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i will like too call to order the austin city council work session on austin energy rates.
The first item we have up for discussion is the 2011 audited finances.
We'll have a presentation from austin energy staff.
>> Good morning.
We're going to load the slides, then I'm going to turn this over to anne little.
>> Good morning I'm anne little haven't of finance and corporate -- vice-president of finance and corporate services.
The agenda today is -- starts the remaining decision points from work session 1 through 4.
I think where we left off was on the general fund transfer.
Would you all like to start with that?
I do have one slide on that.
We can just move through each of these.
We have the gorped transfer, the energy efficiency and solar goals, fund, the customer assistant program and then the request was to compare 2009 test year to the 2011 fiscal year.
Then we have a discussion on all systems sales adjustments and then if we have time, we -- I think last time it was decided that we would continue on into rate design.
On the -- before we move on, I do have a slide on general fund transfer.
The energy efficiency question I think was should the energy efficiency costs be relative to the dsm goal, if so, what would the funding mechanisms be.
On customer assistance programs, I believe the question was we need to spend some time on the program design, but I think the first decision would be whether we assist 20,000 customers, 40,000 customers, or gradually build up to that goal.
I think maybe energy efficiency and the c.a.p.
Questions may need to be deferred until the rate design, since the funding mechanism is a piece of that, but we can come back to that after the gft discussion.
The current general fund 1% of the average of three years of -- of revenue that's both fuel and non-fuel.
It has been proposed that we increase the general fund transfer to 12%, remove the fuel revenue, continue using the three year average, and put a floor of $105 million in order to protect the general fund and when the g at 12% reaches more than $105 million, then we would start using the 12% and i believe that occurs in approximately 2016.
What this does is really reflects the true revenue growth, it improvements predictability, makes the forecasting more even, addressing the electric utility commission issue on fuel in the general fund transfer.
And then by establishing this floor of 1,015,000,000, it protects the general fund.
It's a little bit simpler calculation.
>> Morrison: I don't know that my light it working.
Okay, it's on.
I have a couple of questions.
One, one of the questions that I raised when we first started talking about this approach was can we assess whether doing it this way and shifting it off of the fuel revenue would actually burden one class of customers more than another.
And I wonder if you all could repeat the answer that you provided in a memo and i think that you had some suggestions about -- because there might be a shift, how to equalize that out.
>> Because it would be allocated differently, it would be allocated on base revenue and not fuel, then it would allocate more to the residential class, if you go with the pure allocation.
Now, if you -- if you want to put something in the financial policy that says in the cost of service it would be allocated based on both fuel and base and that is something that is doable and would remain the same allocation that we have today.
>> I think that would be an unintended consequence to shift more to the residential.
I guess that I would like like tomake a motion that we take that as an approach to allocated based on fuel and base so that we don't get that shift.
>> Cole: Councilmember morrison had made a motion that we allocate it based on fuel and rates so we don't have the unintended
consequences of burdening our residential ratepayers more.
Is that a correct assessment of what staff has pointed out?
>> You have the right to do that if you would like to keep the allocation the way it is today.
Is the a second, discussion?
>> Councilmember are we discussing item 1 or 2 or 3?
Because I believe items 1 and 2 are only posted for discussion.
>> Cole: Oh,.
>> If we're on 3, that's okay.
>> Morrison: This is the prior work session.
>> Cole: Okay, there's a motion on the table.
Is there a second for further discussion?
Seconded by councilmember tovo.
>> Spelman: How big is the difference between -- [indiscernible] what we mean is that the residential rates would have to -- am i on or not?
I can't tell.
>> Morrison: None of our lights are working on here.
>> Spelman: That's working, right?
By burden, what we mean is that rates are going to have to come up for some classes and not for other classes if we choose to fund the general fund transfer off of rates and not off of rates plus fuel, am I accurate?
>> That's right.
Keep in mind that large -- the more energy that you use, the more kilowatt hours that you use, the more fuel charge that you have.
So that's where the shift comes from because those customers that are large customers are using significant amount of fuel.
>> Spelman: Right.
>> If you take the fuel out, what we would do is try to equalize that using what's been proposed exactly.
>> Spelman: So how much is that difference?
How much more would the average residential customer pay or what is the difference in the increase to residential customers before and after if we do it this way?
>> I don't think it's really that material in the overall
I think it's about $2 million that would be shifted more to that class, but I'm not positive about the amount.
>> Spelman: Okay.
I feel uncomfortable making a decision until I know how big that shift is going to be, if it's a million or two, that's one thing, if it's 10 million, that's a different thing.
And remind us, if you could, what's the value --
>> councilmember, just to be clear, under this proposal, there would be -- the allocation would basically stay the same that it is today.
So -- so adopting the staff recommendation without the adjustment would be a two million shift, perhaps in cost location towards residential customers, but the motion basically restores the allocation as it is today.
>> Spelman: Well, at some point we're going to have to true this up?
In 2016 or at what point?
>> That's a good point.
I think when the contracts go off in -- in 2016, then -- then I mean that's a possibility.
>> So -- so the effect of -- 1 to 12 non-fuel is nil on the rates you are proposing for now.
But at some point in the future, maybe when we go up for another rate -- when we have another rate case or when the contracts expire in 2016, then there would be an increase for residential customers, relatively speaking of about $2 million.
>> Unless we revisit it.
But that's certainly one path we could use to get there.
>> Spelman: Remind us again, the value of taking fuel out of the general fund transfer is what?
>> The volatility, if natural gas got to be $6 and the markets went that way then there would be a huge amount of revenue that would then go to the city and that's part of the instability that we've had, could have.
>> Spelman: Right.
>> So the electric utility commission has been advocating this for this -- this for a long time, ever since 2005 I think, you know, when gas had a big year or --
>> So the value of volatility from our point of view is partly that the three are shifting around a little bit.
So we would be taking more money, but partly because that's fuel is a pass-through in fuel factor, you are taking a loss of 1% on all of the fuel that we sell.
The more fuel that we have to use, the larger the loss we have to find of making it somewhere else.
>> That's right, the better we can forecast any of our large expenditures like that, the better we can forecast that, the better we will operate the utility.
>> What is the size, you are using two million, other than a percent.
So I just want to be able to get an apples to apples comparison.
What is the dollar increase in residential rates that we're talking about, elsewhere in this proposal?
>> It would be pretty minimal, I think.
You're talking about two million out of about 400 million.
>> Spelman: 400 Million total.
>> About 400 million i believe in residential.
>> Spelman: 400 Million is the total revenue that we're getting now from residential customers?
>> That would increase under all of the proposals that we've been talking about, the -- this would increase it about another 2 million more at some future date but not in this particular rate case.
>> Cole: I think councilmember morrison has a question.
I thought that the savings to the residential customers were more than that.
But before councilmember morrison speaks, I wanted to
be clear are we talking about a savings after the rate adjustment or in 2015 or 2016?
I heard a couple of different dates, I heard about a trueup time.
I wanted to be clear about the time period that we would see that savings to residential customers with the current motion:
>> Well, it would begin whenever we enacted the new general fund transfer formula.
It would begin then.
So it would accumulate over a period of time.
>> Cole: That makes sense, councilmember morrison?
>> Morrison: Just as a follow-up to what bill said and was asking, we're talking about 400 -- about 400 million, that is the allocation to residential.
But another way to look at it is we're talking of the 100 million for the revenue requirement that we're addressing, how much of that is allocated to residential?
Because I think that that's more -- that's the -- that's another way to look at it, that it's 2 million out of something much less than 400 that we're looking at.
>> I don't think it relates to the increase as much as it does the allocation to the class.
Because when you allocate the general fund transfer, it's in the cost of service and you would -- whatever that change would be, you would allocate is over all of the dollars.
Not over just the increase.
So I'm not sure what percent of the increase it would be.
>> Morrison: What -- so of the 100 million in the revenue requirement that we're looking at, the new revenue requirement, how much of that is allocated to residential at this point?
>> About $95 million of the
>> And does that mean about 95 of the 100 when we take out the --
It would be --
So -- so for me, it's a matter of looking at -- at that also as 2%, that 2 million.
Although I thought it was 4 million or we had at some point gotten 4 million.
I think kathy has got --
>> councilmember tovo.
>> Exactly how much money are you saving us.
>> Right, 4 million was the in be that stuck in my mind.
I wonder if we're mixing it up with something else.
[indiscernible] here, I know he did some -- talked with us about this issue.
I would also like to talk with mr. churnic about that.
picato, if you could --
>> please keep in mind we have a motion and a second on the floor.
>> We did do some back of the envelope analysis looking at the issue.
The 4 million-dollar figure that you are referring to did come as a result of that review, but -- but we certainly would defer to aes to, you know, whether that number was accurate as i mentioned.
It was sort of an outsiders back of the envelope type of analysis.
So if you are saying the number is actually 2 million, we don't have any reason to question that.
>> We have someone looking that up right now, so maybe later we can give you that answer.
>> I think that it's clear, there is some money there to be reallocated so that's a good thing.
Then I guess I wanted to just thank you, and thanks for doing the initial follow-up on that question that councilmember morrison raised.
churnic, I wonder if you have done some thinking about this issue and if -- if the motion that's on the table resolves -- resolves the burden on -- on the
overburden that would be placed on residential customers if we adopted this new transfer policy.
>> Well, overburden is -- is.
>> but I -- I think the -- as I understand it, the motion would -- would keep the allocation method the same as it is now.
And it would just change the tracking of the 105 million would be 105 for some period of time.
Until -- until base revenues rose above the level that would -- until 12% of base revenues rose above 105 million, but then the allocation would stay the same.
Councilme spelman said something about a need to true up, if you went in the direction of the motion and I don't see any need to do that.
You could continue the -- the calculation of the -- of the general fund transfer on base revenues or plant and service or a whole thing of things and -- a whole range of things and then calculate it based on total revenues and you could continue that process indefinitely.
There's no particular need to true up.
Obviously, in each rate case you would redo the calculation.
>> Spelman: It would require redo the rates, though, would it not?
Wouldn't that require that we do the rates over again?
We don't set rates, figure out what the profit is and then go back and change the rates in order to incorporate the profit.
We set the rates so that it
1 or 12% general fund transfer in them.
>> That's correct.
>> Spelman: So we would need to know in advance how the rates would have to respond to this proposal to base our general fund transfer only on rates not on the rates plus fuel, would we not?
>> It's really a policy question, I think.
I mean, you could incorporate the treatment of the allocation into the financial policy or we could -- this could be a one-time treatment and then the next rate case, it would be allocated based on revenue rather than based on the non-fuel revenue rather than the fuel and the non-fuel revenue.
>> Spelman: Sure.
>> But that would be a decision you could make in each rate case.
In between rate cases you have the problem which is no different, as I understand, from the problem over the last 17 or 18 years now, of having rates that are not changing but general fund transfer does, but then so do a lot of other costs.
And when the -- when the general fund transfer and all of the over changing costs require the company to -- to file for -- require the utility to file for a new rate case, they would have to do that.
But the -- but the general fund transfer and the way it's computed would be a -- would be a small part i think of the -- of the total driver for a rate case.
