Closed Caption Log, Council Work Session, 04/03/12 >> Mayor Leffingwell: Good afternoon. I'm austin mayor lee leffingwell and a quorum is present so I'm going to call to order the work session on austin energy for austin city council. It is tuesday, april 3, 2012, and the time is 2:07 p.m. We're meeting in the boards and commission room, austin city hall, 301 west second street, austin, texas. Turn it over to larry weis, the general manager of austin energy, to lead us through this discussion. >> Okay, thank you, mayor. Well, good afternoon. We have a very short presentation to summarize some of the points, try to capture some of the items on the agenda so I'll turn it over to ann little who will go ahead and go through this presentation. >> Good afternoon, anne little, vice president of corporate services at austin energy. The primary topics are budget reductions and line items and fees and responses to some of the questions city council asked in the first work session. I will pause after each division in this and see if there's any questions or any discussion. In 2003, austin energy developed strategic goals and they are summed up in our mission statement to deliver clean, affordable, reliable energy and excellent customer service. This mission statement alliance with the city of austin's mission and it also contributes to austin's mission to be the most livable community in the country. Over the years austin energy has become a leader in the industry in areas of reliability, energy efficiency, green building, rerenewable portfolio standards, customer service and also high credit quality. These are some of the has become a leader and how we are above the average utility. We have achieved certification from i.s.o. , customer care, power production. And these are standards related to quality management that ensures that we are designed -- dine our concepts and procedures in order to benefit the stakeholders and the customers. We've also spent about $20 million on early adoption of smart meters, and our system reliability standards outperform the industry. One of the things that we do that is unique to austin energy is our tree clearance communication with property owners. We -- we hang door hangers at each customer's door whenever their trees are going to be trimmed, and then we notify them and allow them to call us and we will come and actually show them which tree limbs we will trim and we shortcut those so that they are more -- so that the trees continue to look well. We also buy transform, that reduce line loss and we have -- we're developing a smart street light program that actually communicates back to us and tells us when the light, street lights are on or off and we can program these to be more energy efficient. Our key accounts are the best in the class and our customers assistance program are above average. In the area of sustainability, we also are above average, and carl robego at the last work session talked about this in detail. We spend about $30 million a year on energy efficiency and the green building program in order to accomplish this. The scrubbers at the fayette power plant cost about with $200 millions, and these -- now we have a coal plant that is among the cleanest in the state. We also use recycled water at our newest power plant in sand hill and that saves over 400 million gallons of drinking water every year and it costs or it saves us about $2 million. So this not only helps austin energy but it helps the environment and the community. We also have a community electric vehicle everywhere network program, and this was partially funded with grant money, but we expect to continue building on that. All of these things add value to the customer, and they come with a high price. And so we really cannot continue this leadership with our current rate. 's stage is to continue positive provide above average system performance and sustain its leadership and to provide affordable new rate structure and we want to continue to supply clean, reliable and affordable energy and excellent customer service. Okay, are there any questions on the leadership or our strategic goals? I'd like to talk about our budget reductions. began budget reductions in 2009, and some of the areas that we've been practicing cost containment ON ARE FTEs, WE'VE HELD Those flat over the last few years, we've also eliminated some f.t.e. positions. We've reduced overtime and call-back and reduced tree trimming. We continue looking at consulting and maintenance contracts and reduce those and we've reduced printing, supplies and advertising. This chart just shows that OUR FTEs HAVE REMAINED Fairly flat. In fact, they are almost the same as they were in 1994. The blue line at the top shows our growth in sales; whereas the red bars show our f.t.e. growth. This chart shows our nonfuel expenses, and it doesn't include the capitalized expenses, edrso debt or the general fund transfer. But I wanted to show you this so that you could see during the years of 2009, 10 and 11 that we've held these nonfuel expenses farly flat. The power supply and market operations on the left, that is our generation expenses. And even though they've increased, that was mainly due to our joint projects ftp and stp and the weather has also contributed to that, the hot weather in 2011. We did find savings, though, 2 million over the last few years in that area. In the electric service delivery area, which is the next bars, those show that we have actually reduced our costs from 2009 to 2011. So we've saved over $3 million in line clearance, engineering contracts and other contracts. The next one is customer care, and again, we've shown some savings there from 2009 to 2011. And we've saved about $7 million in shared services, temporary employees and meter readings. Distributed energy services includes our energy efficiency and the green building section. And they've also reduced their overhead. The support services include , accounting and other support services, human resources, and those have been reduced about a half a million for advertising and about $2 million in software support. The other expenses include city administrative support and other types of overhead, and the employee benefits include our pension and our health. So overall we've reduced these expenses about 3 million, and that includes the increases that come with inflation and materials and supplies and so forth. >> Spelman: Sorry to interrupt, that includes inflation. >> It includes just uncrease in cost is what I meant by inflation. So the things like materials and supplies and construction. >> It's real. >> Spelman: It's real, okay, thanks. >> This slide includes some of the cost drivers for 2013. So our target for 2013 budget is to keep it flat or consistent with 2012. But you can see from these cost drivers it will be difficult to keep it flat. Our joint projects with fayette power plant and look to increase about $20 million. Transmission expense will be recovered through tzar, the transmission recovery factor or the regulatory charge, but then labor, corporate and administrative services will increase about $10 million. And these are all out of our control. So it will be difficult for us to keep the costs flat, but we will try to reduce costs to off set that as much as possible. So for budget controls for budget year 2013, we expect TO HOLD FTEs CONSTANT AND Reduce vacant positions. We'll continue our internal recruitment. We'll evaluate contracts for additional cost savings, and the maintenance schedules, unless they affect our reliability. Then we will expand our debt funding on the capital projects which has been mentioned by the council. And I'll talk about that in a little bit. This shows just some of the capital expenditure deferrals in 2010. We deferred about $63 million of capital projects, and in 2011 another $74 million. And in 2012 we moved out the sand hill energy expansion from straight-line winds, that's the generation plant that we wanted to expand and we've moved that out to 2017. We've also purchased traditional power -- purchased power contracts for wind rather than acquiring or constructing new plants. And we've -- we keep budget -- we try to keep our fairly flat so we have deferred a lot of things because we had the fayette scrubbers and now that these are complete we'll fill these with some of the projects that have been deferred, hopefully. This chart shows our c.i.p. Funding history, and the blue bar at the top represents transfers in from reserves. So you can see over the years that we've transferred money in from reserves. The green bars, part of the bars show the cash funded portion of our c.i.p. And the gold bars show the debt funded portion of our c.i.p. So you can see from this that we are financing more of our projects with debt. Especially as the cash dwindles down. This is basically the same thing but it's another way to show the debt funded portion. And I know this has been previously mentioned by several of the councilmembers, and one of the points that we had made were that debt equity is hard to change. So if you'll notice the red line at the top, that represents our debt equity. And you can see that it's fairly flat while the annual percent of debt funding changes. So in 2006 we funded about 35% of our projects with debt. And if you move over to the right, you'll see in 2012 we expect to fund about 56% with debt. So we are increasing our debt, but because debt equity ratio has outstanding debt and cumulative equity, it doesn't change it very quickly. This section is on some of the rate assumptions, and i know you've seen this before, but I just wanted to review with you that we have taken your considerations and concerns into account and we've looked at the revenue requirements, but in all circumstances it looks like we still need a minimum of $71 million in 2013, and then in the next two phases we would collect the rest of it. We -- we have done cost reduction since 2009 due to insufficient rates, and we still will plan to hold nonfuel o and m budget slight in 2013 but it's not prudent to defer projects any longer or cut o and m any deep. It will be difficult to continue to -- supplys like wires, poles, transformers and vehicles. The only way to reduce risk of uncertainty which includes these risks listed up here is to have flexibility. And our operating cash now is below minimum. Reserves are below minimum, and our line of credit is limited. So the major projects have also been deferred for years. So if any of these risks occur, then it will be difficult to manage with the existing budget or even with a rate increase lower than the 71 million in the next year. Our strategic goals and our industry leadership are at risk and without increasing reserves, they are inadequate to maintain our financial integrity goals, deferral of projects puts reliability at risk. And resource constraints hurt the customer service area. We also may have to contain the dsm and the renewable energy goals. Are there any questions on any of that before we go into the line extension and fees? >> Mayor Leffingwell: Kathie? >> Tovo: Thanks. So you had addressed some of the budget cutbacks and i appreciate that. I just want to return to a question I had asked in one of the earlier q and a discussions. Could you -- I don't know how we can talk about this because I think the recommendations as I've looking over them from the report are on one of the confidential pages, but they had some specific recommendations and I can tell you where they were on page 22 of the bench marking and program review executive summary. And I -- I had asked the question which recommendations have been implemented, and in explored the recommendation for potential savings noted on page 22, and the response was really talked about the second part of the question. I guess I'm just wondering if we could continue a conversation in some venue about whether some of those cost savings have been pursued and if you've got any estimate of what the cost savings might be. I'm sorry this is a crazy way to have this discussion without any specifics. >> Unless there's specifics on numbers, I think we're probably okay to talk about it. My opinion is. Andy? >> Tovo: Shall I hand it to our attorney? >> Mayor Leffingwell: We have the ability to go into executive session. >> Tovo: That's okay. Maybe we can just take it up separately. But --. >> Mayor Leffingwell: Your mike is off. >> These bullet points are general. From what I'm seeing here, you are probably safe to talk about it. >> Mayor Leffingwell: We're okay to talk about it. >> Tovo: So the first was review the engineering workload to see if there's enough variability from year to year to warrant increasing the amount of contracted engineering service. >> Been done. >> Tovo: The second was continued development and implementation of the craft multi stealing program to reduce the craft compliment at decker and sand hill. >> A lot of that has been done. I would say that's been done, but I'd have to talk to jackie and sheryl about that, but a lot of -- a lot of those have been done. In fact, for a large degree when I went through the whole sit-down with the report, I wouldn't say that -- I don't want to say -- a lot of those are very obvious management issues that needed to be addressed. I think they are very generic, the utility and -- but yet they were pointed out and I certainly took notice of it, having just come aboard when that report was done. But a lot of those have been done. >> Tovo: Are those reflected in some of the savings you showed us earlier? >> Yes. I'll give you a example of that. One action that -- that i took coming here in the fall of 2010 was we no longer were going outside to hire and recruit all new employees. We did an internal posting first. So that's one way to address the second part of that question to try to build the skill set inside. That's just one tool. >> Tovo: Great. And then the last one was implement a formal cap x process for justifying capital expenditures. And I think -- I think the second part of my question on that same rfi talked about that. There was a fair amount of discussion in the navigant report about how -- about establishing a process for evaluating capital expenditures and new capital projects. And I guess I was interested in that question whether there had been a new process of really identifying and evaluating capital projects. Since the navigant -- since the time navigant looked at it. >> Well, I took that to be there really needs to be overall management oversight in all of our capital planning and looking at the strategy where are we going with that planning and the result is we pushed the addition of a sand hill generating facility which is $200 million off by a couple years. That's just one example. There's been a number of other moving examples between all of our substations and all of the infrastructure building that we're doing. And so I would just say that is ongoing. It's part of our job to make sure that we look at that, my job in particular, to look at capital plans and strategies moving forward. And I work with ann and our accounting folks to see where we are in our planning of our budgeted. This year in a new budget for this coming year, we will have done a really good job of scrubbing capital as what we're plan to go build this year. Most of it is make sure we've a reliable system and address customer growth. >> Tovo: It sounded like they were looking at a different process, beyond just analyzing the upcoming projects and making sure they are still warranted and necessary and all that. I mean, my memory of having read through it is that they were looking for a more formalized process of review. Was that your impression too? >> Well, I don't really know because after the navigant report, the navigant report to me was a high level, almost generic