mayor's office, we've been working with our commission, and we've been around taking to a lot of the supervisors about the challenges that we face and what the impacts would be. and, so, we met with supervisor avalos and he thought it was a great idea that we come and present here today about what our challenges are as it relates to the financial health of our power enterprise, and really illustrate how important it is to the city, and has been for decades. and, so, we just wanted to make sure that people are aware and informed about the power enterprise at hetch hetchy system. and, so, i would like to also, after the presentation, we can definitely talk about how it relates to cleanpowersf and have a very robust conversation about that. so, with that i would like to turn it over to barbara hale to

go over the presentation. >> thank you. barbara hale, a sis tent january manager for power. good afternoon. ~ assistant general manager as the general manager said, i'm going to go over the hetchy system and the benefits that have accrued to the city as a result of it. our customer base and costs, challenges and consequences we're currently facing, and the options we have in front of us for addressing those challenges, as well as what that means, the overall picture means for cleanpowersf as we see it. skew me. so, clerk, i'm going to switch to the other microphone and the overhead. the powerpoint just disappeared.

so, from these slides i should be able to go through fairly quickly. it's familiar for many of you. the hetch hetchy system, we're very fortunate to have. it's a system constructed in national park and in national forest lands that allows us to store and convey our water for drinking water here in san francisco and much of the bay area, but it's also very key in providing us with the majority of the kilowatt hours we have in greenhouse gas regeneration. specifically, we have 380.5 megawatts of power up in the mountains. we augment that with our in-city generation from solar, small hydro, and biogas facilities here in san francisco, the biogas coming

from the methane generated from san francisco's wastewater system. we've had the wonderful opportunity to have most of the system costs paid down. the kilowatt hours from the hetch hetchy system are quite cheap relative to the market today. and we've been able and willing to share those benefits with san francisco over the many decades of its operation. and what you see before you here is a quick listing of those benefits. 677 million just in transfers between 1978 and -- excuse me, 1979 and 2001. and then, of course, being able to charge the general fund less than it costs us to actually generate and deliver the electricity, we're saving the general fund $50 million a year on their electric bills

relative to what pg&e would charge them were we not in existence. and then many other benefits from in-city solar, energy efficiency, street lights, just the work force, and operations of the hetchy power enterprise, really bringing lots of benefits to san francisco. >> ms. hale, could you say -- it says here the first bullet after the hetch hetchy system also provides 100% clean power to nongeneral fund customers at pg&e rates or less. could you give an example? >> yes, for example, the san francisco airport, the ferry building, these are facilities that we serve. they are not on the general fund side of the city's budget ledger. they are our customers. so, tenants within city facilities like the ferry building, the airport. >> very good, thank you. >> you're welcome.

and, of course, some of the largest consumers on the nongeneral fund side are puc utility, water and wastewater services. and, so, what we're showing with this slide is just an outline on the left of the revenue sources. and on the right the costs. so, this shows you in order to get those benefits, you know, we incur certain costs and we charge for them and receive a revenue stream as a result of that. so, this is fiscal 2013-14, the year we're in right now, where you can see that our operating and capital needs total $149 million. you can see that most of the revenue comes from those customers that you just asked me to highlight, commissioner avalos, our retail enterprise customers.

you can see also that we are, in order to balance, we are dipping into our reserves and that's this light blue bar here. you can see we're reaching into our bank account in order to meet our operating and capital needs. >> and the bank account is the fund balance, is that what you're referring to? this 43.2 million, the reserve is the balance? >> that's the -- that's what remains in the bank account, yes, the balance. so, breaking down where the money comes from, where the revenue comes from, you can see on this slide our current customer base. you can see on the left the megawatt hours that are generated by our system. and on the right, the dollars, what those megawatt hours are converted into. and i think it's important to

note here that 41% of our customer base creates 69% of our revenues. and you can see also that those customers are paying around 14 cents a kilowatt hour for on average for that power. our general fund customers use just a little less than that in terms of the megawatt hours, but they provide substantially less in term of revenue to fund our operations. and then when we have -- when we have power in excess of our customer needs, we have the opportunity to sell that power on the wholesale market. we're also obligated under the raker act that allowed us to build the system on public lands to provide power to modesto and turlock irrigation district. that's what you see in that red

bar. so, we're obligated to provide that power to them to the extent we have it available, up to their municipal and agricultural pumping demands. and we must under the raker act sell it to them at our cost. so, we're not allowed to make money off of them because they had superior water rights on the tuolumne when we built the system. >> does that fluctuate year to year what we provide to modesto and turlock? >> yes, it is based purely on regeneration. but once we meet our own needs, if we have generation in excess of that, we are required to call them up every day and say, do you want power? and if they say yes, we give it to them -- we sell it to them if it's available up to their municipal and agricultural pumping loads. and we have more beyond that, we can sell it in the open market for whatever the price is that day. >> so, has that changed, what we see year to year, is it dramatic or is it pretty