>> Spelman: I agree it would be a small piece.
>> I want to point out something else I guess you have to think about long term.
It is possible that we would have more energy sales in residential than you would, so it is possible that if you keep an allocation formula based on that, you might have it going the other way.
You follow me?
>> Spelman: No.
Try it again, sorry.
>> Well, you could have -- based right now on fuel, industrial customers and all of that, you have that fuel mix, who is using the fuel and so that could shift over so I think that we have to visit this policy, you know, every so often, I don't know what the time element is.
>> Spelman: Whenever we do a rate case, every 18 years or so [laughter]
>> to tune it up to whatever the current state, profile of the utility looks like, which I think would be a prudent.
>> Cole: We have a motion, discussion.
All of those in favor say aye.
>> Spelman: I say no.
You didn't ask for the nos.
>> Cole: All of those in favor say aye.
We have councilmember riley, kathy tovo, sheryl cole, laura morrison voting in favor, councilmember bill spelman voting no.
>> One other thought about gft that I just wanted to throw out there.
The general fund relies on the contribution from austin energy and we have seen and we are trying to correct the problems that it's causing for austin energy with this by putting at least 105 million and then up to 12%.
I'm wondering, we're estimating that we won't reach that 12% exceeding 105 million until 2016.
On the other hand, the general fund and the growth we're probably going to be seeing a lot of that over the next four years.
And I wonder if it would make sense each year to consider a small increase in the 105 million.
Because we would otherwise be seeing a small -- some increase, we're certainly going to be seeing an increase in our -- in our overall budget and other general fund budget.
And it just seems that keeping it flat at 105 million certainly is an option.
But it also might make sense to raise it by 2% a year or something.
Because that would be the normal course of things.
I don't know if this is making any sense to anybody.
But it's just something that occurred to me that we might want to look at.
>> Councilmember tovo.
>> Tovo: Just to clarify, 105 would be set at the floor.
But it --
>> Morrison: This year.
>> Tovo: This year.
But it would be kind of an escalating floor based on kind of general cost of inflation in addition to that 12%.
>> Morrison: Or something like that.
Because looking at it from the general fund side, certainly sometimes we've been able to reap the benefit of hot summers and all of that, we want to take that out.
Because that's causing so much trouble and volatility for austin energy, but the normal course of things is going to be that things are slowly increasing and growing.
As is our budget for the general fund.
>> Spelman: The whole reason for the floor, though, was to accommodate 1% on rates plus fuel to 12% on rates only.
And it seems to me if we're going to be basing our gft on rates plus fuel, in the usual way, we don't need a floor at all.
We can just eliminate the floor entirely and just continue doing what we're doing.
>> Morrison: Well I'm not suggesting that we consider fuel in this at all.
I'm just saying that 105 is sort of what our expectation is this year.
And with growth and base rates and all, we would
expect additional, you know, excluding the whole consideration of fuel, we would expect some additional return to the -- to the owners of austin energy, a growth in the return.
>> Cole: Let me ask a question of staff.
What impact would such a ?
1 to the 12%?
>> Cole: What we are brainstorming here --
>> let me give you my opinion on that.
I think anything that you come up with, what you are talking about is a different way to transition is what i understand.
I think that anything you come up with in that transition period we're only talking about until now 2016.
At 2016 or maybe sooner, depending on the growth of the utility, we'll cross that 105 line and then you'll be on about a 2% or whatever our system growth would be, which is probably consistent with what the general growth is.
>> Morrison: I guess I'm questioning why shouldn't we be on a 2% increase per year in any case.
I'm just brainstorming.
I think when I -- what i hear councilmember morrison talking about is a couple of points on the general fund side.
I'm hearing the concern.
We just talked about it last week that there are certain cost drivers on the general fund side that we don't have any control over.
It makes our general fund expense siding up by some factor on an annualized basis.
Part of what I hear being expressed in the way of concern is 105 in terms of the general fund transfer is the floor, how do we contact for that increasing -- how do we account for the increasing cost in the general fund side in the absence of any kind of annual adjustment in the transfer revenue.
I think is what I hear you saying.
>> Cole: You didn't give
us an answer.
>> Morrison: So what do you think of that [laughter]
>> as the city manager, obviously I'm split because while I have overall responsibility for, you know, the budget of this municipal corporation, so while I'm always concerned about the fact that on the general fund side we're always fiscally constrained, at the same time I'm also mindful of the financial short and long-term viability of the utility and all of the other attendant issues associated with what we do or don't do in terms of the gft methodology.
>> Morrison: That was a non-answer, thank you [laughter]
>> Cole: I have a couple of concerns with that suggestion.
I guess first and foremost is we just have not properly vetted it through all of the channels.
Having a floor gives us -- we're not talking about raising rates at 2% after this.
So we're just looking at the general fund revenue requirement and it's really -- really hard to do this with their piecemeal approach, what if we tweak this, what if we tweak that.
I would like us just to stay at the 105 for now.
Also, because I think we already have that authority to change our policy requirement any time that we elect to do so, and so we could look -- look a couple of quarters from now, say that's going to be too much of a strain and consider all of the details in audit and finance and then bring that through council and make that change.
But in this context, now, i think it would be a leap and also given that we know we're going to have pressures from people outside of the city limits, wanting us to make concrete changes to the general fund transfer and cap it and give them certainty.
I would be hesitant to do that now.
>> Morrison: My only comment and response is to
your statement that we're for the going to be looking at raising our base rates and it would be a strain.
But we would -- we can expect growth in the number of customers, which will increase our revenue from base rate.
>> Cole: That's the exact type of question that we would need to nail because i don't know if that growth in customers would justify an automatic 2% increase in the amount of the general fund transfer.
>> Morrison: So that's a good point and the question is do we have -- what estimates are we using for increasing customer growth.
>> Well, one idea you might contemplate is one that has a minimum of the increase of 2%, if that's your number.
Or real growth, whichever is higher.
So if you have a here where it's 1% that goes up by another percent.
If you have a year where it's 3%, then the question is does it go up 2% or does it go up 3%.
So there's a lot of different ways that I think you can structure a policy.
I think while the money year to career is not huge, you know, everything counts.
What's really important for our work is the forecast.
The ability to know 10 years from now what it's going to be, it's really important.
Fundamentally, I think through all of this great work we're doing, the inability to forecast accurately has been a key business need the utility has to have.
>> Morrison: To argue against what I have suggested, the impact of say 2%, if we're doing rolling averages, could be very insignificant.
If we're doing rolling averages over three years.
>> Cole: Okay, let's continue.
We're going to lose some councilmembers I know about
30, so we better get rolling.
>> I did get confirmation that the impact on the residential class was about 2 million.
I think it's 1.8 million.
>> The next question was that I believe we were asked to compare test year 2009 with fiscal year 2011.
The 2011 financial statement, audited financial statements were released a few weeks ago.
But internally, the general ledger has not been closed and will not be closed until may.
So we can't do a lot of detailed analysis on the different [indiscernible] account, but I do have some information from you -- for you from the audited information with a new known immeasurables where we could detect those.
We did compare the two years for you.
I would like to go through those real briefly.
So first item is operations and maintenance.
And you can see that those are actually very close.
There's -- it's less than 1% difference.
The recoveriable fuel is quite different, but you need to remember that fiscal year 2011 has not been normalized, so it has not been weather normalized or year end customer normalized.
Once that is done, we all remember how hot 2011 was so it would probably come down close to the 2009 test year.
Other revenues and expenses, are very close.
We did adjust 2009, other revenue, to the 2011, looks like we might have overstated it slightly at that time.
That service is -- debt service is pretty much in line.
General fund transfer is the known immeasurable if in both of those, set at 105 million.
Capital from current revenue is down slightly from 111
million to 99 million.
That is really because we've been deferring so many projects and we are on an annual basis, we are financing more with debt.
But the debt equity still remains at about 50/50 in both years.
The required contribution to reserve, we talked a little bit about that at the last work session, because our cash is being depleted very rapidly, this will continue to grow.
The longer we rate, this required contribution will continue to grow so you can see it's almost doubled since the test year.
The contribution to decommissioning reserve stays the same because the basis has been unchanged.
So overall, the 2011 test year in this scenario is about $81 million higher.
I believe with the known immeasurable and the normalized it would probably be very close to the 2009 test year, it might be a little bit higher, but it would be fairly close.
So I think to me this shows that the test year is reasonable and that it would not change material if we used the 2011 year.
>> Cole: Comments, questions, okay.
>> Tovo: I was going to turner because he had an opportunity to review these.
If not, we can cycle back to it another day.
>> Spelman: Remind me, if I could.
Remind me, if you could, how we take into account our capital improvement plan.
In rate settings in the sense of looking at the test year.
Do we just figure out how much money we spent in the test year roll it forward, or do we actually apply our expectations for future c.i.p. expenditures?
>> What we did for 2009 was
we took a three-year average of 2009, '10, '11, what this 99 represents, because it's time we didn't have our forecast completed, we just substituted the 2011 actual to the 2011 estimate that we had in our test year.
So we felt like that was the most appropriate way to do that.
>> If we were to actually use '11 as a test year, obviously we couldn't use '11, '13, we don't know what they are going to be yet.
We do have a forecast for what we need to spend, could we do that instead --
>> use a forward forecast for capital, a cash and capital?
>> You know, we have that forecast.
Pretty close to the same number.
>> It is.
It looks like the annual overall is about -- about 200 million, but we are financing a little bit more with debt in the future.
So -- so it -- it might change slightly, but again that's -- that's mainly to try to fix the cash flow constraints.
We are deferring projects and maximizing our debt.
So it's for a little bit different reason.
So, you know, you could argue that there should be some known immeasurables to adjust it back to your debt equity as well.
There's a lot of assumptions in that.
with immeasurable means past .. [indiscernible] is that accurate?
>> That's correct.
I mean, you can use the -- the three-year average, but what we do is typically go to your debt equity ratio, not your annual percentages, that would still be at 50/50.
>> Spelman: Okay.
It would be 50/50 on 200 million, which is about 100 million either way.
>> The reason it's 200 million and 250 million and
not so other number is because you are constrained by how much cash we've got, presumably the constraints will be reduced if we get an increase in rates.
How do you square the circle?
I don't understand how we do this.
>> I see what you're talking about.
I think what the unknown is, of course, is our future capital needs.
>> Spelman: Well, is that unknown?
That is the basic question.
>> It is.
So we will take a past look at growth, how much substations are we going to build in 2015 or 17 or large capital issues are redifficult to do unless we just look in the past and look at our growth trends.
I think the capital forecast that I have seen here, outside of some larger ticket items like the sandhill addition, routine capital with the growth of the system.
And the $100 million is half of it and -- and I think the -- if we can produce that forecast, I will show -- make sure that everybody knows what it is.
>> Spelman: Your best guess to this point is still about $100 million.
>> Cole: Okay.
>> Any other questions on this comparison?
>> Councilmember tovo.
>> Tovo: Just a quick one, do you have a sense of what the customer growth was?
I see the preliminary numbers as you probably mentioned are not normalized for weather or year end customer growth.
Do you have a sense of how -- what the scope of that --
>> I can't remember off the top of my head what it was between '10 and '11.