in some areas, not specific to austin energy. In other words, I don't know that they actually spent a whole bunch of time looking at how we justify our capital programs, for example. I mean, I don't know that. But I think what I read out of it was that we need to have a method and we should have an executive driven leadership driven exercise that we go through to make sure that we have the capital planning in place and we know what we need to build or want to build. Maybe we don't want to build some things that we can put off for a few years. There's a variety of different tools you can use to do that. We don't have a tool I can give you an acronym for that we use to -- >> Tovo: If you gave me an acronym, I probably wouldn't be able to -- >> that's how we go through that budget process. >> Tovo: Thanks. >> Mayor Leffingwell: I just want to reinforce about what you said about adequate o and m funding. I can think of one example, it's not the electric utility, but the water utility, where back in the MID '90s THE COUNCIL Refused to raise rates and the result of that was -- there were several adverse effects from that. One was that the utility was forced to refinance some of its indebtedness and defer payments on principal for 10 years. Now that's come back to haunt us. In addition to that they were unable to adequately maintain the wastewater structure. A great deal of which is located in our urban creeks. The result of that was in issued an administrative order making us make those repairs and from sewer overflows, the damage done by that. And that wound up costing $471 million. Those are the kind of expenses that come back and many times the original costs to maintain them come back and cause the rates to have to go up disproportionately in later years. I just wanted to reinforce your comment on the importance of being able to maintain that funding. Bill? >> Spelman: I agree entirely with the mayor on the issue of deferred maintenance. It's a point where it ends up costing a whole heck of a lot more. Am I right in presuming this is the shadow of the future costs is what you are looking at when you are deciding what to defer? >> That's right. >> Spelman: You mentioned that you scrubbed the capital budget and my guess is then not only are you deferring things you can afford to defer, but you are also eliminating projects or reducing the size of some projects which we don't need to do. Is that accurate? >> That's correct. >> Spelman: Could you put a number on that? >> We would have to get back to you on what that number is. Probably starting point we just had, for example yesterday we had an executive team meeting where we had our project management group come in and talk about the different projects we have going on around the utility. That would -- that presentation itself would give you an insight as to what we're doing because we've budgeted and targeted goals for capital infrastructure, for example. I can name some substations that we're building. And they are coming in at our under budget on those. So all of the staff are looking for ways to cut the capital costs of these projects we have to build. To a large degree, most of these projects are either to serve new customer load or to provide increased reliability where we need to and also enhance the ercot grid which we in turn get financial compensation for. And so we're looking at really those three places that are the primary work we're doing. But a lot of substations. I think right now we have about eight substation projects going on. >> Spelman: Okay. So it would be -- it would not be inappropriate at all to say that our total capital improvement program is smaller in size than it would have been had you not done all this stuff. There is a number out there and if you could provide us with that, I'd sure appreciate being able to use that. >> Sure. >> Spelman: The other half of that is o and m costs and on the first slide you have a list of expenses since 2009. In order to cure the deficits, in part, you've had to cut back in o and m expenses as well as deferring capital expenses. Of the expense reductions in this list, in another list that you might also have, what proportion of this stuff is temporary, short-term fixes that you can do for a year or two but eventually you are going to have to replace those o and m expenses, in the form of deferred maintenance, more or less. And how much of this is permanent and systemic? >> For a large degree, most of this is permanent. But reduce tree trimming, you can pull back on tree trimming and then you will have a situation where whether it's mother nature, whatever controls it, you have a situation where we have to step up because we've gotten behind in tree trimming problems. So that will kind of ebb and flow. THE NEW FTEs, I MEAN FTEs AND LABOR, OF COURSE, With a utility this size is a big driver. And I feel comfortable that we have a sustainable model FOR THE NUMBER OF FTEs AT The utility. That's where the creative comes. In in other words, we might not have the same number of employees by title in different areas, but the idea so to keep the head count at the right place. So I think that's sustainable. Now, for five years or ten years, I don't know. But in the near term it is. >> Spelman: Okay, so in the near term you've reduced expenses on o and m. It's x percent cheaper could you put a number on that? >> We can put numbers to that. >> Spelman: If you could, that will be helpful. Not only capital but o and m expenses in real terms are lower than they would have been had we not had to go through this drill of losing money every year and centering to find a way of recouping. >> Right. >> Spelman: And this is systemic and permanent at least in part. Some of that stuff is going to have to come back. I presume the tree trimming budget may have to come back, some of the rest might, but there are systemic and permanent changes in the way we do business which is going to cause our costs to go down over the long haul. >> A lot of it is driven by the economy. So for example if our service area really starts to expand, we really have to build out to serve customers and we get on a more rapid pace for substations, a more rapid pace for building out our system that is correct means more employees, that means a lot of different things can happen. And we do that today. We manage our growth with -- by a combination of mostly full-time employees in our council instruction arena, but we also have contractors that come in so we tend to handle peaks and that gets into the contractor services and that's how we try to balance so we don't have peaks in employment and then when construction goes down with a problem with too many employees. That's pretty typically done. >> Spelman: Fairly much industry standard. >> Yes, sir. >> Spelman: Last question. I'll sound off, I'll stop talking. If somebody were to say -- I'm a little tongue tied today. It's the tuesday effect. Our rates, accurate to say, are lower than the average for utilities in texas, INCLUDING MOUs AND CO-OPS AND IOUs. >> Yes. >> Spelman: And it would be accurate to say that our cost of generation distribution are lower than the average utility in texas. Would that be a correct statement? >> On not necessary -- i would say that on distribution and transmission and all the operational components, but our fuel mix and the type of power supply that we have is not necessarily the same as others. For example, we do not have a large percentage of coal in our generation mix. We're about 20%. You know, there's a neighboring utility down the road that has about 50%. So that mix changes it a lot. >> Spelman: Okay. >> When you look at the generation. But that's all in our power supply which is not necessarily outside of our rates but it is a separate charge, you know, that's there. I know you know that, but it's -- >> oh, I understand. Okay. So holding fuel mix aside, are northern fuel costs -- our nonfuel costs are extremely competitive but we have slightly more expensive coal. >> More renewables, a lot of things. The challenge here is as our portfolio moves into the goals that we have, the way to contain and make up that difference in cost is by being efficient. And I think that austin energy got that signal not two years ago, they got that signal a number of years ago and started moving in that way. And ever since 1999, which at that time there was a downsizing in austin energy, they've been very careful, in my opinion, about coming back. >> Spelman: I know you've been receiving collectively signals since at least 1999. Thanks. >> Correct. >> Mayor Leffingwell: More recently just follow up on that, we had discussion a year and a half ago about with the generation plan. 35% By 2020. Also put cost containment in there. Remain -- and the original thought was remain in the bottom 40% of public and private utilities statewide with the rate structure and contained costs to 2% and you specifically asked let's say bottom 50% just to make sure we're able to comply with some other goals too. So that is in our adopted energy policy right now. And not only are we below average right now in the bottom 50%, but we'll remain in the bottom 50% in the future. Laura? >> Morrison:. A couple of followup questions. On the issue of the navigant report, maybe you would want to do this in a report back to us, give us a brief description of the outcomes. You said pretty much you've been through all the recommendations on the cost containment, things to look at, if you could just give us a brief summary of the outcomes of those. And you don't need to do it right now. If you want to just get back to us. >> I can, but let me make this one comment. Because what I don't want you to be is disappointed with what you get back. And that disappointment -- >> Morrison: Well, appreciate that. >> The disappointment would come from the standpoint that when the report was done to assure the city manager that there was some validity to the serious financial condition austin energy was in, and -- and that was the purpose of the report. It was also a report that was done for me. So at least when I got here I knew a little bit about what maybe to expect and what outside industry experts thought austin energy could do in some of the areas. But they did not get very specific. In other words, there wasn't -- the amount of contract for this amount of work, the amount of dollars was frankly kind of -- frankly small. But it was just to do that one part of the project. And then to go beyond that would require either the consultant or us, and in this case mostly it's been us, take a look at all these areas and make sure that we address them. So we can do. That we can go back and look at their recommendations and try to go line by line. But there wasn't any more to those recommendations than what you read. There wasn't any more specific line item action, don't build this generation plant, don't do this, don't do that. You know, it didn't get that specific. >> Morrison: Yeah, know, i understand that, but I just think it would bring a certain amount of, you know, confidence in being able to respond to, you know, constituents who by right are saying are you sure that austin energy is doing what they can and for us to say, well, we have an independent report, I'd like to be able to say that yes, they have paid attention to each one of those and responded in some way. >> I understand that. I understand that. And I understand the need to make sure our customers know that we did do that. >> Morrison: That we can answer those questions. >> Absolutely. Right. >> Morrison: Okay. Great, I appreciate that. A alluding to the cut backs in -- I'm looking at slide 7 and it's showing the NUMBER OF FTEs IN RED Dropping pretty seriously between '96 and I guess 2000 was the low point when it went from about 1700 to 1300. And I don't know if there is anyone, maybe someone here might be able to talk about the effect and what was going on because that's a pretty -- that's almost a 25% cut. And how did the -- it makes me question how did the utility even get along with only 75% -- I mean, the amount of energy that was being provided at that time isn't that far off from the ballpark that we're in now. And I realize that means we would need to ask that question of someone who might have been around in THE LATE '90s AND I'M NOT Sure -- >> there are people that we can tap for that, but I have asked that question more than once and received answers. There was a study done by an outside consultant in the LATE 90s, AND I BELIEVE The city megger at the time commissioned it -- manager at the time commissioned it, and it was to really take a look at austin energy's costs and what we can do to cut it. And there was a study done and identified I think almost like 300 positions that could be phased out of austin energy's operations. Unfortunately they went through with it and my understanding is is that it caused a lot of -- a lot of problems at austin energy for a number of years. And they had to climb their way out of it. And I can't really speak to it more than that other than I can bring -- I can have elaine come up to the table. I think she was here at the time, and maybe fill in gaps on that. >> Morrison: That would be great. And also just in terms of answering questions from people, if someone says how is it that austin energy was able to operate on only 75% of the workforce, and it would be helpful. >> I think the short answer is that they weren't able to do that and they had -- it caused a lot of problems. In fact, a number of really high quality employees left, retired, quit. >> Morrison: Because of the difficulty. >> Because of the difficulties of that and that lack of leadership also turns into a problem, right? >> Morrison: Absolutely. >> Excuse me, I was hired at the utility in 1998 as the consul was leaving, and there were about 300 positions eliminated as a result of their restructuring work. It was part of a effort to get ready for the expected deregulation and so they looked at every function in the utility and determined if that function was going to continue to be needed. An example of some of the reductions that they made, they eliminated our load forecasting section because they didn't believe load forecasting would ever be needed again in a deregulated market. In fact, that's something that's very important to us today. Finance actually had one person, that was an engineer, left in our department. At the utility and that was the only person out of about eight people that used to be load forecasting. So that's one example of the kinds of reductions that were made. We've added some to that, but not a lot over the years. But there were a lot of difficult feelings. The employees were told that they all had lost their job and they could reapply for the few jobs that were left. And so you can imagine the impact on employees who did get retained or were able to be successfully hired again, you can imagine how those that were left and those that did not have a job felt. The 300 that didn't have a job certainly took retirement if they could, looked to other utilities near and far to gain employment, but it was a very difficult position for the utility to be in and it was coming in at the end of that process, you could feel the pain in the organization. And there's no other way to describe it was just pain. And, you know, over time there was this rebuilding that larry talked about. Certain functions we had to do. But load forecasting is one of the foundations for our financial forecast as well as our generation planning. So you have to have it. It's not something that you don't do. And that's just one example. Subsequent to that time one of the improvements that was made, and I do think it's an improvement, utility customer service had been in the finance department, the financial services in the general government entirely before that time. And subsequent to the consultant, they consolidated utility customer service into austin energy, and that has become its home and I think that's been a good home for the utility to have the customer service function right there with its executives and i think that's a vast improvement that did come out of that work as well. There's good and bad that came out of the work. Another example of consolidation during that time was the energy efficiency programs or conservation programs had been in a separate department, and those were consolidated into the utility in about 2000 or 2001 and they've remained there since that time. And I think that's been a good partnership to have that in the department. Because it's the key part of our generation plan now and our resource. So there are some good things that came out of it. Certainly some downsizing was probably appropriate. Did they cut too deep, i think the organization felt they did, but I hope that gives you some perspective. >> Morrison: I think it does. I guess it gave the utility an unfortunate opportunity to try to become mean and lean but it went a little too far. Thank you. That's all the questions. >> ON THIS NUMBER OF FTEs, I just wanted to ask, are these specific to performing austin energy functions or ARE THOSE OTHER FTEs THAT Are funded out of austin energy's gross revenue such as 311 center, code compliance, egr. Are those all part of this number or are those backed out in some way. >> They are part of this number. >> Martinez: Can you give us a clear picture of -- or is there a true definition of a austin energy employee as opposed to being funded by austin energy? >> We can break that out in the different units. >> Martinez: And it would be helpful if you did that, and I know this is some work and you may not have that data, but when you go back to those years when we were forced to cut, was the consultant saying cut nonaustin energy employees, and I'm making that term up. I don't know if they existed to that extent back then. I would suspect not as much as they do now, but it would be helpful to know over time, you know, how that number has increased and/or decreased in terms nona.e.