSELL: I want to point out, last year I was here and Mr. Cornwell was here, and I believe we were the only representatives of that class of people considered property owners. But this year we have Mr. Anderson, Ian, and if there is anyone else that are property owners, if you could raise your hand. The point being, we increased the interest in a way by over a third, and that may not say a whole lot. But I want to share a couple thoughts. After last year's collaborative forum, I sent a letter to Commissioner Eastman at the Energy Commission and expressed what I thought was a good idea, an idea that my -- you know, if nothing else, start a dialogue, and the idea was maybe it's time for property owners that are living in this wind -- either living in or own property in wind resource areas, maybe it's time to start evaluating and looking at some of their concerns. Is there a way to turn what could potentially be adversaries into advocates for the industry. And that was received very well. Commissioner Eastman, Chairman Keyes, the collaborative forum professors, White and van Dam, as well as the CEC, all seemed to say that sounds like a good idea, let's see if we can do something about it. And that is part of the reason this panel was put together today. I would have liked this panel -- I would have loved to have, say, more representation up here, more representation at the forum itself in attendance, but I want to ask, and I think there is a real nice way to do this -- they will get evaluation forms, is that right? MR. VAN DAM: We'll contact everybody through e-mail. MR. RUSSELL: I want to ask the question, if you could somehow get an answer back, is there interest and do you believe there is mutual benefit in creating some type of property owners' group or association. And I don't know that there is a group right now that that organization could slide under their umbrella. I think probably not, but after hearing Michael Sullivan's presentation yesterday, and every bullet where he talked about, you know, these issues, these things that cost money, you look at the owners, the property owners were somewhere in -- were mentioned frequently throughout his presentation. So I think this thing has got to go to the next step, this idea anyway. So if you can help, and I'll probably follow up using the roster with an e-mail asking and making some suggestions on how I think all of you in attendance might be able to help me do that. If you can help, great. If you have some ideas, great. But if you could forward these thoughts on, that would be wonderful. It could be the worst thing for your industry too, I don't know. I can kind of hear some of the wheels turning right now. I can't imagine, you know, property owners, you know, all of a sudden, We Shall Over Come or something like that, but I want to thank the panelists, Ian and Rick Roberts. If there are no other questions, I'll turn the closing over to Case. (Applause.) UNIDENTIFIED SPEAKER: I think it's a great idea, you should aggregate the farmer rancher throughout the country and form this organization. I know one farm that I have been to several times, it's on the state line, it's owned by FPL on the Washington/Oregon border, there are fifty landowners that have leases there, just the volume of them. They are not organized, they are not together in any way, except they all get checks, and they are all generally really happy. And of course that is the largest wind farm in the country right now, but that is just an example of the interrelationship with the industry, with the farmers and I don't know if really they exist throughout the country. So I think what you just said or maybe you gave genesis to is a great idea and I just want to reinforce that to the group as we give you our ideas, and actually reinforce what you just mentioned. UNIDENTIFIED SPEAKER: Someone else might know more about the organization, but there is an organization called Wind Industry based in the upper midwest that I know deals a lot with landowners across a number of different states and helps bring in information and shares stories. MR. RUSSELL: I'm familiar with them. SAME SPEAKER: I think they would have a lot of information that would be useful as we go through the process here as well. MR. VAN DAM: Thanks very much, and I think this is one of the items we want to keep on working on in the coming years and working with Rick and the others to get something in place. Kind of want to close things up. We are right on time, boy, we did this well. It's noontime, thanks very much for your attendance. We'll be probably in touch with you via e-mail, getting some feedback from you, some ideas how to improve things in the coming years. I think we are heading in the right direction. Send us an e-mail, give us a call if you have any information, have any feedback for us. Thanks very very much for your attendance and have a safe trip back home and look forward to being in touch with you in the coming period. Thanks very much. (Applause.)