We are forecasting growth of 4% average annual growth.
>> We have staff that I'm sure we can get that number.
>> Tovo: If you could give us kind of the one-line summary.
If we were to use, caveats aside, if we were to use the 2011 numbers, what would our revenue requirement be?
>> Well, this is as close as I can come right now.
We do know that fuel has not been normalized, I think it would come down close to the 2009 level.
I know that the contribution to reserve would remain at the 51 million, though.
So I think that any way you look at it, the 2011 with the known immeasurable and the normalized would be slightly higher than the 2009, I do not believe it would be lower.
>> Thank you, now we're going to move on to the topic of off systems sales [indiscernible] prior meeting.
JULY 31st, 2001 [NO Microphone] prior to that time, we were our own control area or well also call that the [indiscernible] authority which means that austin energy was responsible for planning, scheduling, and dispatching.
All of the generation in our system to meet our own customer needs.
We were also responsible for the instantaneous balance and demand, supply and demand has to equal out, we owned excess reserves to hold in the event of extreme weather conditions, plant outages, et cetera, because we were generally responsible for everybody serving our own needs.
At the same time, but it's kind of a separate issue, we also had excess generation resources.
We had stp come online, fayette, holly, decker, our
system was smaller -- our customer need was smaller than it is today.
So we had significant excess generation.
The market in the late '90s was very attractive for off system sales, so we made significant off system sales.
We kept all of that revenue and used it to fund reserves, which we later used for a variety of projects that we discussed, including the replacement of the holly power plant with the construction of sand hill.
That all changed in 2001, as I said, with the opening of what we used to call the ercot zonal market.
In the ercot zonenal market beginning in 2001, we continued to schedule and dispatch our own resources to serve our load, but ercot did all of the balancing function, they kept everything in balance.
As the slide shows, we submitted a balanced schedule to ercot with equal amounts of our sales obligations and our generation resources.
So every day, for the following day, we sent ercot a schedule for every 15 minutes of which power plants we were planning to dispatch to serve our customer load.
Ercot carried out the balancing function when they didn't quite meet, but we gave them a schedule of what power plants we were going to operate to serve our own load.
Where we had excess generation we sold that to other market participants when it was economical to do so and those transactions were recorded as off system sales, much as they are today when they have those types of transactions.
At this time, also, we had this new opportunity, the ercot market, we offered our excess energy into the ercot ancillary services and balancing energy markets as they are called, that's a
little bit different than today because those markets represented only five to 10% of the total power supply in the region, whereas today's ercot market represents 100%.
When we had off system sales to third parties, those were discrete transactions, we accounted for those much as we do today.
We kept the revenues from those, those have generally funded our reserves.
Over time, our load has increased.
Our reasonnation resources have not increased significantly, so we have, just on a factual basis, decreasing off system sales to third parties compared to what we had in the late '90s and the first part of the 2000s, I guess we call them.
We shut the holly power plant, we built the sand hill power plant and another thing that's happened as a result of that is the mix of our resources have changed.
We have more of a peaking system because of the power -- because of the facility at the sand hill system, whereas the holly system gave us more of a base load system.
The peaking resources that we have are better designed to be consistent with sales into the ercot market, rather than sales to third parties.
SO THEM ON DECEMBER 1st, 2010, Was the opening of the ercot nodal market.
Now, with that market we no longer schedule, dispatch or balance our generation, all of that is done centrally through ercot.
So ercot forecasts the load needs for the entire system, they carry out a centralized generation dispatch.
We don't send these balancing -- balance schedules to ercot telling them what resources we're going to use to serve our customer loads.
What we send them is a pricing offer that tells them what we will offer to supply at different prices.
Ercot takes all of the pricing offers from all of the companies in the system, adds them all up, puts them in a stack and then dispatches all of the generation resources in the system from least expensive to most expensive to meet customer load.
So our generation now, instead of being specifically nominated to serve our customers, it serves the ercot system load.
It's completely disaggregated from what our customer needs are.
There is -- I guess in a separate transaction, if you could call it a transaction, our customers are served out of ercot.
Whatever our needs are, we draw from ercot, ercot is responsible for making sure that the amount of supply in the region is sufficient to serve all customers, but those are completely separate.
In any five-minute interval, that's what ercot does, it tells us where to run our power plants every five minutes, we may have excess -- we may have more supply that we sell into ercot that our own customer needs or we may have less supply into ercot than our own customer needs.
It changes on a five-minute basis.
I do want you to know, though, that there is great value in the system to our customers.
Because our power plants serve as -- as I guess a back stop for what our costs are in serving our customers and this centralization of the market has kind of squeezed all of the inefficiency out of the market.
Remember when we were all kind of islands operating ourselves, we might have been running an expensive power plant when next door san antonio had an
inexpensive power plant.
Now, all power plants are dispatched in pricing order so that we've kind of squeezed out the inefficiency, that's good for all of our customers.
The last point on that slide, is within this ercot market, not talking about third party sales to other customers, but within this ercot market, there's no longer really a sense of what is an off system sale.
We just have sales.
We sell to ercot.
Does that particular sale serve us, does it serve third parties?
We don't know, it's just a sale into ercot.
So in summary, and I'm going to summarize and then anne is going to talk about the consequences for this in the way we booked off-system sales in the revenue requirement.
But that traditional concept of off-system sales no longer applies in the ercot market.
We no longer schedule, dispatch or balance our own customer load and our generation, our generation serves the ercot market, our energy is purchased from the ercot market.
These are entirely separate transactions.
But our objective is always to limit our customers costs financially to the cost of supply of our power plants.
If we sell 2,000 megawatts into ercot and during that same five minute period we take 2,000 megawatts from ercot, then the costs to our customers are the costs of our power supply.
If our plants are more expensive than the market price at that time, then we take more power from ercot at a lower price, that's good for our customers.
If the ercot price is higher, then we sell in more power and the cost of our customers, the cost of running our power plants is more efficient.
The cheaper it is for our customers, but when there it is excess supply in the market, we take that and benefit our customers with lower prices.
But I want you to know that overall in this issue of excess sales, we are a net buyer in the ercot market more than we are a seller.
And the way we book our transactions through ercot is that every day ercot sends us a financial settlement statement.
This is a daily statement for every 15 minutes, it has 55 separate line item components on it of charges and revenues for all of the different functions that are going on in ercot.
And as we have proposed, all of the benefits and all of the costs of those ercot transactions flow through the fuel charge for the benefit of our customers.
So I have two key points.
That I want you to take away from this.
And that is one related to ercot sales and one related to third-party sales.
With respect to ercot, we just have sales.
We may be net buyers, we may be net sellers in any 15 minutes.
When we are a net buyer, we charge our customers for that through the fuel charge.
When we are a net seller, we offset our customers' costs for that through the fuel charges.
That way we have done appropriate matching of excess costs and excess revenue.
We match them all up and we offset our customers' costs through the fuel charge.
Our second is related to third party sales.
Because of the facts of the way we operate our system, we have very little third party sales now.
In the 2009 test year, i believe we had $25 million in third party sales, less whatever the fuel was.
This year we have almost
churnic in his note said that we have booked something called off-system sales at $7 million for the first five months of the year, that's not really off-system sales.
That represents mostly congestion reimbursements that we have been getting from ercot.
So as far as these physical third party sales where we sell directly to another party, we have almost none of those now.
Different from the test year in 2009.
So now anne is going to discuss how we adjusted the revenue requirement to take account for the changes in the way that we -- that we managed through ercot and the difference in our actual off-system sales to third parties.
Mark did a good job of explaining the benefits of owning our generation in the nodal market.
As he said, those benefits include what we called off-system sales in 2009 and that's kind of what we're talking about now.
In the rate proposal, we have proposed to include all of these benefits in the fuel factor.
And what that will do is the -- the off-system sales or any of those revenues that come in will benefit the customer in the year that we changed the fuel forecast.
So it -- it -- it follows the cost causation and the matching principles as well as the fuel rules at the public utility commission.
So all of these benefits will be included in the fuel adjustment every year.
In order to talk about the off-system sales, we have to talk about the test year normalization of load and resource adjustment.
And that's what I'll talk about just to show you the three-step approach of how that was done in the test year.
The first step is to remove those off-system sales.
That were in 2009.
That was about 44 million and as mark said part of that was off-system sales, some of it is congestion, there were -- some of it was balancing from ercot.
So they were different types of revenue.
All of those are now included in the net settlement.
They are not distinguishable.
So the first step that you would do in any adjustment is to remove those things.
So we removed about $44 million from the test year.
Step 2 is to normalize those or figure out what the adjustment would be.
And so we -- we run a load forecast that is weather normalized and adjusted to the year-end number of customers.
Then we run that through a production simulation model and that model then dispatches those the way that the ercot market would do it.
In essence, it looks at all of the 4,000 nodes in ercot, dispatches all of those at lease cost and the ones that are labeled ae comes out as either revenue and then it also estimates the fuel associated to those generation units.
So it's a very complex model that gives us the results.
Those results come through and show us then what the load zone costs would cost.
If we owned no generation, then that's what we would have to pay to serve our load.
Then it shows us our fuel expense for our generation.
Then it shows us the revenue for our generation.
And all of the ancillary services, congestion, and the off-system sales are embedded in all of those numbers.
So when we compare the load zone costs that we would pay with -- if we owned no generation, to the net settlement cost from the model, then it showed a benefit of about $66 million.
So then that's the third step is to adjust that and book those things.
So we took out the 44 million, and in essence we replaced it with approximately 66 million.
And the off-system sales are included in that.
They are not necessarily distinguishable, but we can tell when we look at what it would cost before our generation was dispatched and after, we can see the difference, which is approximately 66 million.
>> Tovo: If now is a good time, I do have a question.
Commissioner day has pointed out that because of the way the long-term contracts work, that this system may not be or this method may not be as fair to residential customers and i churnic has provided us with some comments along the same lines, I'll just read from commissioner day's memo and ask you to respond if mr.
Churnic could jump in here, too, commissioner day's memo says removing the revenues from sales off system from consideration and base rates and netting those instead to non-fuel resident revenues against fuel, allows this -- sort of summarizing -- allows benefits contract customers because they don't pay any non-fuel generation expenses.
Because they're not paying base rates.
So they benefit from -- do you follow the argument?
You look like you are about to jump in.
churnic if you could --
>> I want to point out first on the particular line you said that I noticed in a memo.
Long-term contract customers pay base rates and in is generation cost in those base rates, so the base rates are not changing, but it doesn't mean that they are not making a contribution to fund the cost of these power plants and I didn't quite understand that particular point in the memo that said they don't pay base rates.
Maybe that was just a minor misat the same time.
But I guess on -- misstatement.
But I guess on the concept generally --
>> Tovo: Pardon me for interrupting.
They don't pay base rates consistent with what other customers pay.
>> Well, their base rates are fixed through the terms of the contract.
So we will adjust all of their customer classes rates in the rate review at the time that you pass some new tariff.
>> Until 2016 they are set below other customers' base rates.
>> They are set wherever they are set today and they won't change until the term of that contract ends.