-related employees. >> Right. I want to -- we can do that. I know what you want and we could put that together. I want to also emphasize that since that time, i don't know what the numbers of employees are, but nationally we've entered a time of reliability requirements that are just huge compared to what they used to be. So we have entire new departments and regulations and rules that turned into LOTS OF ADDITIONAL FTEs And highly skilled ones, i should say, for all of our nerc compliance, which is the national electric reliability council, and ercot compliance work and everything that we do to emphasize that came down from the federal government a more reliable and functional grid to operate in the united states. So we have that new business. So when I look at it, when i looked at it before, i looked back to since that time there's obviously some professional positions that got cut that really didn't need to be, but then how many more additional employees were put on to do the new jobs that we needed to do and handle the new growth that we needed to do and the new enterprise we needed to do. For example, we have a really good chilled water business in the utility. I think it's a fascinating business and I think it's going to be very, very successful, but we have all of those additional employees as well. We've entered into some new projects and we'll try to lay that out for you. >> Martinez: I think to me it's the most objects that are performing functions that wouldn't be energy related. We argue economic growth is energy related bus it increases consumption and demand for utilities and we charge for it, but I want us to separate that out. >> That example that number is separated out. We have a lot of climate initiatives and a lot of other actions that we've done are corrected to what we do, but tonight. >> Martinez: Thank you. >> Mayor Leffingwell: Just to follow up with that, it's not only expenses that are outside the utility and perceivably unrelated to the operation of the utility are funded in some cases by austin energy, but it's inside the utility itself. And you mentioned a couple of them. You know, that don't have to do directly with the generation, transmission, reliability factors, and i think we need to identify those extra costs, those extra burdens that have been put on the energy company largely by council action through policies. So if -- if additional cuts are necessary, we can see where those cuts could go without affecting the reliability -- the reliability and cost to our customers. Is that clear enough? You know what I'm talking about? >> Yes, sir, I do. >> Mayor Leffingwell: Okay. >> Mayor? >> Mayor Leffingwell: Sheryl. >> Cole: I am kind of disturbed by the slide that pointed out that even if we did $71 million rate increase in 13 and then 31 million in 15 and 16, 25 million, we would be in noncompliance with our financial policies all the way down. I'm wondering could you walk me through what policies those are and what we can do about it? >> I can't give you exact details because we have not prepar budget or forecast yet, but just running some preliminary examples, it appears we will not replenish reserves to the levels required in the financial policies. >> Cole: So is that the main concern, replenishing reserves? Is that all reserves or emergency -- >> even the working capital will -- and currently it's below the minimum level right now, the working capital. >> Cole: Remind me of the terms of the working capital budget -- I mean reserve fund. How does it work? >> It requires us to have at least 45 days of operating expenses without fuel. >> Cole: Have we ever -- and even if we make this rate increase, you don't believe that we will be in compliance with our financial policies or -- >> if you remember on the revenue requirements, we broke those out into what was the mandatory operations and then we deferred the replenishment of reserves until 2015. >> Cole: Zero. I remember that. >> You are looking at almost break even, but you won't collect that money that quickly. So it puts us at a deficit even in 2013. And so we won't come out of that probably until later on. >> If you look at slide 33 in here -- they don't have that. Oh, I'm sorry, you don't have it. >> Cole: But I guess you are going to present it later. You'll get it to me later. I know we talked about a reserve neutral for at least one year. >> Yeah, it's not in your package, but it's on the -- it's on the screen. >> There we go. >> So basically what it does is it -- it takes you -- i can't read the numbers. In 2009 it shows you where we were about in our test year, and each level represents a different reserve fund. So starting at the bottom you have your operating fund, and then you have your contingencies or emergency reserve fund, then the contingencies and it worked up to all of the funds. In 2010 you can see that we've used most of those reserves. By 2011 we've used all of them except for the emergency contingency and the operating fund. And then as we move through this current fiscal year, we've depleted everything except about $30 million of our working capital, and it should be up to about 50 million. And then the reserve -- or the emergency portion of the strategic reserve fund is adequate, but the contingency is slightly under the level that it should be. And in order to move through 2013, that gap increases to about $162 million. And if you look at those, the horizontal lines at the top, you can see that the top one is the maximum and the orange one in the middle is the minimum. So we're way below the minimum even now and it will continue to be depleted in 2013. And that's where the 71 million. -- With the 71 million. >> Cole: Ann, help me understand what that means in terms of risk to providing service to customers. >> It definitely increases the risk. Some of the risks that are related to weather or outages, anything like that could cause us to dip into or completely use up the emergency reserve. So we need to start replenishing the reserves. That's what they are for. Everything else in the revenue requirement is for normal iced typical year. The reserves are for the nontypical items that do occur and will occur, it just is a matter of time. That's why it's necessary and required in the cash flow methodology to replenish your reserves to adequate levels. That's part of the run that is allowed by a utility. >> Councilmember, a specific example would be if we had a power outage that was unplanned in the summer and we didn't have sufficient cash to pay for the purchased power, we would have to use the reserve and then we wouldn't have the luxury of waiting until january to raise the fuel rate. We might have to raise the fuel rate in the summer to immediately recover from our customers the money that we had to pay for the purchased power. That -- that's the situation you can be in when you are under your minimum levels. And that's -- >> Cole: That's a risk we have to take and be aware of. >> Right. And the proposal that we have on the table is contemplates and plans that we will not be able to rebuild the reserves right away. So we feel that we can operate that way, but that's not -- >> Cole: Prudent. >> Well, no, I mean we need to make sure that we have a solid forecast and we can see ourself climbing out of it. >> Cole: Well, I mean, these financial policies have been around longer than I've been here or you. >> A long time. Right, exactly. >> Cole: For a reason. >> Spelman: This is 2013 forecast in the absence of the $71 million increase or -- >> no, it includes the $71 million increase. If you remember, for the last four years we've been running a deficit of about that amount, and we just -- that's why the cash is being used up. And it will take us a while to get out of that deficit position. So that's what you are seeing here with the $71 million rate increase. >> Spelman: Okay. But now we're not running a deficit with $71 million. The cash is just draining because -- >> right, it's -- >> Spelman: There's a lag between when the money comes in and when we have to spend it. >> Right. Our revenue is inadequate. >> Last year when we put our budget together, we thought we would have these rates in place before we actually will get them in place. So there's an additional cash drain that is causing this situation to be a little bit worse now. >> Spelman: For fiscal years 2013 and 2014, presuming we get you a rate increase at the time we expect to get it to you, is that number likely to come up or is it going to stay at that low level if we get a further rate increase downstream? >> No, it will come back up. After phase 2 when we can replenish the reserves, you will see it gradually come back up. That's our hope. >> Spelman: My question was about with the next two fiscal years. We're going to be stuck with a cash situation that looks like this for the next two years and only when the $71 million rate increase kicks in will we actually start to see it come out of that. >> >> Spelman: How many days reserve is this? The standard we've been setting for ourselves. >> In 2013 the working capital is completely depleted. And so is the contingency. Only some emergency is left. >> Spelman: So basically our reserve is zero. >> Right. >> There's a slide in our rate presentation that I'm going to see if we can't put up that demonstrates this. But it -- it shows that we have $138 million strategic reserve. That's the one, that's the -- that's the cash that you hide away. That's the one you really have to have. It does not forecast us getting into that, but i don't think we're going to be able to accurately say we do or will or won't be able to get into that cash because it depends how the year goes. And I think that's -- that's the part that concerns us right now is that that's really the strategic reserve that's in place that you never touch. And that's -- that's the policy area where we would have to come to you and get permission to get into that cash. >> Spelman: Thank you. >> Cole: Councilmember morrison. >> Morrison: I just want to comment that this topic of one of our -- our first work sessions, and one of the things that we had on our agenda today was to sort of revisit and see if we had consensus about some of the approaches to some of these things. And I thought now might be a good time to slow that out since we just started talking again about reserves. Because I think that -- my understanding was there was a pretty good consensus of moving forward just so keep the reserves neutral at this point, basically to adopt that -- that $31 million not in this -- necessarily in this -- in this rate increase. And at the same time there were discussions about changing the replenishment rate to five years for the ones where the financial policy does not identify a replenishment rate. And we are calculating it as three years, so talking about perhaps doing it five years. And the third thing that i recall that we were sort of circling around was the issue of whether or not it made sense to have this third strategic reserve, the rate stabilization reserve. Does anyone remember any of those discussions? >> I do. >> Morrison: Okay. Good. Those all have bearing on what kind of action we're going to eventually take on the rate case. >> I do have some slides to answer some of those questions that came up in that first meeting. If you want to move over to that section, we could move over there. >> Cole: I wanted to say that with the mayor and councilmember martinez not here, I want to be careful not to take any action. But I don't have any problem at all with us having some discussion. Or that it's sounding like we're giving staff direction to do x, y or z. >> Morrison: And we're posted for preliminary action, so I'm totally fine. Why don't we wait until they come back and I hope we'll manage our time so we can circle back around and take a relook and regroup on those first three work session topics. >> Cole: Aren't you saying that they mirror what we're talking about now? >> Morrison: We did sort of get around to one of them. I just want to make sure we're very clear. >> Cole: I'm guess I'm asking do you want to do that right now? >> Morrison: No. I just want to make sure we manage our time properly. I think that's very important. >> Cole: I agree. Are you ready to continue with your presentation? >> Tovo: Mayor pro tem cole cole councilmember tovo. >> Tovo: In the interest of managing our time, i wonder if we could take a minute or two and regroup about how we want to spend our time. I think we are going to need at least 30 minutes if not 45 to make some of those preliminary actions if we are going to take them, especially if there are slides that respond to some of the questions from if first session. >> We have one more small section we could do on line extension. >> Tovo: That sounds great. I'm trying to get a sense when it might make sense for us to wrap up so we can turn to taking those preliminary actions or at least -- >> Cole: Why don't we finish the presentation and then go straight to those issues since they are kind of fresh on our minds. And you can get those other slides or whatever. >> Morrison: Could I just add we also have on our agenda to hear from mr. lazarus. >> Tovo: We have a lot on the agenda. Maybe we can agree to stop times so we can move on. I think we'll need to turn to preliminary actions if we are going to have that piece 15ish and we have to talk about line extensions and disconnection pieces which I know you are moving into and then we have the decoupling piece, so that's a lot. >> Cole: Can we think of timing we'll give you five minutes to get through your last presentation and discuss that. And then we'll go ahead and budget 20 minutes to talk about the reserve items that councilmember morrison wants to talk about. >> Morrison: There's actually several items we need to talk about. >> Cole: I saw the postings. >> Morrison: The items we've already talked about. >> Cole: I saw them listed here. >> Morrison: We need to talk about debt equity, reserve -- debt equity ratios, reserves, general fund transfer. We talked about solar and energy efficiency caps and, of course, the other things that we're funding. Besides the general fund items. >> Cole: I don't think it's reasonable we can get through all of that today even if everybody was here and we had all the staff. But I want to hear the feedback. >> Spelman: Are mayor leffingwell and councilmember martinez coming back or have they left for the remainder of the session? >> Cole: I believe the mayor has left for the remainder. >> Spelman: I would feel uncomfortable taking anything, any action without the presence of the mayor. >> Morrison: I do want to say we've discussed all of these items at length, so the idea was to just see if we could -- and I think we landed on quite a few things. So it's a matter of trying to find the time to delineate those. So maybe what we could all do would be to try to get a summary of where each of us landed just personally between now and the next work session and try and address these things at the next work session. If we've all sort of reviewed and tried to remember where we were, we could maybe be very efficient about it. >> Tovo: I agree. The intent was to take some preliminary action before the end so we don't have to go back and revisit all of these issues at the end and try to regroup and, you know, ask you for more information and more questions. I think the more time that passes the more difficult it is to remember some of our consensus points and, frankly, remember the complexities of some of these issues. I would suggest we try to do it at our next work session and I think it would help if we individually regroup, but I agree we need everybody here. >> Cole: Perhaps we need to have a work session that is just an action session only and post what we want to take action on and not even possible action or even possible action, but just that session where we're not also getting all presentations, you know, so that everybody knows we're actually -- because, again, I don't want to take action without. Can you recall agree with that? So let's try to organize for the rest of the presentation to mostly receive staff presentation, ask questions about that and then maybe move around and discuss. >> Morrison: And we do need to get to the decoupling presentation. >> Cole: I know. >> Yeah, the next part of this was an issue about line extensions. So let me go back to the beginning and tell you -- define what a line extension is. All utilities have different philosophy and different pricing associated with hooking up new customers. So when new customer comes to the utility at austin energy today, austin energy has a philosophy and has operated many years this way and I don't know what the history is and I don't know if it's ever been any different, that we virtually do not charge much at all to hook up a new customer, regardless of sight. Residential is very small amount. On the other side you have utilities that charge a lot of in other words, they recover all of their costs associated with hooking up a new customer. So therein lies the goal posts, if you will, between the two philosophies. The electric utility commission, my understanding is over the years, has suggested that one of the ways that austin energy could reduce its costs is in effect be reimbursed by customers for growth. And so I can make this report pretty short by you that we have a study underway. This is not connected to rates, but in the end it is part of our revenue requirement. In other words, if we were reimbursed for a large amount of new customer hookup, we wouldn't need as much cash to operate annually because it would be coming from the new hookups. Art? It's as simple as that. But I have asked for a study about a year ago. It's taking a lot of work. The people that do that work all happen to be involved with the rates work. So it's -- it's -- so part of the plan was before we come back for the next part of the rate that we would have this work done and we would be able to fold that recommendation into the second phase. Which means that if the policy is to change how we do business today, that would mean that second piece would be less, correct? Now, you might want to know how big a number is that, and, you know, what is it, and I want to know that too and I don't have the answer for you. So that's where we are with our line extension policy. >> Cole: Let's see if we can get consensus on this because we've been following this. I have a real strong sentiment that we should charge for our line extensions. It basically helps growth to pay for itself. Of course, we need the information from the study, but unless people need to berate this point any further. Everybody says we can move on to some of the other issues that we need to discuss. >> Excuse me, but keep in mind this is a fee, not a rate. So we will bring this up as part of our fees. The way that we do fees, disconnect fees and all those fees are done as part of the budget. We produce a fee schedule every time we introduce a budget. Is that right? And so when we introduce the budget, we'll have a fee schedule and so my expectation is that when we're ready, we will address this through the fees and it would not be through the rates. But we know the connection. We know the connection between the revenue part of it and not. And so we'll do the work. >> Cole: Councilman spelman and then councilmember morrison. >> Spelman: When will you have the work done? >> By the -- by this winter. >> Spelman: So it's going take the rest of the year to nail this down. >> I'm trying to remember the -- the performance or i was I gave the people that work me mow that are producing it. I think it was by this winter to have it done for review. And to look at it. It's interesting to me because austin energy obviously hasn't gone through this exercise before because they really don't have the experience going through this so I'm having to exert leadership in getting this done. >> Spelman: Is that i can't it's taking so long? >> In other words, if you were aligned personnel for the year, how much did you work on customer work and how much did you work on putting the system back together. That's the kind of detail we need to put it all together. >> Spelman: Okay. Do you have a sense the costs for charging are a little bit or a lot below what our total costs are? >> Well, it's really not a cost. It's really a philosophy. But let me say it this way. It's far below what it will cost if we were charging 100% because we're not at all t philosophy is we welcome growth and as growth comes on, all of the customers pay for growth. It's not uncommon for public power utilities to have one philosophy or the other or to pick a place in the middle. So it gets beyond a pure business decision. It gets into a philosophy of how you want to address growth. And -- and, you know, I've lived with several different models and this one is unique and it has a certain public power of value that has worked here in austin. Worked very well. >> Spelman: I can imagine it working really well if you are growing about a percent a year like the average metropolitan area, but when we're one of the fastest areas in the country it doesn't work very well. >> Right. So you have a lot of unreimbursed capital and you have a lot of labor and material going to growth. When you hook up a large building downtown, that's not a large amount of money to hook that up for the amount of revenue you get or the amount of sales. But when you have urban sprawl and a lot of housing development and other types of distribution system impact, that's when it can really hit you. >> Spelman: Exactly. Will you have sometime between now and the end of the year preliminary estimates you would be able to share with us just to get a sense what kind of numbers we're talking about and what effect this would have on bottom line? >> I will do my best to try to meet that. Again, what we have on the table, the second part of that, in my mind, that is a piece of what has to be done before we know what that second part needs to be. But today looking forward, we know that our current line extension policy is what we're using on support our revenue requirement. It is not -- I'll say this, it is not my educated guess on this, it is not a number that swings a long way one way or the other. It's not a magic solution. >> Spelman: Growth may not be paying for itself, but it's not costing us that much. >> Right. >> Cole: Councilmember tovo. I'm sorry, councilmember morrison. >> Morrison: Thank u do we know when we last changed these fees? Not in our memory? >> No, she's been there since 1998. So -- >> Morrison: Okay. I just -- I don't know if there's an option to do this, but if we're talking about it not being finished until the end of this year, it's probably not going to get into a budget until 14. I just wonder if there isn't some outside help that could actually pay for itself by getting this done earlier. Because it's really frustrating, you know, that we're having to wait yet more and I think there's a strong drive to get these to cover the real costs instead of all of us paying for it. >> My goal was to have it known and be able to make a decision upon it before the second piece came about because that's really what it would effect. In other words, we can't get this done now for the proposal that we have now. Whether we had a consultant or not. The way it works in the utility business having a consultant come in is our financial people have to tell them everywhere to look anyway. So it really doesn't end up being a big help -- now, what does help by having a consultant is to say, all right, here's what everybody else does with line extension fees, here's the industry norm that is correct type of work. I think that would be helpful and -- cost of service studies anyway, this is a cost of service function. It is something that you typically do as part of a cost of service function. So we'll get it done as fast as we can. Our goal is to incorporate that into the budget cycle that you are correct it would be the 14 budget cycle and it would be hopefully we would be able to deal with that long before that so we would know what impacts that would have on the second part of any rate change. >> Morrison: If we do a second part, right. Then the last point I want to make is I understand, and lezar might talk about this, there are some folks that are looking at charging different hookup fees, connection fees depending on especially houses out in the sprawl area, depending on how much -- how efficient they are and all of that. And so I wonder if looking at that, looking at the difference between apartments, hooking up an apartment building versus, you know, with 100 units versus hooking up just one, whether we ought to really be looking at a finer tuned, more finely tuned fee schedule. >> My recommendation would be to do the first step first, and then if you want to start tuning it up more, think what we have to have is we have to have something to tune up first. If you see what I mean. >> Morrison: I definitely don't want to suggest anything that's going to make it take longer and i realize there's some basics, but I do think that we should think sort of broadly and figure out how we might do this, really bring our values into it in the end. >> Yeah. Just to -- just to tell you one thing that austin energy does which is an industry standard and it's the right thing to do, I believe, when we have a large residential subdivision, the contractor does all the conduit, all the infrastructure, our job is to inspect it and we come in and pull the wire in and put the transformers in place and energize and that's -- that's the role that we take. So it used to be the day when the utility had its backhoes out there doing all the digging, putting the conduit in the ground. When it comes to that subdivision, whether they are energy efficient or not, those types of goals, there's probably less of a control or incentive by the utility to get involved in that from that level than there used to be. And -- >> Morrison: But in the end, if there are more costly subdivisions to serve, they will put greater strains on need for new power or capital so there is some difference as to whether or not it's an efficient subdivision or not. >> Unless they are all going to have an electric car. >> Morrison: Right. >> So there's a lot of things to factor in. >> Cole: Councilmember. Councilmembertovo. >> Tovo: Can you tell us the current only involves buildings in require more than 300 feet of line extensions, is that correct? >> That's correct. >> Tovo: Another they think we might be considering is whether or not that policy is appropriate for whether -- and that doesn't -- in an ideal world, yeah, it would be great to have the line extension study done, but that's a policy we could consider now without benefit of having that fuller line extension study. I guess I'm concerned -- let me start by saying that i really agree the point mayor pro tem mentioned. I do believe growth should pay for itself and I think we should figure out policies and fees that will ensure that that happens. Austin energy needs the revenue and if we can find untapped ways of recovering revenue that I believe should be recovered now, you know, that is a better option than raising our existing customers' rates. I would rather have new customers pay their fair share of the costs of serving them. >> Well, I'm suggesting that -- that we go through that work when we have our budget before you and we'll look at the fees and that's the time when we can do. That the study won't be done before this budget cycle so we're really looking at something interim. But we could do something in between budgets, an amendment or anything on fees, I presume. >> Tovo: And if it saved 10 -- you know, if the -- if the utility could realize, i don't know, $10 million more, I mean is that way out of the ballpark? Do you have any sense of the magnitude of the costs that are currently not being recovered? >> I'm going to keep my numbers to myself right now. >> >> Tovo: I'm just thinking, would that be -- if we had a number, would that be a known and measurable change that could factor into the revenue requirement? >> Yes, it is, and you can forecast thebaid on accepted growth. Have you economic indicators that by economists who have given reports about the city's growth and everything and we have a way of turning that into new customers that we think are going to hook up or not hook up. >> Tovo: We could calculate the number of new customers, but we couldn't yet calculate how much -- how much they would otherwise be under -- how much the utility would be underrecoverring those charges until that study is done. >> That's correct. >> Tovo: And so right now it looks like based on the response that you returned in the february memo, right now you recover about 3 to $5 million annually. And -- and so I guess my question today is do you have any sense about what the difference in cost is of, say, providing service to one unit in an apartment complex in the central city versus the cost of providing service to a single-family residence in the central city versus the cost of providing service to a house outside the city limits where the houses are more dispersed? The common sense it's cheaper to serve the first than the third, but especially because we've had so many concerns from out of city residents, I'm interested in knowing