>> The non-contract customers are not paying any additional portion in their base rates to cover the long-term contracts.
That's not happening in the proposed rates.
Austin energy is -- is absorbing that loss until the long-term contracts are moved to the new rates.
>> Tovo: Right.
I remember that adjustment in there.
But the -- and -- I don't want to speak for her.
But I wonder if that was the point that they are -- that their rates are set -- there is a gap right now, between the customer -- between -- would you help me on that.
>> The only thing that I can think of is when you mix it up with the fuel charge because the fuel charge is being passed on to everybody and so there's the disconnect between what's going on with the fuel charge and what the net revenue is for wholesale sales and when mark talks about that going into reserves, really what it does is it goes to cash, it gets balanced against the fuel charge, depending on the recovery and base rates right now you have a large block of customers, use a lot of energy who are at a rate that was established at the time of their contract.
And that will all go off in 16.
So I think that for the short period of time we do have confusion between the recovery of revenues from different groups, but the time between now and those contracts changing is pretty -- going to happen pretty fast.
And so I guess in my mind this is a question of whether we need to try to work something to correct for that or not.
But as anne pointed out, that $25 million in additional revenue is forecasted in the initial revenue requirements part of our rate increase.
So -- so we really can't deal with that now, but those base rates will go up and everything goes to square -- when everything goes to square I guess.
>> I think that ms. day, mr.
Churnic are both correct that there's some cost shifting going on.
I mean, this is a rate review, there's cost shifting embedded in all kinds of decisions.
But to me this is kind of an issue of -- excuse me, of the consequence of not changing our rates in 18 years.
We have a number of different elements in our current rate structure, in our current accounting practices, that -- that have become inconsistent with the way we actually operate in the market.
One of the objectives of this rate review is to clean up those distortions and disparities that are embedded in our current rate structure.
So that over time rates will be more fair and more stable.
So -- so while there may be some cost shifting because of the -- because of the different treatment of fuel, it's the right treatment of fuel, we believe, given the way the market is structured and the way we have to operate in the market and as a whole, there's no change in total costs to our customers that -- the change in booking of these revenues into fuel doesn't change the total cost to our customers, but it does have some cost allocation implications for the three or so year period where the contract customers continue to pay their current rates.
But that -- just that one tiny points that you said before from the letter that they don't pay production costs or -- or generation costs is not quite correct.
>> Probably I'm quoting [multiple voices] multi-page memo that is really quite in-depth.
So I probably quoted it -- should not have quoted it out of context because i think commissioner day does make a very good point in this letter and I think has good grounding for it.
churnic might speak to the cost shift because though it is just a few years, I think that i significant.
>> Morrison: My question here also, it's not just about for me it's not just about a question of contract customer.
The simple question for me is if we're looking at some revenue and some costs, i question why it's all handled through fuel because we know that the costs are fuel as well as generation.
>> Well, first of all, it's common practice to handle that with -- with -- for all utilities.
That's the way it's done as a standard through the fuel.
So in other words if you have a wholesale market where -- where it actually costs you, like last year we netted a loss really because we had plants go down and everything else, that recovery mechanism is your shack absorber for that.
If you have a [indiscernible] I you do it all through the fuel.
If you do it all through the fuel it spreads through whoever uses the fuel.
The kilowatt hour users pay more of the fuel charge, there's really kind of as mark said, year to year, you can view one group of customers as having a win or s, depending on who the fuel users are.
>> My question is not about let's finds the winners and the losers.
My question is I'm just looking for the logic in why it should all be through the fuel and you are suggesting because that's the way we do it.
>> Well, I'm not -- I'm suggesting that's the most efficient recovery mechanism.
>> Morrison: Efficient in terms of what measure?
>> Efficient in terms of the whole risk model and the wholesale market that austin energy operates under, was put together with a lot of work here.
And it was all put together with the ability to flow it through in real-time, well annually not being real-time, an annual adjustment.
I think you all know how it works.
So that way austin energy's regular finances, if you will, the operating part of the utility, is really insulated from having to come back and do rate adjustments all the time based on a volatility that might exist in the generation portfolio in your fuel.
From that standpoint up to the energy crisis in 2000, the rating agencies, bond markets and everything that rate municipal bonds for publicly owned utilities took challenge to some of the problems that can come from not having this -- this recovery mechanism.
So when I talk about everybody doing it that way, what I'm talking about is there is a standard in the industry, for publicly owned utilities that are generators, to handle their wholesale markets in this behavior.
And it is -- it is -- protects our customers, because we have the ability to get that -- but one way or the other.
Now, you can have yours, mark talked about it, early 2000s, there was a really robust wholesale market, that has tightened up around the country.
So we just have to normalize it.
I can remember years where wholesale markets were really lucrative.
In a couple of years.
Then that led to some lawsuits as a matter of fact some other things that happened nationally.
But now it's kind of simmered down and now with the gas price where it is, the only thing that really happens is that we have net cost annually because we might lose one of our cheap resources, like if we lost the stp project, the hit comes to the fuel charge.
But likewise there could be a market some day where we have a lot of sales and that would come into that.
So that's the logic behind it.
And so the variability part of it is who uses the fuel?
So as your customer profile changes over time, a certain customer group is going to be more responsible for the fuel than another group.
If you will.
That's -- that's where the dynamic comes in.
>> I want to give you just a slightly more weighty kind of answer about why these costs belong in fuel.
>> What kind of answer.
>> Weedy, down in the weeds.
>> More technical.
>> Remember the slightly.
So let's say in the next 15 minute interval we are on net drawing more power from ercot than we are selling so we owe ercot money.
We charge that money to our customers through fuel.
I don't think anybody has ever challenged that that's the appropriate treatment of that when we're short and we have to pay ercot, for -- for excess power, that goes through the fuel charge.
But in the next 15 minutes, we might be long.
We might be selling more to ercot than we're buying from ercot.
So we're receiving revenue.
So the question is how do you book that revenue?
And it seems to us only appropriate that we also book that revenue to fuel so that our customers who are paying when we're short are also benefiting in the same way when we're long.
So we're -- we're trying to keep that balanced all the time and all of that is going through fuel and since -- since when we have those sales, in ercot, we don't know if they are serving our customers or they are serving some other customer.
We're just giving all of the benefit of that to our customers by offsetting their fuel costs.
>> Morrison: I see that definitely makes sense if you're going to allocate the extra costs through fuel, then you definitely have to allocate the extra revenue through fuel.
I'm just trying to get to understand why we do it through fuel either way.
But I think we need to hear from mr. churnic.
>> One other thing in summary, you may remember back earlier in this process we talked about fixed versus variable costs.
Well, because these are just like larry and mark said, they are very volatile, they are unpredictable, they are definitely variable costs, all of our variablable costs are allocated on kwh production.
>> I think on a lot of the fundamentals I agree entirely with what you have heard from the austin energy staff.
I don't see the change being significant from before the nodal market to before the nodal market as the staff does in terms of conceptually what's going on.
But the fact is that -- as long as your transactions are short term, it's hard to distinguish between sort of the economy transactions and what would normally have been considered an off-system sales.
You certainly can have bilateral sales and it's my understanding that -- that it's -- that it's -- austin energy's position that if they made one of those, signed a contract, for three months or whatever to -- to sell a block of power to -- to another utility or to a -- to a retail supplier, they would roll those revenues into the fuel [indiscernible] I don't think there's any real concern here about austin energy overcharging in total.
But I think there are three real issues here.
The first is the issue with the fixed contracts.
Their contracts were set assuming that -- that off-system sales were going to be credited through base rates.
And therefore the fuel charge would be somewhat higher or else equal.
Now austin energy is saying, well it's really hard to sort out what a real off-system sale is as opposed to an economy transaction and so we want to just get rid of that distinction and have all of our revenues generation related revenues from outside the system flow through the fuel clause.
The problem with that is you have these customers you put on fixed rates assuming a certain kind of fuel clause, now you are making it a somewhat less expensive fuel clause and making base rates a little higher, which works overall for the rest of the customer base, but not for those -- those customers on contracts.
So I propose that to solve that problem, a -- a base rate credit for off-system sales, bilaterals, ancillary services be rolled into base rates and that the same amount be used as the base for the fuel adjustment so that austin energy will collect its total costs net of its revenues, it's off-system revenues, but that some of the benefit will be in base rates and once the -- once the -- the customers come off the standard contract, the special contracts and go on to the regular rates, then -- then you could switch the next rate proceeding or phase 2 of this proceeding or however you want to do it could change that and get rid of the 35 million credits, what I propose the -- the austin energy says in their slide here, it was 44 million, but in any case, to have some set aside recognizing the fact that those contracts were set up assuming that -- that the -- that the benefit of the off-system sales was going to go through base rates.
And therefore presumably their base rates contracts are somewhat lower and they would really be double dipping if you did what austin energy is proposing to do right now.
The second thing that i would suggest that the council be aware of, there is a shift of revenue requirement between classes, as a result of -- of taking a credit that would have otherwise be allocated as fixed generation costs and moving it io a contract as unallocated energy.
So less of that credit is going to go to the residential small commercial or if it's going to go to -- to -- to the industrial customers.
Now, a question is, sort of the third issue is -- is that equitable?
And the effect exists, but maybe it's okay.
I think if you -- if you follow the kind of -- the kind of direction that i suggested in terms of old allocating production costs where most of the costs are recovered through energy, then recovering the benefits that go with those fixed costs through energy in the fuel costs makes sense.
If you say we are in a world, as I think austin energy pretty much explained, where -- where the -- the cash flows in and out of -- of austin energy to ercot, to fuel suppliers, they are all energy based.
There's very little that's -- that's capacity related.
They are peak demand related.
And -- if most of the fixed costs of generation are allocated energy, then the benefits that you get from being able to make the off-system sales in whatever form you describe them, flowing that through energy makes perfectly good sense.
If on the other hand you keep the -- actually not keeping it, if you move from what you have got now to the proposed average in excess, which is basically a peak allocator, to the extent that they are generating revenues to -- to support -- support customer loads, they are generating revenues from the off-system sales, which flow back to customers, if you flow that through energy credits in the -- in the fuel clause, then you pay based on your peak, which means that it hits residential small commercial, and -- and you get a credit based on your energy use.
So -- so the simplest thing to do is to go in the direction that I suggested in terms of cost allocation, put most of the fixed costs on to energy, then you can just say oh, the heck with it, once the special contracts are -- are over and we're -- we're looking at -- at everybody paying the same kinds of rates, then -- then we can just -- just -- just flow all of the -- all of the wholesale transactions through the fuel clause, whichever way they're going, whatever length they are, and -- and that's about right because most of the fixed costs of the plants will be collected through energy.
But if you don't go that way, then I think you have to -- to wrestle with how you credit some of the benefits of having the generation in terms of austin's transactions, how you credit those to -- to -- to the people who are supporting them.
I probably talked more than enough.
>> Cole: Thank you.
I do want to -- to remind everybody that we do have another presentation, rate design, and many of these issues will also be encompassed in there.
This is the end of your presentation, correct, on -- on the financial?
>> Yes, it is.
One of the questions earlier is what was the customer growth in 2011, it was 1.2%.