the relative costs of serving them and whether certain customers are paying their fair share and there may be a cost recovery issue there. >> It's real variable and let me give examples of that. When we connecting a new customer to our downtown network grid, that is -- that is completely different category. It's complicated and involves work below the street, involves a lot of congestion, a lot of -- you know, a lot of things come about that. The second category is urban density with commercial buildings and predominantly that's all underground. And every new commercial customer that comes along or industrial -- pretty much commercial customer in downtown environment, every one of those requires an estimate to do the work that we need to do, and there could be a lot of impact. We may have to go underneath a road, we may have to do a lot of things. So there's the underground and overhead component to it. There's the network component to it. There is the size of the load and the sub station impacts to it. If we have a really large load that we cannot tap existing circuit, we have to do a lot of work all the way back to the substation. And if it's a really large customer we have to build a new substation. Then on the outside rural areas you have underground, overhead. So the cheapest way to serve is overhead. And if it's a real short drop and it's overhead, really that's the least cost. Then it becomes real variable after that. You can have a lot of residential underground subdivisions that as i explained the contractor builds most of the infrastructure and we pull it. All of these are real variable. And the large variability is labor. So if you have a customer where we have two crews out there working for two days, but all together that's a lot different labor cost than -- than others. So that's where all this variability comes into. >> Tovo: Okay, so it sounds like maybe there's not -- that it would be difficult for you to provide sort of a case study for each of those scenarios because they just have so many variables right now. >> You would have to look back at a year and say, okay, last year we hooked up this many of that type customer and that's the level of detail I'm hoping this study produces. >> Tovo: So one of the suggestions or one of the recommendations from our rate adviser did recommend revising the line extension policy. And I wondered, whitmire, if you could join us for a couple of minutes and talk about whether you felt that was a critical component to happen during the rates, during the rate process because of potential impact on revenue components. >> Yeah, line extension policy was really key at my recommendations because it has a direct impact on the -- on the fixed delivery charges. With the council goals of zero energy homes going forward, those would most likely manifest themselves in zero energy subdivisions. Without either extension, a line extension policy that recovers a substantial portion of the costs from those customers, they are truly zero net energy homes and we go good the volumetric. Those customers will respectively receive wires on for free t counter for that, of course, would be to have high enough line extension policies to recoup that investment, and then the fixed delivery charges wouldn't be as necessary. >> I see. So a revised line extension policy you think would obviate the need -- >> it would certainly reduce the need for the fix charges. >> Tovo: Okay. Thanks. Thank you for that. Anyone else? I'm done. Thank you very much. >> Cole: Next is decoupling. >> Technically we have connection and disconnection on there too, but if we want to postpone that given lazar, I think that's all right. >> Cole: It's my understanding you were concerned about the decoupling presentation. And I think we're running short on the time. >> Tovo: Take that up another time. >> Cole: Councilmember tovo, you are keeping track of what we're taking up next time. >> Tovo: With excruciating detail. With the same daily brought to the [inaudible]. >> Cole: Go right ahead. >> Good afternoon. Jim lazar, senior adviser with regulatory assistance project or rap. I'm here to talk about an issue that may be helpful to the council as you are working through austin energy's revenue requirement and right design issues. Rap is a nonprofit. We are primarily foundation funded. We exist to assist utility regulators. That includes you. Mostly we work with state utility regulators around the opportunityry and other countries. We do a little technical assistance and training work with power utilities. I'm an economist. I have worked on utility rate issues for about 34 years now. I've been an expert witness in about 100 proceedings and worked with rap in about ten countries around the world plus about half of the united states over the 11 years. I have kept one private client in burbank, california. I've given you a couple of publications, one on decoupling and the small white a guide to regulation the small book, blue cover. And one on pricing dos and don'ts which is a white cover eight and a half by 11. [One moment, please, for change in captioners] >> I beat around the bush as to why we exist. Separately the city i understand has retained paul trenek as a consumer advisor and I will try to stay out of the turf that he will handle very well. Paul was one of my mentors when I first started by consulting practice in 1992 and was a reviewer on one of my publications that I hope is going to be out very, very soon. I have the highest respect for him. There is a couple of -- clearly naturally issues before you -- narly issues before you. A proposal with a very large percent rate increase and that's obviously very difficult. There was a proposed large increase to the monthly fixed charge. And that reflects a number of concerns. The effect of that kind of rate design is that small users of all types, including people in apartments, seniors living alone and people with photovoltaic systems pay much higher bills than they do under the current rate design. Of that group at least apartments are unambiguously cheaper to serve an single-family homes. So to the state representative that there is cost justification, it may not be applicable to all the different types of housing that you serve within the system. And finally there's the proposed five-block rate design, which has the advantage from an economic perspective of pricing incremental use, incremental costs for very large use residential customers. It has the disadvantage of complexity and simplicity is one of the traditional regulatory goals for rate design. I put together this table comparing austin energy's rates to other large municipal utilities and i only looked at large munys that serve cities. And I primarily focused on the west, but I'm from the west. Olympia washington is my home. So there may be some geographic bias there. The six dollar current ae monthly customer charge is average or a little below average for the industry. The overall rates are average, a little below average for the group. 22-Dollar proposed customer charge is the highest I've seen for a municipal electric utility. That doesn't mean there aren't some out there. It's not a typical for electric cooperatives to have that high a charge. Where others, one or two customers per mile of distribution line. But very unusual for an urban utility. I also looked at how many blocks there were and what is the ratio of the lowest block and the highest block. These rate signs are all a little bit different and it wasn't easy to categorize them. But the current austin energy block rate is pretty typical and the proposed five-block rate would have the -- in addition to the highest customer charge, it would have the highest ratio of the end block to the first block of this group of utilities. So the original proposal was intriguing to me, but a pretty dramatic departure from what we usually see. Revenue stability is always an issue to utilities. Utilities, like oil refineries and hotels and office buildings and airlines, are dominated by having high fixed costs that they recover through the sale of a product for which the demand varies from time to time. That's how markets work. People make investments in order to produce a product and sell it. In a competitive world, oil refineries cost billions of dollars, but they recover that cost one gallon at a time. In the long run the cost of new power resources, including emissions, augmenting transmission and distribution systems, significantly exceeds the retail prices of austin energy. While in the long run virtually all costs are variable, in the short run they're not. And I'll show this graphically. If the cost are recovered in the per kilowatt hour charge, then weather, hot summers or mild summers, cold winters or mild winters, conservation, customer migration through self-generation, like photovoltaics, can produce revenues without a correspond be short run decrease in cost. Now, economic theory tells us that prices should reflect long run marginal costs to encourage long run efficiency. People make decisions of what kind of houses to build, how big a house to build, where to build it based on the prices they see. And if those prices reflect what the cost of society is incurring to serve expansion and growth and new needs and presumably something efficient can happen. I show this graphically. The bar on the left is an approximation of austin energy's current costs for owning generation plant, for fuel, emissions, transmission, distribution, customer service. And all of everything else that is in the rate. Only the fuel and the emissions component varies in the short run. On the other hand, in the long run the costs are significantly higher. Cost of new generating plant costs more than the older generating plants that have you. Emissions are generally looking forward, being valued at something resembling their real cost in terms of health and planetary impact. Those costs are much higher. So the little red circle on left is what's variable on the short run and the tall bar, set of bars on the right, is the economically efficient price. In the short run you don't create much money, so that creates the revenue stability concern. Here I've done it a different way. I took a utility that has 20% of its costs -- its non-fuel cost, that is what's not in the fuel cost. 20% Varies in the short run and 80% does not. In this situation a five percent reduction in sales produces a 40% reduction in net income. Conversely a five percent increase in sales produces a 40% increase in net income. Well, in that framework the utility has a pretty powerful incentive to try and sell more power, to discourage energy efficiently and renewables. And that -- that's just if they want to have a solid bottom line of net income, the current traditional system provides them a way to get there, which is to sell more power. If that's not the city's goal, the city's goal is one of sustainability and efficiency, then addressing the earnings volatility due to sales is something you need to look at. There's several ways to do that. High fixed charges are one. They discourage efficiency, they harm small users, but they work. They stabilize the utility's net income. There are less margin recovery mechanisms that are targeted primary at energy efficiency programs. For private utilities that reimburse them for their lost sales margin when the utilities implement energy efficiency programs. Quite a few of them around the country. They only address specific causes. You could target it to pv, you could target it to efficiency, leave out weather, leave out economic conditions. They're difficult to administer, but they're not I am possible administer. They tend to be fairly controversial. And the third that I'm going to spend the rest of my time talking about is we call decoupling or revenue regulation, where the regulator sets an allowed revenue level, number of dollars, and if the utility actually recovers some amounts greater or lesser those deviations are trued up typically in the following year. Decoupling can address energy efficiency issues because of the utility's encourages customers to implement energy efficiency measures with meants or education or information -- with incentives or education or information and sales decline, the utility will lose some distribution margin and a decoupling mechanism overcomes that problem for the utility by assuring them that they will get -- if they're allowed revenue independent of sales volumes. It removes a disincentive for the utilities to pursue conservation. It does not by itself create an incentive. Most regulators around the country, private utility regulators, state regulators, have conditioned implementation of decoupling on some increased commitments by the utility to implementation of energy efficiency programs. That's just -- that's sort of been the we'll make you whole if you do a good job. There's a lot of interest in solar in aunt area. We have a lot easier time getting fuel here for the solar systems than we do in olympia, washington where i call home. You can come up to the northwest rain festival every year from september to june. But it's still only about less than a half a percent of your residential consumers. The revenue impacts are very minor. That is, the amount of impact on other customers is not a big deal yet. It however is a measurable impact on the net income of the utility. A few million dollars is spread over a billion dollars of other customer sales is a pretty minor impact, but the net income of austin energy is a pretty small part of that billion. And a few million does matter there. Decoupling ensures that if sales decline due to additional solar installations that austin energy net income would not be affected. Now, if and when solar gets to -- I was going to say five percent of the system, and that's my judgment and a different number may be other people's judgment, it may be appropriate to revisit how pv customers contribute to distribution cost recovery across the system. That doesn't mean -- I just heard the discussion of line extension policy and I think implementing a cost recovery for line extensions is a good idea and the zero energy subdivisions will use -- we expect very little energy are a good example of the need to do that. So what is decoupling? It's a pretty small change in traditional utility regulation. Under traditional regulation, you set ultimately the price of electricity. And the net income varies with the sales. Sometimes it's higher, sometimes it's lower than forecast. Under decoupling you set the allowed revenues. And the price varies very slightly with the volumes. So the utility has then no incentive to increase sales, but it still has every incentive to control its expenses. Utility controls its expenses and it still recovers the same revenues and there's more net income to flow back in to reserves and financial stability of the utility. This is graphically on the left traditional regulation. The utility regulator sets the price, and that price remains stable over time, and the revenues go up and down. On the right the utility regulator is setting the revenue level and the price goes up and down a little bit. That's the essence of it. The states in green have an electric utility decoupling mechanism in place for one or more of the electric utilities they serve. Those in orange have a lost margin mechanism for energy efficiency programs in effect for one or more of the utilities they regulate. The only state that has i think universal decoupling for all of its major investor-owned electric utilities is california. So for all these other states it's in place for one or -- but not all of the utilities in the state. There are a couple of other states, main master plan and washington, have experimented with decoupling. They're currently not in effect