>> Cole: Next we're supposed to have a presentation on rate design.
But just in the interest of not losing any councilmembers, we are also supposed to discuss on item 4 our work schedule.
And I thought we might go ahead and take that up.
Does staff have any outline of what we have scheduled thus far?
With -- with -- with -- with a listing of that, the ae work schedules, the council meetings, the council work sessions, the budget work sessions, the work sessions on rail, the work sessions on bonds, the work sessions on the work sessions.
>> councilmember, let me just say that -- that this posting is just for these sessions.
I believe on tomorrow's agenda for your regular work session, we can have that broader discussion.
There was an item put on tomorrow, but if you want to talk about these sessions, moving topics, moving dates that's what this posting is about.
We have tomorrow a broader discussion.
>> Cole: Okay.
>> Morrison: I do think that it makes sense to consider, I think we have a -- another ae work session scheduled for tomorrow afternoon.
And we had earlier discussed in general that we really didn't want to have two ae work sessions during a week where we had a regular council meeting, not to mention that we also have a budget work session this week.
So I was going to suggest that we take a look at canceling tomorrow's and moving it to a later date.
I don't know what that later date should be.
We could talk about that tomorrow.
But I thinkat's something to consider.
>> Cole: I think that is a great idea.
>> Morrison: I thought that you would like that.
>> Cole: I don't think that we -- we necessarily need a motion.
That would just be direction to staff or any other ts about that.
>> Tovo: I agree.
I think we're overloaded this week.
But I will just want to churnic is in town through tomorrow and we probably, you know, want to talk about when -- how we might fit the rest of the sessions into a schedule for him.
>> Being on.
>> Part of the appeal of having the two sessions, you know, back to back is that chernick could be here tomorrow i, believe and may not necessarily be able to attend the rest.
In any case, I think that we still need to have these sessions in a way that we're fully able to participate and it sounds like tomorrow is probably not a great option.
>> Cole: If there's no further comments --
>> let me just say.
In direction it would be helpful to staff if you say just move everything back or you will come back and discuss it later as to where the proposed session for next -- for tomorrow would go?
>> Tovo: I think we just want to move everything back.
Just keep shifting.
>> Morrison: Then we'll have to come up with another date for one more work session.
>> Tovo: Right.
I think we need several more at the end at this point.
>> Cole: Okay.
So clear about that, larry?
Are you good?
>> Cole: What is your question?
>> Well, I didn't hear all of that, I'm sorry.
>> Cole: I guess we're not going to have a work session tomorrow.
>> You are not?
>> Cole: Afternoon on ae, no.
We're just going to have the council work session in the morning, but not an ae work session.
And so the question is did you understand the direction by councilmember tovo and morrison that we simply want to move everything back, that means a shift, finish i think wherever we land at any particular point and then move the items upward so that nothing gets missed, we're still keeping the categories, but we're working with different dates.
>> Being on.
We're prepared -- okay, we're prepared to handle any issue any day as long as karen is happy with the agenda, and so -- we're ready to go.
>> We'll work with your offices on the constraints that we have on certain dates.
>> Cole: Okay, thank you, as long as everybody is happy.
Anne, are you ready?
>> Well, mark is going to go first and then I'll come in, in a few pages.
>> Thank you, councilmembers.
Right now, we're entering a -- a new phase of a rates discussion.
A phase you might call the fun stuff.
The revenue is more of a fact based discussion, what are the facts behind finding out what the right numbers are.
Rate design is more of a policy discussion.
What is the right rate design that we have to set in order to meet our community policy objectives.
Recognizing that we have a -- that we have a legal and regulatory framework that we have to work in.
We have a very short discussion on the first two issues our rate design principles and the proposed rate design and then the other issues are those that you identified for us and we're happy to work through those, however you want to move through them.
[One moment please for change in captioners] don't want to talk about those, if that's important, but those fees are part of budget and are part of the fee schedule that we set.
So they're not rates.
They are fees.
And so we can bring that up in the budget process because I think we have a set list of fees that we charge for a variety of different things.
And if you're talking about field collectiond disconnections and all of that, that's one issue and that's fees.
If it's about line extensions and what we charge new customers to hook up when we build, and we're building new customers, that is a revenue issue, and what we talked about before is that we're doing a study right now.
We are not prepared to enter into quantifying -- quantifying the amount of revenue that could come to any change from our line extension policy as of yet because we have a study that's going on.
It will probably take about a year for us to have a recommendation.
>> One of the things we talked about with regard to line extension fees are whether we had a different policy, different council policy on that, then perhaps there would be more revenue recovered and the reason that it's on the schedule is because it may have some impact.
The thought was it may have some impact on the revenue requirement going forward.
Decrease connection, connection fees are on the schedule for some reason.
The fact that iy not have a big impact on the revenue requirement, I do think that it's appropriate to take a look at our policies with regard to connection and disconnection fees because while the technology now allows for those reconnections to be done very esively, we continue to charge our customers the same high rates that we did, you know, when there was a truck that needed to go out to restore power to somebody'souse.
So I do think there's a policy issue there that we absolutely need to address, and again, it's on the calendar because we're sort of hashing throughs of different austin energy policies, some of which may have an impact on the revenue requirements, some of which may not.
So I guess I'd just open up to my colleagues whether we want to talk about it today or perhaps at our next session or sometime soon, but I do think while we are our head in this issue we ought to have a discussion about it.
council member spelman.
I'm nore the best time to talk about it but I want to let everyone know I have to leave at 1 15 at the latest and i would prefer to get into rate design for that purpose.
larry -- I mn, mark.
The figure that we've prevented for you is kind of where we started our discussions.
Last -- a year ago january with the public involvement committee.
With tha group we developed and discussed the rate design principles that we would follow in this process, and, in fact, we have a white paper, public involvement committee white paper 2a that discusses this.
We also shared these issues with the electric utility commission last spring and summer, and what the figure shows starting from the bottom is that our rate design first has to be based on sound economic and cost of service principles, and then along the way there are these points that have to be balanced, that we have to strike the right balance for fairness, establishing financial stability for the utility, our energy distinguishes to -- affordability for customers, consideration for low income customers, understandability, transparency of our rates, adherence topriate laws and regulations, and then in the end the rate design that we come out with has to support the strategic direction that's been developed by austin energy and approved by the council.
So what's unique about this rate design philosophy is that it is driven by our and your strategic directions.
Those are found in the 2003 strategic plan, in the austin climate protection plan, the resource and generation plan to 2020, and in the city financial policies.
Those involve very extensive energy efficiency and conservation objectives.
Our objective is to develop 800 megawatts of energy efficiency resource by 2020, which is not an insubstantial goal.
We're talking about a third of our system being served by -- not quite a third of our system, but a significant portion of our system being served by energy efficiency rather than sales of electricity to our customers.
We also have the affordability goals that we have discussed extensively, developed by the council, and fundamental public power, we have to provide community value and benefit from the community's ownership of our service.
And in the end we have to balance among these multiple objectives which are not always consistent across each other, and so we believe that everything we have presented in these recommendations is an effort to strike a balance in fulfilling those objectives.
Are there other options and approaches we might use to fulfill those objectives?
But the recommendations that we've made are a balance to meet the utility's objectives for financial stability while trying to satisfy all of the objectives for community outcomes that have been adopted by the utilitynd the council.
So very briefly as you know our current rate structure is made up of these elements.
For residential and small commercial customers only we have a $6 customer charge, so if you use no electricity at all your bill will be $6.
We also have an energy charge.
That recovers o&m expenses, capital cost ofr services, wires and power plants.
For residential customers that's a two-tier block, a lower tier the first 500 kwh and a higher tier and it's dairchld for winter differentiated for winter and summer based on six months.
For commercial customers above 20 willo watts a -- kilowatts there's a demand charge in addition to energy charge.
That is to satis again there is a six-month seasonality baked into those charges.
We also have the fuel charge or the green choice option,ince 2009 we have the transmission service adjustment rider or tsar, which was designed to capture the recently increased cost of this operating the statewi transmission system due to the build-out to accommodate primarily west texas wind power.
The proposed rate structure is similar but has a number of changes.
First we extended the customer charg from just serving residential and small commercial customers to all customer classes.
And as they have discussed extensively and we'll discuss some more, we have raised those fixed charges to improve fixed cost recovery.
We have added an electric delivery charge, a new charge which is also a fixed charge, which collects a portion of the electric delivery or distribution costs as a fixed charge for residential customers, and as a demand charge for commercial customers above 10-kilo watts.
The energy charge for residential customers we are recommending be expanded to five tiers from two tiers, and we are recommending to adjust the seasonality factor into the four peak months rather than the six months that we previously defined as summer.
Of the demand charge we are recommending to expand to all customers to 10 kilowatts per month down to 20 kilowatts with the same change in seasonality and we have also recommended a number of unbundled charges.
These unbundled charges provide greater transparency as has been a top priority promoted by our electric utility commission over a long-time period and provides dedicated funding to -- to the functions that are embedded in each of those charges.
>> Well, bear with me on this chart.
It's a lot of numbers.
It's complicated and part of it is that we've got non-summer and summer on here, so focusing on the summer, you see in the first column you have the existing rates for austin energy customers, and what we've done on the tiering is we've just reflected the cost spread across the break of kilowatt hours so currently 55 cents for less than 200 and so forth.
The cost of service is the next column, and the cost of service isn't allocated amongst the tiers.
The cost of services for overall residential in the summer-winter split, and the fixed charges came up to where they are.
My experience with all cost of service and public power systems is you never recover all of your fixed costs.
It's extremely difficult to go there, so it's a pretty -- it's loompling and sort of threatening -- alarming and sort of threatening number when you first see it, but that's the analysis that was done here and that's how it comes out.
So alternative, if you don't collect it there, you collect it in the energy you sell.
Along with a lot of utilities across the country like austin energy, we have more regulation today, we have more individual line-item programs what's been offered and down below you see in the community benefit charges, customer assistance, our street lighting program, that's all included in the energy above, what's being proposed and what the cost of service shows is that customer assistance programs street area light, energy efficiency programs which was recommended by the electric utility commission that we have a separate line item for energy efficiency, and then a regulatory charge which includes all of our ercot charges and -- that we recover.
Those change from time to time so we can increase those without affecting the entire rate package.
In december 2011 bringing the full revenue requirement and the full best business case forward, we projected a rate increase like this and we looked at tiering, which I'll talk about in a second.
And then what we ended up doing is looking at our -- a prudent way to go about this in a two-step process, and so the proposed increase focused on the phase 1 increase, which is on the table now and that's what we're seeking your approval of.
With that we reduced the residential -- this is only residential.
We reduced the residential charge to $22 a month, 10 and 12, and the other most important part of that is we're including 200-kilowatt hours in the two $12 charge.
So for $22 every customer is receiving their first 200-kilowatt hours free.
What does 200-kilowatt hours run?
Typically lights and a refrigerator in an apartment, comes under the 200-kilowatt mark.
An average medium size residential home as a base use might have 500-kilowatt hours and on up and everybody is different, a a little bit, but 200-kilowatt hours is a pretty decent break point for minimum electric usage.
The next breaks, residential tier rate design let me talk about that.
First we've heard a lot of concern about this.
It is new to texas.
There are not utilities that use this.
This rate design is actually -- it's been approved and actually state commissions have asked for it in several states.
I don't remember how many the last time I looked it up, and the count keeps coming.
In fact, I think the state of idaho just ordered that this design be used.
Why this type of rate design?
Well, first of all the tears create flexibility -- you could implement five tiers and have two tiers be the same and use that as a tool.
It's done for two primary reasons.
One is to promote energy efficiency, that is by giving our customers who can use our fabulous programs, to get themselves out of one tier into the next lower tier.
If you have fewer tiers and you try to do that, what happens is the cost between those tiers becomes very abrupt, and having an abrupt change between tiers is a real concern for consumers when they first start using this type of rate design.
The top tier in this would 8 cents per kilowatt hero.
In that block a customer saving energy into that tear will save most of their highest block of energy costs.
So for example, an air-conditioning improvement.
The other idea for this rate design is we were really not interested in putting demand meters like small commercial customers -- putting demand meters on residential homes.
Having demand meters and energy meters on residential homes is a real customer relations problem.
It's a customer issue, and to release that technical level to the customer is pretty difficult.
We do have customers that are interested in time of use.
We will have a pilot program for that, but the fundamental reason for this rate design as well is to address demand.
So the three air conditioner home has more command on the home than a single air conditioner home.
So few follow that logic that's another reason for this.
We did not invent this.
This is modern rate design.
It's being used in every region of the country that wants to promote energy efficiency, they want to promote correct price signals, to give consumers the best incentives possible.
I found it interesting here that after a while the air-conditioning contractors and the energy efficiency contractors in our community started -- I mean, they get this.
They understand the incentive to do this.
If you run your numbers on any kind of efficiency programs with this type of design, the cuss pay back -- customer pay back is much better than on our existing rates.
So in the spirit of what mark talked about, trying to make sure that our programs are successful and that we stimulate energy efficiency to the best we can, that is the purpose of these types of rate designs.
Now, the controversy comes, and you've heard this in some comments that I've read that, you know, utilities that have had top tiers of 40 cents a kilowatt hour, they've run into problems and the state says you can't do that.
Those are private utilities that -- that have been -- very aggressive about tiered rate design.
Frankly I think it's because the regulators wanted it, they wanted to signal a big schaub to customers to try to get them on eshock to customers to get them down.
But 40 cents an hour would be quite a shock.
Those have changed.
You'll find across the country there are a lot of people using tiered rates and they all have a different slope to that rate change and that's really the key to that.
So we've picked a very moderate slope.
There are some that say it should be steeper, but our concern has always been, is that to keep this fair and between the classes and everything else.
So the next slide is on commercial customers, and what we're proposing there is very simple compared to the residential site.
We are removing secondary voltage below 10k w, and the kilowatts were measured in an interval of time for every customer because we're going to remove that demand charge and we're going to remove the electric delivery charge and the benefits will be to small worship, school portables, small retail businesses, and the rate structures are similar to current, and that is there's an energy component, a demand component and a minimum charge.
And it does not shift cost to other classes.
All of the costs in anything that we've worked out here has all been contained within the commercial -- the commercial class.
And then on other commercial, because we're implementing steeper demand charges to reflect, again, the true cost, we are looking at a three-year transition period so that we're not affecting the full demand charge right out of the gate for those customers.
So with that I think going back to the residential rate design or any questions on that, I'll take some questions right now on that.
council member morrison?
no, I don't have any --
>> council member spelman?
will we be returning to the houses of worship issues later on or this is our shot at talking about that?
>> Pardon me?
this is the basic -- will we return to the house of worship at some later date --
>> I believe that's on the agenda for the next meeting -- that was my understanding.
>> And we received some input from your offices and others and we're working on that and we hope to be available to discuss that -- I have some questions on that issue but I will hold them until the appropriate time.
council member morrison?
I do have one question on the residential rate recommendation.
One of the new items that we're looking at is an energy efficiency program charge based on kilowatt hours.
And one of the things that came up in our discussion of water rates -- I know you don't like me to bring those but the things that carry over, and that was concerns about laying out in a line item charge something like the conservation programs because it's a pr issue in terms of people looking at it and saying, well, why am I having to pay for that?
Is it an option to include energy efficiency in the fuel rates?
>> In my opinion, it is, but my understanding is it's not commonly done at the puc.
So it would be an item that we would have to, you know, bring up in that context.
I am aware that the largest public power utility closest to us -- they recover it that way, and I personally think that would be a better way to do it but whether or not that's the right way to go through the puc with it or not is a question that --
>> council member?
We have been advised by council that there are some possible challenges in that area if we should be subject to an appeal before the public utility commission.
so I guess i would like to be able to explore that possibility, because I think it's an alternative that I think would be good to have on the table here.
So I don't know what the next step would be.
I guess it would be to ask you all to put together what it would look like if we did that and make sure we're wellapprised to the potential risks to doing it that way.
We would -- this amount is set by -- based on our budgets, and we're going to continue with our budgeted programs to meet our goals.
So it's just a matter of whether it comes out of that fuel revenue or whether it doesn't.
It would be -- again, i think it would be more efficient to handle it through fuel, and then like a lot of our business decisions that we're discussing here, I guess sometimes it comes down to a question of do we want to do it like -- exactly like what we think the puc might do for a very small part of our service area, or are we going to do it for austin energy and what the right decision is.
And so that's, I guess, ultimately -- ultimately you'll have to wrestle with that.
and I think it's important -- I think it's important when you look at the puc impact, it's not just like the puc would have us do, but what is the real risk of what they will do if we do it another way, and then following that -- and i know that's not an easy question, but it would probably just be good to look at some other similarly situated mou's and why they chose to do that as opposed to just a private.
>> Well, I think the money doesn't change no matter which method you use.
It's just whether you're picking up through a line item or whether you're picking it up through field.
So from a regulatory standpoint the revenue and the cost is the same.
-- why are they challenging it or looking at it so closely at the puc?
>> Well, I don't think they are.
The question is would they, and that's really the question, and that's the point I make is that we have to design everything around the possibility of that or we just take what's the best policy forward and -- what's best for the city, that's the only question.
but also if it challenges the puc, we have to deal with it and if forced to go back to a line item we could do that, but if there's a consensus that it would be a better way for the city to look at it in the -- in the fuel charge, that's what I'm inclined to do.
>> Perhaps that's an issue we might want to discuss with council at some point.
>> Cole: okay.
>> I would to say I agree.
I think this is a good option to putting it to the fuel charge and I really appreciate what you said, reese about making decisions that we think are best for the majority of our customers and not sort of -- I mean, I don't want to -- well, I'll just say that the way I see it, which was inspired by your comments, was that we need to make decisions that are good for the majority of our customers and not be overly fearful of what some of the objections might be and limit our options at this point, and I think also it would seem to me, and this is something we can discuss with council, that if there were a p usm c appeal on that point -- puc appeal on that point, our council could -- counsel to point to the other majorly owned public utility that does it the same way.
Whether or not that would be successful I think is something we need to discuss with our outside counsel.
and it's interesting, and I take this kind of based on what our city manager said earlier, and I think it bears mentioning that here we're sitting with a particular hat on as to austin energy and what might be best for austin energy.
But we are elected to determine what is best for the city.
And sometimes those may not always converge or line up.
They actually might be at opposites, and I think it's really imperative that we note the times that that is happening, like it might not matter at all or be better for austin energy that we not pay as much attention to what happens at the puc, but it might be better for the city as a whole to care about that because of the long-term implications of what the puc can do, so we don't want to just discount the way that they may think about things.
Any other comments or questions?
yes all of the programs put it in the fuel charge.
>> I believe so.
aren't there some in base rates as well in san antonio?
>> We could find out.
my understanding was they use a combination of base rates on the fuel charge.
Is there any benefit to having a separate line in terms of being able to set -- being able to adjust -- adjust it between rate cases or being able to set goals over a multiple period of years?
>> Well, the flexibility to the fuel charge is actually easier because we could reflect it through the budget and recover it through the fuel.
So with here, we would have to have this approved where we could submit a number for the budget as we submit the budget to the city manager, we go through and say we're going to raise the efficiency charge a little bit.
You could put a mechanism in either way to adjust it up or down.
>> In -- you're saying we would be able to adjust that between rate cases?
>> That was the idea, is that any of these items here could be -- could be adjusted if there was -- if there was a need to, and that, I believe, was the philosophical point of the electric utility commission by having that a separate line item, is to demonstrate that we are funding the program and that it is important to us as a objective, and I'm not sure if I could remember all of their other points about wanting to have that in here, and it's been something they've talked about for some time.
So that, I think, is where, really, the idea came from.
and I think one thing that's impressive about san antonio's energy efficiency is some years ago they adopted a plan to step up their energy efficiency -- commitment to energy efficiency over time so it wasn't just a one-time adjustment, it's a long-term commitment and I think we've had some discussion here about doing something similar to that, actually setting goals for increase in expenditures on energy efficiency overtime in order to reach our long-term goals, and that having a separate line item fee would allow us to help recover those additional amounts.
>> You know, frankly, the challenge since I've been here of energy efficiency programs isn't the money we have to spend.
It's getting the customers to spend it.
You know, it's marketing the program and getting the program moving forward, and the way that we've operated our budget so far is if there's 50 more solar systems that could go in this year and our budget is getting close, we'll go find the money somewhere to make sure that our programs -- because the marketing of the program -- the marketing of energy efficiency, the marketing of all of that and the use of all our funds for all our programs, the marketing is really hard and the economy recently has slowed that down a little bit, and we're trying to do our part to do the marketing.
So that's where the budget becomes tough.
We can set any budget number we want but we got to get the customers motivated to spend it.
So there's a little bit of disconnect there.
I'd follow up on council member riley's idea.
We're spending currently on conservation, operation and maintenances.
Which includes marketing.
>> And the other is rebates.
>> It's call the carif.
Conserve rebates incentive fund.
>> Spelman: okay.
How much of our total spending initiative is crif.
>> It's about 15 million in crif and the whole program is about 50 million, the all in, total amount --
>> I think it's a little bit less than that because there are some other programs incorporated into the distributed energy services, des.
What we're including in here is about $27 million, and that includes the rebates for energy efficiency, solar and the overhead that goes with that.
27 includes solar, energy efficiency and overhead.
>> Yes, and also the green building and programs that are related to that.
>> Spelman: okay.
What I had been hearing is that there's -- one way of differentiating between what we put in the rates and what we put in the fuel factor is the distinction between the overhead or the o&m expenses and advertising.
that would go in the rates and then -- cr --
>> crf would go in the fuel.
We're buying energy so that's makes sense.
the kilowatt hour I don't have to buy from ercot because I already bought insulation --
>> consider a power plant.
so the puc has not considered a case where -- anybody has ever tried to do that before, because the only people who would be doing that would be municipally owned utilities and they haven't heard an mou rate case since 1981, or whatever it was.
>> I believe that's correct.