in those states, although there's a decision pending in washington that could reinstitute decoupling for at least one or two utilities there. The typical adjustments for decoupling are much, much smaller than those for fuel. Here I've got the actual changes and prices for northwest natural gas, and for portland general electric in oregon under decoupling mechanisms. And on the second column for changes, how much the retail price of northwest natural gas changed because of changes in the purchase gas adjustment, the fuel cost, if you will? Increases of as much as 20% in a year, decreases of as much as 12 percent in a year. The next column is what's happened with the decoupling adjustments. None of them have been in excess of one percent. For portland general, the electric company, the power cost adjustment, which is a little different than your fuel cost because it includes all of the power costs and off-system sales, has had swings of as much as up 11 percent or down 19% in a year. The decoupling adjustments have been less than one percent. So the amount of instability in the rates is not very large. And this really goes back to the slide that I showed earlier here. That a very small change in the sales volumes can trigger a very large change in the earnings, but addressing recovery of those lost revenues doesn't typically involve very large changes in rates because the net income is such a small part of the total electric bill. So what does the reeling later do? The first thing do you in every rate proceeding, including the one that you're in now, is to determine the allowed revenue requirement. For decoupling, this needs to be done for several years in advance in some way. There are three alternatives that we've looked at. One is to set the defined amount of revenue for each year in advance. Adopt a three or five-year revenue requirement for austin energy for the non-power part of the electric bill. Another would be to set an allowed revenue per customer that would either remain stable over the three to five-year period or might change if there's cost trajectories that mean it should change. And then let the number of customers affect the allowed revenue. So you would allow $200 per customer in distribution margin, and if the number of customers grows, then it grows rapidly, then the allowed margin would grow rapidly. And if it grew slowly, it would grow slowly. And the third alternative is to make a new determination each year. It's actually what california does in essence is they have a generate case every three years, but in the intervening years they have what they call an attrition case where they look at what's changed in the last 12 months and they adopt a new revenue requirement. So there's a role for you and some changes about how you pursue that role. One question that's often asked is should all classes of customers be covered by decoupling. And the general rule is that all of the major classes that have lots of customers in them generally should be. But there are customers that have contract demands that obligate them to make payments whether they use power or not. They're in essence decoupled anyway, large industrial customers are often in that category. Your large industrial customers are under contract until 2015 and without having an opinion as to whether those contracts are reflecting today's costs, that's an example of an alternative to decoupling is you enter into a contract with a customer to recover a defined amount of costs. We often recommend that those customers with individual shares of the utility revenue over one percent are left out of the mechanism and handled another way because if a very large customer moves its production to mexico or china,, doubles its production, it can have a pretty significant impact on the system and ought to be addressed explicitly, not as part of a general mechanism. Some systems for decoupling separate residential customers and apply one decoupling mechanism or calculation to them and a different one to the commercial customers. That's common in areas where the residential load peaks in the winter and the residential load peaks in the summer and the weather affects are very different on the classes. Classes that have less than 10 members are off excluded. So there's some exclusion. I haven't studied your tariffs, but clearly your contract demand customers wouldn't come in to this mechanism until the expiration of the contracts. So now I'll go through decoupling for austin energy. This is what you would need to do and make decisions on if you opted to address the revenue stability issue through decoupling. First would be to adopt a policy. The second would be to determine the non-power revenue requirement. Let power costs flow through the fuel clause or a more expensive power cost mechanism that reimburses the utility on an actual cost basis in some way. And then a decoupling method for the non-power costs that would give the utility assurance that it would recover those expenses independent of sales volumes. Third it at the end of a year compare the nonrevenue from actual sales to the allowed non-power revenue that you would determine it should recover and figure out what the difference is. The fourth step would be to implement a surcharge or a credit to the following year to recover or rebate that difference. And the fifth step that I've put in here is a periodic outside audit and some kind of a schedule for future rate reviews so that a stay in touch with the mechanism and make sure it's doing what you want it to do and don't let it get away for 17 years without some oversight. We recommend a three to five- year period to bring rates back to a cost basis of every three to five years. So the first step, adopting the policy of decoupling. And I just drafted -- in blue there all I think that is necessary for a policy is that you would establish and annual non-power revenue requirement and the utility would be allowed to recover that independent of its sales. A couple of limitations here, these are quite common. If the indicated change in rates for any year is more than three percent,, the amount in excess of three percent would be deferred. Changes in rates that big under decoupling typically only happen when there's extreme weather. And extreme weather usually averages out over a period of a couple of years. As we've seen in a couple of states is that they've had a five percent decline in sales and a five percent surcharge as the distribution rate indicated, they impose three percent and the next year it's a mild year and the -- or it's an extreme year and there's a lot more sales and there's a big decrease indicated. So if it goes over three percent, it doesn't immediately flow through. Now, that doesn't mean the council might not sit down with the utility and stakeholders and your constituents and say we need to do something soon to maintain the financial integrity of the utility. But in general a three percent collar or cap -- collar meaning up or down, a cap meaning only on the increase side -- has been used in quite a few states. And then if the cumulative increase over any period of years exceeds two and a half percent a year. So if three percent followed by three percent would exceed that cap, but three percent followed by one percent would still be four in a two-year period, that would fall within the multi-year cap. Just to make sure that rates don't just keep ratcheting up without detailed council review. Obviously with detailed council review, you do what you need to do. Next is defining the non-power revenue requirement. The utility has been before you with all of the elements of cost. At a minimum that would include all of the distribution, customer service, administrative and general expense, the interest and depreciation associated with the non-power part of the system, but not necessarily including the interest in depreciation associated with generation of it trans miss. On owe transmission. You could I think initially with the information that you've been working with already do this for the first year and then quickly of a that, and in the early part of -- the later part of this year do that for subsequent year or years. So here I've done an arithmetic exercise where in the first year there's $800 million of allowed non-power revenues and forecast sales of 10 billion-kilowatt hours for a non-power rate of 8 cents a kilowatt hour. And over the five years the expected -- the allowed non-power cost grows, the expected sales grow and the estimated rate grows. This is a costs are increasing scenario. I don't mean this to be anything resembling a study that I've done of austin energy. This is a simple numerical example of the concept. But this is what you would expect to happen and you might well adopt these rates in advance for each of several years. To be the benchmark against which you would measure deviations. So then a third step, at the end of each year compare the actual to the allowed non-power revenue. So in the first year we forecast that the sales would be 10 billion- kilowatt hours, but they were actually 10.1. The actual non-power revenues were $808 million. There were $8 million higher than we allowed the utility. So the utility owes the customers an eight-million-dollar rebate the next year. We'll see that in step 4. If we skip over to the third year here, the forecast sales were 10-5-64. The actual 10-4, twist, the actual power revenues are 450 million and if I back up the allowed was 880. So there there's a 10-million-dollar deficiency. And in the subsequent year there would be a surcharge to recover that $10 million. So the rates can go up and down or the rates can go up or down. The utility is always receiving the amount of non- power revenue that you authorized. And in the last year here i did put in a significant decline in sales and a 32-million-dollar surcharge that would be imposed in the -- actually in sixth year. So step 4 is proposing a surcharge or a senior credit to recover the difference. So in 2014 we've got this eight-million-dollar excess that needs to be rebated and we divide that by the sales and it's a sur credit on the 08 cents, less than a 10th of a cent of kilowatt hour. About a one percent decrease in the rate. In the next year with the 10-million-dollar surcharge it goes the other way, but the rates go up a little bit. This is actually typical of the changes that you see, even with the built-in structured increases that i had in the very beginning of the allowed revenues and sales going up over time and the rates going up. The total rate increase that customers see is still a one percent affect of decoupling and basic through there was a two percent effect built in over times and the assumes. The rates don't change very much. And the last step that state regulators certainly do is they do an evaluation. And a periodic audit is the mechanism doing what we thought it was going to do. Is it doing what we want it to do? Because we might have learned that what we wanted isn't such a good thing. That audit should be someone accountable to you. I assume you have a city auditor who is accountable to you, but you can -- probably are going to want to use some kind of an outside firm that has got familiarity with power system accounting to help with that. And then as I said earlier, a full rate review, at least every five years. Now I'll turn to some of the common criticisms of decoupling because there are some and some are legitimate. Decoupling is not a perfect system. The existing traditional regulation is not a perfect system. And when you find the perfect system, then we'll hire you and send you out on the road and you can tell people all over the world what the perch system is. -- What the perfect system is. The first common criticism is it's just an annual rate increase dressed up in a halloween costume. If the forecast of the allowed non-power revenue is accurate on average, on average, then there will be equal increases and decreases due to decoupling. If sales are on a decline, then it will be an annual increase. If sales are on the increase, it could be an annual rate decrease. But if the forecast allowed revenue is accurate, and the forecast of sales is on average accurate, then there will be an equal number of increases and decreases. The next criticism is a decoupling shifts risks to customers. Right now when there's extreme weather the rates don't change. With decoupling when there is extreme weather the rates do change. The customers bear risks like weather, sales variations already. That's what reserves are for. That's why utilities hold reserves so that when a storm systems and damage is a distribution, they can pay overtime to get it put back together again when it's extremely cold or extremely mild they don't run out of money to pay for fuel and purchase power. And customers bear that risk through high charges for reserves. The rating agencies have recognized that decoupling stabilizes the utility net income and has generally the rating agencies have said that utilities need to have lower retained earnings to maintain the same bond rating if they have a revenue stabilization mechanism in place. So yes, it shifts one aspect of risks to the customers, but it removes the way that those risks are now being included in rates potentially from the customers by allowing lower retained earnings. Next, decoupling harms low income consumers. If the effect is annual rate increases, it adversely affect every customer. But so do annual rate cases. Obviously this rate review is has taken up a lot of your time. It's taken up a lot of the utility's time. And that's money to the people of austin. It's taken up a lot of interested parties' times and that's available to them. So rate cases are expensive. When private utilities go through the regulatory commission process, one of the elements after rate increase is how much were the rate case expenses and they tally them all up. And it's in the millions of dollars. They're not cheap. And high fixed charges, $22 a month, are even worse for low income consumers because the vast majority of low income consumers are below average users of power and are adversely affected by high fixed charges. So yeah, there is an impact on low income customers. I think on balance it's neutral to positive, but i certainly wouldn't ignore it. Decoupling increases costs. Well, if it means that full rate increases are less frequent is actually saves costs, but if you sit and forget for 17 years, this is going to require a little bit more oversight than once every 17 years for council. So it -- compared with traditional regulation and my own -- utility that serves me is in every 16 to 24 months for another full rate case, compared to that decoupling saves costs. Finally, people have said that decoupling diminishes the utility's incentive to control costs because they're guaranteed that they're going to get their revenue no matter what. Actually, what we've learned is it's quite the opposite. Because they can't increase the revenues by increasing sales. It removes any attention they might be giving to sales promotion. The only way they can actually increase their net income is to control costs. If their going to get the revenue anyway, if they can hold the expenses down, then they have more net income. So that's one common criticism, but I personally think it is entirely misplaced. I do want to spend a minute or two on your fuel adjustment mechanism. Currently your fuel adjustment mechanism treats power from utility-owned power plants differently from power that comes from power plants that are owned by independent power producers. And it does that because the interest and depreciation components of power plants you own is in base rates. But the interest in depreciation component for power plants that are owned by others flows through