Just like this rate design that a number of other items we're probably going to discover going to be unique to texas.
seems if we included the o&m in with the fuel factor -- if I were the puc I would look ascans at that and see what are we doing, but if we separate the o&m and only put the rebates and the other variable costs in with fuel, I think our case is really good, for the reasons you just mentioned a minute ago.
That would be I think where we ought to start.
>> Yeah, and I think that we probably -- I didn't say that that's the idea.
That's what we were actually thinking about, if we did that.
>> Spelman: okay.
294 or 293 cents per kilowatt hour that's on that -- in your proposal, roughly 12 -- roughly half of it is o&m and the other half is crif.
Is that about right?
>> I think only a third of that is o&m but I can get you those numbers.
if you could get me those numbers I'd like to see them.
council member riley?
I do have some other questions but -- other items on this chart if we could.
I think it would be a good idea to finish this because we're at a stopping point so why don't we finish this.
actually if we could go right to the top and talk about the customer charge that would be helpful.
First, let's just talk about the concept.
We've gotten some suggestions that the customer charge really should reflect the marginal cost of a new customer, and so for that reason we don't often see established urban utilities with very high fixed charges because our infrastructure is largely in place, and when somebody moves into a previously unoccupied apartment, there's not a whole lot of additional cost, especially with our current metering mechanisms.
70, from that standpoint, seems rather high.
Is that -- is marginal cost a fair way of looking at that charge?
What's the concept that's at work in that customer charge?
>> Well, the concept at work is basically the consultant boils down all of the accounts at austin energy and looks at those costs associated with customer service, manning the phones, doing all the different customer services, outage that we have -- outage not necessarily the system cost of picking up the outage but having the outage capability and all of that.
So it's very far-reaching and you add that all up and you look at your cost and how it's allocated and they come up with a cost of service number.
And similarly, on the distribution side.
And as you know, one of -- what we're trying to do is we're dropping the energy rates, have gone down in this scenario, so it's a balance between a higher fixed cost, you can bring your energy rates down and the only thing in the energy rates is energy rates.
So if you take your fixed charge and you move it down to really low, then we have to put everything on the energy rates.
So it's just -- it's just a trade-off between revenue recovery, and all things being balanced, austin energy isn't making additional revenue by raising the minimum charge.
What we're doing is just shifting it between the energy recovery and the base.
So that shift is between low -- small-using residential customers and larger ones.
And the former cost of service, when you look -- it's in all of the documents, when you look at the cost of service analysis that was done, the huge gap between the low residential customers and the large ones, so the larger ones we're subsidizing heavily over there.
And -- are sub you know -- subsidizing.
You never get it perfectly so it's all a balance.
The result is whatever customer service minimum charge we have or you agreed to do, we will have to take that revenue that we don't recover and we will move that into the energy charges.
And that's just the -- what we'll do.
>> Riley: into the energy.
>> Yes, move it into energy.
And then I think the other thing we did, of course is we have the first 200-kilowatt hours is included in the $22.
So at some point that minimum charge gets down low enough, that energy -- you know, we would be -- we would have to take that 200-kilowatt hours back out and put it back in the energy.
More like our rates are kind of today.
but there's no conceptual reason why we need to put the bulk of the costs embedded in that customer charge in the fixed charges as opposed to the volumetric rates?
>> Well, again, you know,, at least for me when I came here, you know, we have these -- climate protection plan and we have all these really high goals, which i think we can achieve, and the idea was that is that we could have a customer that puts distributed solar and does all the energy efficiency they can and everything else, we still will have to supply that customer on certain times, and we ultimately are going to need to recover more of our fixed revenue and not through sales.
Now, when in the achievement of all of our goals is that going to become a problem?
I don't know.
Is it going to be in 2025?
Is it today?
That's the policy decision that's difficult to pick on, is that you cannot move that way.
I will tell you that almost all operators of utilities, publicly owned ones like that, we would all like to have higher fixed charges because it does a lot to stabilize our revenue.
It does a lot to stabilize our revenue, but it is not popular with customers unless they're getting something for that fixed charge.
Hence our proposal.
>> Riley: sure.
And then there is a certain disincentive associated with a high fixed charge in terms of the individual customer's perspective and the motivation to pursue energy conserve aig.
I mean, if you're a very low energy-using customer, then having a $22 fixed charge will have some impact because what's --
>> unless you -- if you use less than 200-kilowatt hours a month I would agree.
on the electric delivery charge, are there other utilities in texas that are doing that, the --
>> electric co-ops do it, and, you know -- I'll be real candid about it.
I had a utility that i managed in washington and we had a $25 a month charge, and the reason that we did it is for this and for -- the political will of the board at that utility saw the need because of our -- because of our swings in revenue.
Electric cooperatives are governed by board of trustees and they have fixed system cost, they have have outages really bad so it's the same idea.
It's not a rural urban issue.
It's really more of a fairness issue and it really is a big policy issue, and i think that every -- every decision maker about that policy with the utilities has a struggle with it, about what that right balance is.
I will say that there are some utility rate designs going on out there, if we all remember cell phones, we used to pay by the minute, and I don't know how many minutes I use now.
I have a flat fee.
And so there's some of that logic moving through the industry, and I'm not up to speed on it, but I know that's been discussed by lots of folks, is to try to disconnect any down side for utility to not want to promote energy efficiency, to not want to reduce the energy a customer uses in their home while at the same time keeping the level of reliability there for when their dg or their car isn't running -- their house, or energy efficiency hasn't done enough, there will still be that interconnection need to the utility.
So that's the business set.
council member tovo?
I wanted to talk about the fixed charges and get back to the issue of line extension fees for a just a minute.
It sounds like from our previous discussion that it's been quite a while since those were assessed fully enough to know how well austin energy is recovering its costs of customers especially since my guess would be some of that growth has been in outlying areas where there may not be lots of existing infrastructure.
Is that -- is that about right?
Is that where some of the new growth is?
>> There's two kinds of infrastructure.
The urban, large load infrastructure, like our downtown network, and that is very expensive to work on, and that's a really high cost, wros out in the suburb area developers do subdivisions and then what we do is come in and pull the wire in and make it up and inspect it.
So we're not doing the dirt work and the infrastructure work in large subdivisions.
We do the wire part and the transformers and hook it up, so that's a big change.
My understanding is at some POINT IN THE 1990s, AUSTIN Energy changed its policies to not require fees to hook new customers up.
For the most part, when you come here with a new business and hook up to our system you're not paying anything.
That's all integrated into the cost that all customers pay.
I don't know the history about why we got away from that, but that's -- that's where it came from.
well, I'm glad that we're going to look at it because I think as we've all talked about before, I think we want to be sure that especially to the extent that it's in this rate proposal, that existing customers are not paying for that and subsidizing that future growth, but if -- if our line extension policies are such that we are underrecovering those costs, would that be reflected in the cost of -- in these fixed charges?
I mean, that has to be reciewpped somehow and -- recouped somehow -- I'm asking you to speculate that those cost of service charges are higher than they would be if we were actually recovering our cost of serving new customers adequately.
>> The capital revenue -- or the amount of money that we put into capital every year would be affected.
That would be rolfe, it's called contribution in aided construction and that would be funded by customers, so there would be a line item on our income statement that would have reimbursements by customers to the capital program.
So, for example, if -- if -- I'm just making up some numbers because we don't know what they are.
But let's say that out of our 100 million dollar cash capital that we put -- 25 million goes into the support of the system and now we're recovering 75% of that, so let's say there's $17 million was coming back in the form of revenue from customers to do that.
That has nothing to do with the minimum charge up there.
That would be outside of that.
What it would really drive is our capital program.
So right now what we're doing is in austin energy's budget we forecast customer growth and we're spending cash, and in some cases debt for like a substation when we have that kind of growth, but when we have wires growth to new customers we pay for that out of our capital program right now.
so the capital program costs are not reflected in the fixed charges, the fixed customer charge or the fixed electric delivery charge?
I would have thought it was in that second.
>> Well, it's all in there, all revenues in and all costs are in there, and they're not discretely assigned to one versus the other, I guess is the way i would answer that.
Otherwise -- I get in trouble with ann if I go too far into the accounting world here.
well, it would seem that if we're underrecovering our cost, that probably that contributes to higher fixed costs to our existing customers, but --
>> you could do it that way.
I mean, the reality of it is that there's a piece of revenue and there's a variety of different places we receive -- or excuse me, there's a cost to operate and there's a variety of different places we receive revenue.
Customer growth is one of those areas where you normally receive some revenue from the customers that hook up to your system.
However, it is very established public policy by public utilities that want to encourage growth and want to have low costs associated with new growth to its system for obvious reasons of growing its utility.
So it's really a big policy.
And I haven't dug too deep, but I'm real curious as to what might have happened back in the '90s to change that, because obviously it changed, I'm presuming even with the council and the city manager at the time and how -- how we're going to proceed with that.
So -- yeah, thank you, i think that is interesting and I see paul robbins raising his hand so it sounds like he has some information.
I was going to suggest -- i don't know if that's where my colleagues want to go but I think that's an avenue to explore as we delve into line extension fees.
And I do want to just say, you know, I have very strong concerns -- I'll just say this to my colleagues, those of you who are still here, you know, I have strong concerns about the high fixed charges and I think we ought to work to figure out some other alternatives.
>> Cole: I agree with that.
I'll just say that as a policy matter I would land on this, that new customers would pay equally to other customers and that they wouldn't get a discount but they wouldn't necessarily be charged a whole lot more.
But for sure, that the burden of the utility, the cost burden, would be spread evenly, whether that's reflected in the capital account or fixed charges, just as a policy matter.
But I also understand, and you can help me with this, i think there's some timing problem in figuring out what that cost is.
Is that right?
>> For line extensions?
Is that what you're talking about?
>> Well, I'm saying that i move to town and I buy a house and you're going to have to provide me and the rate that you're going to charge me, the timing of when you're able -- and you have to do a line extension and a connect fee.
Am I paying that amount right up front?
>> If your existing home -- if you come in as a customer to an existing home, you just pay a connect service, which is a customer charge and you just connect to the system.
But if you come to town and you want to build a new home --
>> cole: yeah, okay.
Then there is -- normally the person -- the builder contacts the utility, they go out and they negotiate or work with the cost to connect to the system.
Different line extension fees exist for different utilities, there are lots of different ways and the philosophy is there's a system impact fee.
You probably heard of this even with residential home development in cities where they might have -- you -- your building permit might cost you a lot because it has a cool impact fee and -- a school impact fee and other fees.
I've never worked with utilities but what we try to do is recover pretty close to the soss associated with our personnel and -- costs associated with our personnel and with our equipment that we roll to hook you up as a new customer.
That wouldn't be part of this new customer charge.
That's a completely separate transaction.
You write us a check for x amount of dollars, we build the service to you ever home and you're another happy customer.
so when we talk about trying to have growth pay for itself and a part of this customer charge, what exactly are we referring to?
>> Those are two different things.
>> Cole: okay.
>> This customer charge has to do with ongoing existing customers, telephones, services, things like that.
The line extension comes in the form of a reimbursement from customers to hook them up to the system.
It's a separate transaction.
However, it does come in as a revenue that offsets your capital cost associated with system growth.