the fuel adjustment mechanism. And that's not uncommon. mechanisms were generally established in the 70's during '73 and '78 oil embargoes when fuel prices skyrocketed and became extremely volatile. And in the short run utilities weren't buying power plants or signing long-term contracts, they were just buying fuel. And the fuel mechanisms were put in place to deal with the volatility and price of fuel. But over time as the independent power market has grown, utilities have the option, many exercise that option to buy some or much or each all of their power from third- party non-utility providers signing long-term contracts. And if that flows through the fuel clause as i understand it does here, that tends to bias the utility's choice in favor of something that flows through automatically and against something that they have to come to the council to get recovery of. Even if it might not be the least expensive alternative a, and we've seen evidence of that in some of the states, so this is not a hypothetical concern. One utility was penalized very severely for gaming their fuel clause this way. So one suggestion for you to senior in consultation with the utility and stakeholders would be to convert it from just the fuel adjustment mechanism to a comprehensive power supply cost recovery. It really separates the delivery and administrative function from the power supply function. And in essence that's what the deregulated utilities areas of the state have. You pay a regulated price for the delivery function and you get a power marketer gives you a comprehensive power supply contract that has all the fixed and variable costs of power supply and the power supply price. Not suggesting pursuing deregulation, but to separate the costs into a power supply bucket that has all of the power supply costs in them. And recover these on an actual cost basis and a delivery and administrative function and recover those on a decoupled basic, of specific allowed revenue amounts per year. And if you were to make the -- make any change, or maybe if you don't, some sort of an annual public review of the costs and revenues and the power cost mechanisms, transparent accounting of what's in there and what's being recovered. I wanted to wrap up with a couple of sort of details. If you were to pursue a decoupling mechanism and there were to be small annual changes in the price customers pay, should that adjustment require council review and proposal? Most regulators require that it does, that it comes back to the regulator. It's hopefully just a matter of checking the arithmetic, but it also means that you would have before you the information and would be making a change to previously adopted rates. If the council can adopt a multi-year revenue requirement and what's beingry justed is the -- being adjusted is the fine- edged sanding around that, it may -- that may be possible to avoid the risk of multiple year of a year appeals to the public utility commission. But your legal staff and your utility staff are in a far better position to advise you on that than i am. Pragmatically I don't think this council has -- there's been no plan to adopt a multi-year set of new revenue requirements. So I would be astounded if you have the data in the short run to do three or five years all at once now. You could adopt an interim rate increase that would cover the first year and then spend part of a year figuring out a traject terry of the revenue requirement for the second, third, each fourth and fifth year. Pragmatically that's probably the most that could happen. Finally, is decoupling appropriate? It was created to remove the incentive to sell more power and to remove the disincentive to participate and implement energy efficiency and renewable energy programs. To make the investors indifferent to sales volumes. Municipal utility had pretty much the same concerns about its bottom line that a private utility does. You know, the utility's reserves still belong to the that's one fundamental difference. But they're not in the customer's pockets, they're in the utility's pockets. And from a customer's perspective, it sure looks like a power bill whether it comes from a public utility or private utility. And if you don't pay it, the power gets shut off, so it's really quite similar from a consumer's perspective. Why was the fuel adjustment created? It was created to stabilize the utility income in the face of cost changes that the utility didn't have control over. Decoupling does the same thing for revenue changes that the utility doesn't have much control over due to weather, whether or not to customer installation of solar and some revenue changes that you might want the utility to welcome energy efficiency in particular. So decoupling is a logical follow on to the tradition of utility regulation. I think the answer is is it appropriate? Yes. I'm happy to answer any questions you have. The plan as I understand it is for me to be back here for your workshop on the 19th and to be available for a discussion with other interested folks at that time. So that's my plan. If you and your staff decide you don't need to see me again, let me know before i get here. >> Cole: I don't think that will happen. I think you can count on the fact that that won't happen. I want to thank you for your presentation and then I'm going to open it up for questions. I may have to leave before all the questions are answered, but I did want to go ahead and tell you guys about the out of city ratepayers presentation that's going to be held on -- that is planned for april 14th in the city of lakeway at their city hall. The councilmembers from the city of lakeway, we will have a joint city council meeting. They will sit with us as we listen to testimony. And all of the -- either the city administrators or mayors of all the service areas have been notified that we will be there considering that topic and it will be a public hearing where is citizens can make comments. Councilmember tovo? >> Tovo: Thanks for that information. I just want to clarify a few things. So all of the out of city -- all of the out of city elected officials in management have been invited to attend? >> Cole: No. The only ones who will be in attendance is the host city, which is lakeway. And they will attend and post because they will be attending. The others have simply been notified that we are considering the issue. >> Tovo: Okay. Thanks. But I think you've answered the question I had, which is whether there will be citizen testimony. And it sounds like there will be from the out of city areas. Anybody from the out of city areas will be welcome to come and -- >> Cole: Yes. We'll have public service announcements, a sample one was given to either the city administrator or merit of every service area, city that we provide service to that we will be taking public testimony on that issue at that time, at that location. >> Tovo: Okay, great, thanks. >> Cole: Thanks. Councilmember morrison? >> Morrison: I do have a question. I think that's great that we'll be taking testimony and hearing from folks. I am wondering are we expecting to have a presentation from staff as well as discussion among councilmembers? >> Cole: I have asked austin energy, I think yesterday or today, to prepare a brief overview a lot like the one that we had when we first started this, not the in-depth that we've been having completely. Just an overview of the history of the austin energy and some of the issues that we're dealing with. And then we're going to focus on the issues that they want to hear. And we know some of those issues and we're going to be -- staff is going to be prepared to talk about them. Right, robert? >> Morrison: I guess i want to add that I know that when we've talked about out of city ratepayers, there have been some other issues that come up. For instance, other elements, other services that they received from the city and whether or not there are out of city rates for other services. And things like that. And so, for instance, there's no difference when you're going to barton springs pool. So if you're an out of city person or not, and so i guess for me it's important that we try to have a bit of a broad presentation from staff. And secondly, -- secondly nothing. Thank you. [ Laughter ] >> Cole: And I do think we want to provide that general information, but understand that we're going there primarily to listen and understand their perspective and what's on the horizon. And we're not going to take any action at that point, but just -- >> Morrison: Well, yeah. That's sort of what I was getting at. This has been I think a lot of what's fruitful from the work sessi is us being able to toss around ideas. This sounds like it's more a matter of listening and for the discussion with our colleagues that might not so much happen there, and it might just happen at a follow on work session. >> Cole: I think it's very important that we make the outreach gesture and show that we are concerned and that we want to. And to mostly listen. >> Morrison: Yeah. I get that and I think it's important. I appreciate you setting it up. >> Cole: We are scheduled 00, but we'll probably leave here about 30 because we're also going to have a community mixer, breakfast kind of, 30 and then scheduled to begin about 10:00: okay? >> Morrison: Do you think it takes an hour to get to lakeway? >> Cole: I don't know what time. I'm going to leave that to robert and kay. I'm not doing transportation, food, all that. Okay. I'm going to turn it over to councilmember spelman for the rest of the session unless there's -- >> Spelman: [ Inaudible ]. >> Cole: I will not leave until councilmember tovo comes back. Is there any other questions about the lakeway visit? Chris, do you want to start questioning? >> Riley: Sure. First I want to thank you for all your help with this and coming and visiting with us today. It's a fascinating subject that you're addressing and it offers some intriguing possibilities for our situation here. Just a couple of questions. First I want to ask you about the nature of the council's review of the annual adjustment. You addressed this in some detail on slide 30 about you noting that we probably will need to do some annual review of the adjustment so it wouldn't be considered an automatic rate adjustment. Other times on slide 18 you mentioned that we would have the option of making a new revenue determination each year. And 25 you mentioned that we could have a formal audit accountable to the council to review the revenue requirement. As we look ahead at those possibilities, knowing that we're going to need to scrutinize that adjustment, how will that be different from what we're going through now? Is that going to be like going through a rate case each year just for purposes of managing that adjustment? >> Hopefully not. The revenue per customer mechanisms where the regulator sets a -- the one that's proposed in washington would be works out to about $250 per year per residential customer and about $600 per year per commercial customer as the calculation of the revenue requirement. All there is for the regulator to do is to verify how many customers have been added to the system. Multiply that times the allowed revenue per customer to calculate the new allowed non-power for the whole -- allowed revenue for the whole system. And then to see how much revenue was actually received and calculating the difference. In that situation if a revenue per customer mechanism works, it's a very simple procedure. And the revenue per customer systems work for growing utilities. And austin energy is a growing utility. They don't work in pittsburgh where the number of customers is stable or declining because the utility's employee health benefit costs are still going up and if the number of customers is going down, it -- you don't wind up with enough money to run the utility. The idea would be that the initial mechanism would sit nearly all of the parameters. The only state that to my knowledge does almost all case every year is california. Hawaii has a simplified attrition mechanism that they do a calculation every year, but it's a simplified one. It's not as simple as revenue per customer. But the revenue per customer mechanism creates a way for the revenues to grow as the costs grow because when we do studies we find that the costs of the utility move more or less along the same trajectory as three measurements of usage. Number of customers, peak demand and total kilowatt hours. They're all going up at about the same rate. So the revenue per customer mets allows the revenues to grow at about the same rate the costs are growing for a growing utility. >> Riley: Okay. Would there be any particular scrutiny of the utility's costs during that review or would we still oversee costs in the normal course of things over the year? >> I think the overview of costs would be in the budget process. >> Riley: So just as it typically is now. >> Yeah. For the private utilities, the whole theory is that if they hold their costs down they make more money. In the case of the municipal utility you have a budget process that you go through and I would expect that would continue. >> Riley: So there's nothing about this mechanism that would undermine our ability to manage the utility's costs? >> No. >> Riley: Okay. I wanted to look back at the slide 16 showing the geographic distribution of decoupling approaches. The map of the united states. When I look at that map we note that -- as far as we know decoupling hasn't really been done in texas. In fact, if we're looking at the states that have decoupling in place for all the utilities, it really seems, other than california, it seems to be a line along a particular latitude. And which leads me to wonder if there's something about either the generation mix or other utility characteristics that would make -- the kind of decoupling you're talking about more suitable for utilities in some states than for utilities in other states. >> With the exception of michigan, each of those states that are in green are states that are national leaders in energy efficiency. That's actually what I think is in common is they were -- the regulators wanted the utilities to do a good job in their energy efficiency programs. The utilities say if we do a good job on the energy efficiency programs, our revenues will suffer and our profits will suffer and decoupling was presented as a treatment for that particular mall distribution margin. And -- malady. And arizona is several at a lower latitude and it is a leader in energy efficiency, but just very recently. And other than that the other southern states, there's no eagle awards been given by the american council for energy efficiency economy in the southern tier states. There's improvement. We're working a project with the arkansas commission right now, a deep dive on energy efficiency that we're quite optimistic will put a star -- a high achiever among the southern states, but there isn't one yet. To give perspective, texas' energy efficiency directive to the private utilities, about four-tenths of a percent of sales per year compared to minnesota's target of one and a half percent of sales per year. Massachusetts 2.4. >> Riley: But as you know, given that this form of decoupling has not been pursued in texas as far as we know, that does require us to exercise some diligence that we're not running afoul of any rules that are currently in place governing texas utilities and there are a lot of rules governing texas relate and you touched on a few of them. One that I wanted to ask you about was piecemeal rate-making. In texas the public utility regulatory act generally prohibits limited issue rate-making because it contemplates a more comprehensive review of all the utilities' revenues. Has that concern being raised in other states and are you -- are you familiar with that? >> Yes, it has. In fact, in the white book that I've given you, at the back of it there's a section on criticisms of decoupling. And one is that it violates the matching principle. The purchasing principle is basically that -- the matching principle is basically that sales and customers and revenues and costs generally rise together and decoupling quite intentionally decouples the revenue from that growth. So I'd refer you to that section. And as you know, we recognize it as a legitimate concern. And -- but from the way that most states have done it, and that you might do it is you're actually adopting a very clear revenue requirement for each of the years. And there's nothing piecemeal about that. It is designed to recover all of the utilities revenue requirements, no more, no less. And if you can do that for several years in advance, i know the utility has a multi-year financial forecast. I don't know how much scrutiny it's received at the council level. But every utility has one. The rating agencies require it. You may be able to set a revenue requirement and not have there be nothing piecemeal about it. The only adjustment would be that the allowed revenues would be trued up just like fuel adjustment mechanism trues up the fuel collection. >> Riley: Only. I expect we'll need to give this more attention. >> As I understand those in texas law are better to explain that than an economist. >> Riley: I appreciate you helping us as the issues come up. I look forward to working with you on this. >> Morrison: Thanks. Thank you for coming. It's really been helpful and I look forward to having us explore this more. One question, you mentioned that there are some concerns that this unfairly impacts low income folks and you made a comment about that. I assume since this is really more about rate design than cost allocation, that it doesn't have unequal impacts to different customer classes. Would you say that that's correct? >> Well, I mentioned that some states have established, you know, sort of two pools for decoupling. One for residential and one no nonresidential customers -- nonresidential customers because the seasonal variation in usage and I don't know what it is for your system at all. And -- but basically with respect to the low income customers, if decoupling facilitates a rate design that's favorable to low income customers, which i think it does compared to what austin energy orally proposed, then it should be a net benefit. If it also results in austin energy needing lower reserves and therefore a lower overall revenue requirement, it would be a benefit. >> Sorry to interrupt. We've lost our quorum. >> Spelman: I noticed. I was hoping you wouldn't pay attention to that. >> It's councilmember tovo's fault. She's always on the ball. >> Spelman: What would be appropriate for us? To suspend all discussion. >> Everybody can stretch a second. Probably a good time anyway. A little pe. >> Spelman: Yoga. Anybody want to lead us in yoga? Never mind. >> Spelman: Frivolity. Thank you for returning. >> Morrison: It's not so much -- you've talked about low income folks and i appreciate that. I guess I'm concerned about sometimes we think up great ideas and in fact there's some implicit shift of cost to residential over commercial or something like that. Is there anything like that that we need to be aware of? >> I don't think that's a concern. The low income advocates who participate in state utility commission rate cases generally oppose decoupling. And their principal objection is that it makes it more years between rate cases. And when there are rate cases, they have a venue for coming before the regulator and asking for improvements to the programs that benefit low income customers. And that's a legitimate, pragmatic political concern on their part. And having worked in the early years of my career for a low income advocacy group for a year and as a consultant to a few of them over the 80's and early 90's, that is when you get to make a deal. Advocates have access to the austin city council on a continuous basis. You're different from a utility regulatory commission that only gives people a venue when there's a rate case. So that's a fund men difference in austin at least with regard to that. But if your low income advocates have a concern, you should listen to it carefully. And if I can be of any help in helping you shape a mechanism that addresses that concern, I'm available to do that. >> Morrison: And what you've suggested, just in the scenario that you laid out in your briefing, it has us talking about it every year basically. So that wouldn't be an issue. And are there ever struggles between the advocates for commercial versus residential independent of income level? >> In the private utility regulatory world the commercial class is almost always absent. Industrial customers are actively involved. >> Morrison: Okay. I meant industrial also. >> People who write checks with two commas in them for their power bills show up. [ Laughter ] people in classes when you can't up the number of people involved you need two commas to count up the people are involved. And the commercial sector just doesn't show up in most cases. In a few places they're organized, a couple of grocery companies, kroger participates, but the commercial (indiscernible). Industrial customers are involved. In the book we talk about some of their concerns. Obviously they can speak better to their concerns than I can, but the principal concern that is a legitimate one is industrial customers actually want the utility's bottom line to be tied to its sales. That is, they want the utility to have a vested financial interest in their customers producing more of what they produce and consuming more of the electric utilities' product. And decoupling takes that incentive to raise the utility's profits by increasing sales away from the utility. I've heard industrial customers say we want the utility to have a vested interest in our success as an industry. That's legitimate perspective. I don't think that when the context that decoupling was created was to find a way to make utilities indifferent to variations under sales volumes due to weather and energy efficiency programs. It's a big deal. We're talking about one and two and three percent variations here, which can have a pretty substantial income on the utility's net income, but don't actually get to the point of affecting economic development policy. >> Morrison: Thank you. >> Tovo: Well, thank you very much. I look forward to hearing from you again. I probably will have some questions at that point. I know that we have a memo from our outside legal counsel, but I guess it's all protected and something we should discuss in executive session, is that right? Okay. So perhaps we can figure out a time when we haven't already scheduled executive bercado could come and talk to us about the memo and we can continue to kind of wrestle with those ideas before mr. lazar comes back. That's all. >> Spelman: Okay. When would be an appropriate time for us to have conversation? It seems like having that conversation fresh on the heels of having this conversation would be a very good idea. >> [ Inaudible ]. >> Tovo: Would that be next week? >> Spelman: We could do it at the next council meeting or the next work session as well. Come on up, sir, please. We promise not to make you say anything you don't want to say. >> [ Inaudible ]. It will need to be before THE 11th. >> Spelman: Before the 11th? >> Yes. I have a personal conflict that week. >> Spelman: Okay. >> Morrison: Is the 10th a work session? >> NO, IT'S ON THE 11th. >> Morrison: Council work session for a regular meeting, yeah. Is that a tuesday? And we do have a council meeting on the 12th, right? So we do have a work session ON THE 10th. >> Spelman: How much time do you suspect -- do you believe you're going to need to explain your memo to us? >> I can set it out in a matter of a few minutes, i suspect it will take a bit longer based upon my past experience. [ Laughter ] an hour maybe? Does an hour seem unreasonable? 45 Minutes? >> Spelman: Okay. I haven't got the agenda for work session, city council meetings in front of me right now. Would you be available on THE 10th? >> I am. Any time that day. >> Spelman: All right. We have a work session for this subject scheduled on tentth or is it just a generalized work session? >> [Inaudible - no mic]. >> Spelman: Sounds like we need to do this on the regular work session then. The only alternative would be thursday's council meeting. >> That's not before -- i think that presents a scheduling problem. I think we need to do it after -- >> I was talking about thursday two days from now. We're not posted for anything related. We should be germaane to this subject. >> I'm available. >> Spelman: If you're available on the 10th we'll schedule it on the 10th then. >> That's fine. >> Spelman: Never mind. >> Dispute the council rules for not a executive session on the work session -- >> we're asking it. >> We'll do it. >> Spelman: It's not really a code. They're only guidelines. Okay. Thank you, mr. lazar. Very much appreciate you coming. We look forward to talking with you soon. What else is on the agenda? >> Morrison: I guess i hate to say this, but do we need to look at the topic for our next meeting? Because we didn't have the opportunity to do the preliminary discussion, possible action. So I guess I would like to consider moving that down to -- I don't know what version of the schedule i have right now. Okay. Moving the potential preliminary council action of issues from sessions 1 through 4, I would like to put that on a session on our agenda for session 5. Since we weren't able to do that. And I hope that we could all take a minute to remember where we were at the end of each of the last sessions so that we could take potentially give some consensus positions on some of those items. >> Spelman: Remind us, councilmember morrison, what is listed there as being the curriculum for session 5 #. >> Morrison: It says other related issues. That's a good one. Review austin energy 2011 audited finances. And then third, all system sales in a nodal market. So that's the meaty topic. To consider. And we do have it considered from 2:00 to 5:00. So we have three hours. So hopefully that would fit in. >> Spelman: weist, did you expect to have a long conversation on all system sales or is that relatively short? >> We can make it short, but we arecado's comment that it could get complicated. >> Spelman: It's scalable? >> Yes, sir. >> Spelman: Let's hope we could scale it down a little bit. We probably need an hour, maybe an hour and a half to discuss where we've been and maybe draw conclusions about where we are right now? >> Tovo: If I may jump in here. So several of our very committed and bright audience members pointed out that we haven't had the benefit yet of the consumer advocate and that it might be useful to check in with him before we make some preliminary decisions. So that raises for me -- having argued asaid justly for blasting on or for preliminary actions I'm going to suggest that we agree that we should have the benefit of talking with our consumer advocate prior to making some of the preliminary decisions. So I just throw that out. That raises for me a question of when we might expect his involvement. bercado, maybe you have an update on that. >> As you know I've been working for the city manager's office and kind of being the liaison with mr. churnek. I spoke with him a couple of times yesterday. Basically where he stands is he's got all the documents, he's been poring through them, he's brought on some additional assistants from a couple of experts who specialize in areas that he does not. He sent some discovery to ae today that's going to be a phone conversation with ae tomorrow morning. So he's beginning to get up to speed. I expect that you will be seeing a letter from him in the next few days, kind of an introduction letter letting you all know who he is and that he's engaged and some of the specific areas that he's looking at pursuant to your resolution. And then I think he intends to begin to weigh in on some of these issues through memos, but I think he would be happy to do it through phone communications as well. And I've impressed upon him the fact that you all are going to begin to make decisions on some of these issues, specifically on the work -- at the work session ON THE 11th. And so hopefully he will be able to get something out before then. I alerted him to that if he had positions on some of these issues he needs to do that. That's where it stands. >> Tovo: I think we can certainly keep it on the agenda and continue to revisit it in subsequent meetings if need be. >> Morrison: We don't have to take action by any means until we -- >> Tovo: We can start to gel around what our independent positions are. That's great. >> Just to let you know, there are four work sessions, I believe six, seven, nine and 10 that are fairly close together between the 17th and the 24th. And they do address some of the issues that we know are important to consumers. And so our hope is to try to get him here for an extended period and I need to talk goode about his thoughts on that. But the thinking is that he will be here for some or all of those work sessions. >> Spelman: Is it likely churnek would be available for a phone conversation on the 11th if we needed to have one? >> I think he's available, assuming his schedule doesn't have conflicts, at any time to visit with you all on any of the matters that y'all are interested in. So yes. >> Spelman: Okay. That's good. Anything else we need to know about that? >> Morrison: So I guess I'm making a motion that we add that to our agenda for next time. >> Spelman: Okay. So holding over that -- [overlapping speakers]. >> Morrison: The preliminary action for sessions one through four is what it would be if I can get enough votes for that. [ Laughter ] >> Tovo: I second that. And just say the unfinished business I assume would mean the connection/disconnection piece as well. >> Morrison: Yes, text and disconnection fees. We didn't get a chance to talk about those. >> Spelman: Moved and seconded, all in favor? Okay. Passes by a vote of four to zero. Which is good because if it was a three-one vote that wouldn't count. [ Laughter ] we also have the question of where we're going to be meeting. We've met both in chambers morgan i think you were suggesting that we ought to make a standing decision as to where we ought to be meeting? >> The other ones are listed for council chambers, but there's been a housekeeping matter that came up asking if you could do it in here. So if that's the consensus, then we'll just change the schedule to say that they're in the boards and commissions. >> Spelman: Anybody have any strong feelings on this? >> Tovo: The only concern, the reason we had scheduled them across the hall is sometimes we've had a fairly large number of people in attendance. And today we were full, but I think last week we had, i don't know, 40, 50 people. I was trying to do a little hand count. I don't know whether that's -- if we'd be able to accommodate that number over here. >> Spelman: This is probably a tremendous breach of decorum, but let me just ask for hands from y'all. How many of you would refer approximate to meet here as opposed to the chambers? How many of you would prefer to meet in council chambers? That seems to be good enough for me. I think our audience would be more comfortable in chambers, if that's not much more inconvenient. >> Can we do all of the decisions like this? [ Laughter ] >> Spelman: A motion on water treatment plant 4 is not in order right now, but that did occur to me. All right. Any other business to come before us? There being none, we are adjourned. Thank you.