>> Cole: okay.
Council member riley?
we're not going to have a session tomorrow.
I would like to hear from chernick with with respect to the rate structure.
He provided a memo.
on the last topic, this issue of having to do a study for the line extension fees and all, when I brought that up to you six months ago you said, yeah, we're going to do that study.
Have we started in it?
What's the timeline.
>> The timeline is probably -- I'm guessing probably this winter, you know, we'll be ready to do that, and then we'll explore what it is.
And it's going to take some guidelines on my part as to how we want to analyze that, but our electric service division and the engineers and so forth were all doing that.
It will also come with a cost, because we don't have the field people and the accounting system to do all of that as well.
So that's another part of the analysis has to be done, is to have a system to do that.
So -- okay, but what I understand is the bottom line is if we were -- if we were gathering line extension fees, that would allow us to decrease the overall revenue requirement, which in turn would decrease the rate increases and how you divide up those rate increases is what we're talking about now.
But overall we would have --
>> right -- -- less of a demand for a rate increase --
>> here's what it would do, in real terms.
It would affect our capital forecast of the future, and it would be -- it would be dependent upon the growth that we forecast as well.
So if we had no growth you would have no revenue from it.
But if you had a lot you would have more.
So -- and, you know, we could have the opportunity -- if the revenue requirement went down, we could potentially decrease the fixed fee or other fees.
And so -- that's where it gets into it.
>> I'd have to sit down, too, with the city manager to assess this, but i believe it would be part of our budget process.
The line extension fees are fees, and a different kind of policy outside the rates.
hear from mr. chernick?
>> Where would you like me to start?
On this last point, you may want to distinguish between charging higher fees to new customers simply because they're new, and of course the equipment you're putting in for them is new and it hasn't been dpreshtd and it was -- depreciated and it's purchased in $2,012 instead of $1,995, so that's sort of one way of looking at what you want to bill for, and some utilities do that.
But the other approach is, well, everybody who comes on to the system is entitled to something, and if they happen to be new, well, that's the breaks.
They'll be an old customer at some point and somebody else will be new or some old equipment will wear out and have to be replaced.
So in that perspective what you do is you just look at the particularly expensive extensions, and if somebody wants to be added at the end of the street and it means one more pole, maybe, then you might say, well, that's sort of within the average of what we spend per customer, but if there are several -- they're several pole spans down the road and you're going to have to add a pole and you have to add a transformer just for them and several other things, then they're particularly expensive and maybe they should pay for that.
And there are a lot of sort of questions about what -- what fairness means -- and is that a policy decision that we would need to make?
This is not something that falls from the sky.
I mean, certainly the policy guidance has to come from you in terms of what the dollars are or what the -- the cutoff is.
You could come up with a rule of, gee, if you're -- if you don't take more than one pole to extend the service to you, that should be covered.
That seems like you're just part of the system.
But if it's more than that, then you're asking for an extension.
If that sort of thing strikes you as meeting your standard of fairness, then that would -- that would be a perfectly reasonable kind of direction to give to the utility, which can then work out the specific rules.
In terms of sort of the more core rate sign issues, weis said that this is not a rural-urban issue in terms of practice.
I think it really is, that the rural co-ops do charge, many of them, high customer charges, such as the very large charge that austin energy has proposed, but if you look at the texas investor-owned utilities, they're charging 3 to $6.
The retail electric suppliers, many of them don't flow that through as a customer charge but roll it into the energy charge.
Municipal utilities generally do not charge the 20, $25 customer charges that the rural electrics do, and that makes sense because if you're talking about a rural electric your next customer may be a couple miles down the road and each customer has likely acquired their own transformers.
There aren't a lot of economies of scale for a lot of your customers, and so it makes sense that you think of each -- each additional customer is a commitment of a lot of capital and not just the -- the meter and reading it.
And for that matter, traditionally for rural electrics reading the meter has been a significant expense.
So -- so getting that clear, these proposed customer charges, fixed charges, is a total of $23, including the dollar for customer assistance.
That's really an extreme number for a nonrural utility.
And it is a zero-sum gain and you're going to collect your revenues, so the more you put in the customer charge, the less you have to charge for energy, the less you put in the customer charge the more you charge for energy, and I believe strongly that charging for energy is a good thing, especially given your policy direction, that you want to encourage conservation and people are more likely to conserve if they save more when they conserve, and the way to achieve that is to put the charges into the variable charges that they can control.
There's also a real equity problem.
Smaller customers tend to be lower income customers.
And the more you put into the customer charge, the more you're hitting them.
So it's not like you can get rid of the assistance program if you -- if you lower the customer charge, but it just makes the problem worse.
And there is a benefit to the utility, revenue stability, from having large customer charges, large fixed charges, but there is a real trade-off there between the efficiency of the system and the efficiency of the signals you're giving to customers, and the -- and the utility's revenue stability.
weis pointed out your revenue stability would be great if you just said each residential customer pays us $500 a month, period.
Doesn't matter how much you use, but that would give horrible both psychological and economic signals in terms of energy conservation.
And part of austin energy's concern about the size of the customer charge and revenue stability seems to be based on the concern that customers will install solar systems on the rooftops and basically stop using energy, or they'll use it sometimes but they'll -- they'll feedback as much as other times and have a zero net bill.
It's my understanding that the utility is planning to move, as soon as this rate c is over, to the -- and I don't know why they're waiting on that other than maybe they're kind of busy right now -- move from a system where your billed kilowatt hours are reduced by the electricity your solar system produces, to one where you buy all your power from -- from austin energy so there's no lost revenues, and then you get a credit on your bill which is paid for through the fuel charge.
So there's no lost revenue on that side either.
And the company is completely made whole.
So I think given that there's a solution on the solar side and energy efficiency is not going to get people down to zero electricity use or close to it even, although it can get them down a lot lower than they are now, I don't see that the -- the need for a very large fixed charge is as pressing as the utility has suggested.
One other thing that I just wanted to mention is in terms of moving customers on to demand rates, the company has proposed moving -- and then has sort of backed off of that -- moving some churches on to -- and a large chunk of small commercial load on to a demand rate.
All the commercial customers between 10 and 20 kilowatts are now on an energy only rate, which tells them to conserve.
They would be moved on to a demand rate which tells them, try and guess when your maximum demand is going to occur and try to figure out when to reduce that, even if that means increasing your loads at high cost times, even if it's increasing your loads on the system peak, reduce your maximum load whenever it would occur.
So if you've got multiple machines, run them at different times.
We don't care when you run them.
You can run them on peak.
We're not going to give you any time of use signals, but just don't run them all at the same time.
And that's a silly incentive to be giving people.
The utility has spent a lot of money on smart meters.
They spent a lot of money -- or they're about to spend a lot of money on a data system so they can actually use the data that comes from the smart meters.
That will allow them time of use rates, various times of responsive rates.
Once that system is up and running, then I think they should come to you with a set of rate designs for -- starting with the larger customers that reflect how costs are actually incurred, and demand charges thou shrink away to reflect just the customer-related -- customer-dedicated equipment, the size of the transformer on a commercial customer, for example, and anything upstream from that really ought to be on time of use energy.
I think that's all I really wanted to say in response to this morning.
You've got some other notes for me.
If anybody has questions -- council member riley?
Did you have questions?
so that, chernick, you mentioned that that proposed fixed charge would put us on the extreme of -- at least for urban utilities.
Are there other urban utilities that you know of that have a fixed charge that high?
>> I haven't tried to -- to do a nationwide survey, and there are so many, especially when you get into municipals, but there are probably some, but it's -- it would be a very small percent.
When I say extreme, it's not necessarily the highest in the country, but it would be in the top, you know, 10%, 5%, and three, four, five times what some other utilities are charging.
you mentioned that the down side from the individual customer's perspective in terms of the incentives for conservation, but you could see some value from the utility's perspective in terms of eliminating an incentive for the utility to increase its output, but throughput incentive, it's sometimes called.
>> Yes, and they're changing the utility culture is important concern.
If austin energy management is really having a hard time getting their staff to do what they're told to do, then maybe some of that staff needs to be replaced with people who actually believe in what the council wants and are not fixated on selling energy.
Why they would be fixated on selling energy, unless they're -- they're getting bonuses based on that i don't understand, but austin energy should be able to say, this is what we're going to do, and if, under some circumstances, we need to file for a rate increase, we'll file for a rate increase, and that can happen for a lot of reasons.
Energy efficiency would be one of them but certainly not the only one.
And there are other mechanisms that -- that i discuss in my paper that jim lazar has talked to you about.
There's really full decoupling and then there are various mechanisms that give the utility some assurance that if it does a lot of efficiency and has a financial problem as a result, that there will be a mechanism there to take care of them.
And it's much better to deal with it that way rather than to take away the customer's efficiency incentive and then to get the utility -- put the utility in a position of getting customers who are demote vaited to conserve.
Demote vaited to concern.
It's much better to do it together.
I don't want austin energy to have economy problems but I think there's better ways to do that than a $23 fixed charge.
>> You would shift that to the energy rates.
>> I would put that in the energy rates, yes.
>> Council member morrison?
I guess first i just want to comment that i think that what we're trying to do is set up a framework and a system, a business system here that encourages us to achieve our goals.
I don't really think it's an issue of staff here.
We have very dedicated --
>> then maybe it's no problem.
well, the challenge we have is setting the framework within the business model to achieve our goal and I think that's what we're all trying to do here.
I do want to mention a couple things.
One, in terms of stability i think we need to keep in mind, and I think you've mentioned this, that our reserves are another mechanism for helping to maintain stability.
If we have the reserves, and the issue of stability on a year to year basis should not be as big of an issue.
Would you agree with that?
>> That's correct.
One reason to have a very small customer charge and to have a rate stabilization fund is just what you hit on, is that you have the stability mechanism in place, and that's really what it comes down to.
So that you don't come down to do rate increases very often.
That's the idea.
but in our proposal we have a large stabilization rate fund and a large fixed knee.
Now, grant -- fee.
Granted we don't have the stabilization fund at this point, but if we had a large rate stabilization fund, the period that you wouldn't -- you don't need as many other mechanisms for finding stability.
You can achieve it a couple ways.
You know, to have a fully flexible and operating rate stabilization fund, needs to be a pretty good size for austin energy to really have a tool that really works, so it would take us a number of years to get that.
The other characteristic that's unique here too is the shape of our residential customer base.
Austin energy has a real high proportion amount of small to medium users of energy too, so it's -- so it's really a revenue stability issue from that standpoint too.
But -- anyway.
the other question -- or thing i thought we have to discuss -- we're about to lose ou quorum, council member morrison, so do you want to go ahead and ask your question but -- maybe we'll have to have the answer later, but I think that given that these high fixed fees would be outside the norm for our kind of utility, we need to think about what the puc regard for them would be also, because they could also be a high-risk item there.
>> Right, and I just want to emphasize again, I think this is my third time today, is that there's 200-kilowatt hours in that fixed charge too.
So that's a different way of looking at that number as well.
thank you, austin energy, and mr. chernick.
We appreciate you coming.
We'll try to get with you with our other questions.
This meeting of the austin city council austin energy work session is without