relatively flat? >> it's very water dependent. it depends on the water system. it depends on what's going on with maintenance of the system. >> and then could you give examples of who some of the main wholesale customers are? >> so, over the years we've sold to various raker act eligible wholesale customers. raker act eligible means there are other public utilities. so, for example, most recently we sold to the california department of water, the folks who pumped water through the aqueduct system here in california. so, we're selling to the state of california. they're nonprofit, they're eligible. we've sold also to other publicly owned utilities, but really cbwr has been a pretty steady counterparter of ours in recent years. for example, palo alto,

alameda, the northern california power authority, these are eligible entities that we can do business with. >> thank you. >> and, so, just to drive home the idea here behind our customer base and where we receive our -- the lion's share of our funding, this slide shows on the left that same set of retail general fund customers. but instead of showing it in the megawatt hour or revenue picture, this is showing it based on the rates that they're charged. so, you can see that the general fund is charged 4.75 cents a kilowatt hour right now typically, there are some that are charged less, but generally speaking it's 4.75 cents a kilowatt hour. you can see our enterprise department customers are charged on average around 14 cents. then you see the black line on the bottom, shows the

transmission and distribution costs that were charged by pg&e that we pay today at 1.8 cents a kilowatt hour. that's one of the cost element that builds our cost profile. when you add all of our cost profile elements up, it's around an average cost of about 10 cents. so, you can see that top black line shows that when we're selling to a retail enterprise department customer, we have some contribution above our costs. on this slide it's estimated at about 4 cents a kilowatt hour. when we're selling to a general fund department customer, we're selling well below our cost. we are expecting that transmission and distribution cost element to increase. we have been forecasting increases in our budget planning for a number of years now because we are seeing the end of our long-term agreement we had with pg&e for

distribution and transmission services. that agreement is referred to as the interconnection agreement or commonly it's referred to the ia from 1978, expires in july of 2015. with that expiration, we expect to see our transmission and distribution rate rise to the red line, the red dash line you see here at about 3.4 cents a kilowatt hour. we are in ongoing conversations, ongoing litigation, regulatory proceedings that influence what that number ultimately will be, but that is the number that's currently in effect. so, if we were to roll off of our interconnection agreement today, we would jump from a 1.8 cent a kilowatt hour transmission distribution cost to a 3.4. i'm highlighting this because it's one of the costs that, although we were anticipating a change, it's coming in higher than we had anticipated. and, so, that's one of the factors that's a challenge as we look forward on our financial plan. >> you said that this rate,

3.4, that will be in july 2015 is in effect? does that mean there are plans in place that's what it would fall back to regardless of negotiation -- if negotiations aren't settled? >> no, what i am referring to is the transmission rates that are charged on pg&e's system are set by the california independent system operator and ferc. those rates are known today and it's a postage stamp rate that anyone would pay. so, we know that. we are exempt from paying those rates right now because we have this special agreement with pg&e. but we know when that agreement rolls off, we could be subject to that same rate that everybody else is being charged. so, that's actually effective today. with respect to the distribution component -- >> hang on just a second. i'm sorry. we wouldn't expect it to be higher because we wouldn't pay a rate higher than the independent operator says we should. >> right, [speaker not

understood], right now we're estimating that to be -- component of it to be in this add up that gets to 3.4 -- >> could it be less? could we expect we would be able to negotiate something that is, you know, comparable to what we've already been paying so we wouldn't go up to 3.4? >> so, we're not, we're not giving up on that effort. [multiple voices] >> there is a rate setting process that would -- that indicates what the rate is that's paid by most people. we've had a special arrangement historically. yes, we would like to try to continue to have a special arrangement and we're working with pg&e to try to get there. it's the subject of negotiation. >> and a are there regulatory factors that would influence our hand? ~ to be stronger? >> so, can i jump in? so, one of the things that we're trying to identify, one

of the challenges, and some of the challenges are time sensitive and this is one because we know in 2015 it expire. so, we're meeting with our commissioner, with the mayor's office, with the city attorney. we have a working task force to really dive in to see how we can minimize this impact. so, we've been actively pursuing this and it's like all hands on deck. so, this is only one element, but we have -- looking at each one of those com poets, we have a team of folks trying to address it. ~ components >> thank you. >> and, so, that's with respect to the transmission component. the distribution component similarly, it's in a contract now. you asked, commissioner, whether it was in effect. pg&e has gone to their regulator on distribution rates, the federal energy regulatory commission, and asked for a rate increase relative to what they charge other of their distribution

customers. >> is that what pg&e does very often, ask for a rate increase? i'm just joking. [laughter] >> thank you. the process at the federal energy regulatory commission for a distribution rate like this is to allow it to go into effect subject to refund. so, if we weren't protected from the standard rate that pg&e charges others, this is the rate we would be charged today. as i say, it's subject to refund. we're actively participating together with city attorney in the case at ferc, trying to make sure that we pay our fair share and no more for distribution services. >> so, we have full support in that. >> the other thing i wanted to illustrate is that most of our customers in the retail side, we charge equivalent to pg&e.

and, so, with the transmission and distribution, they're not raising -- the pg&e doesn't typically raise their rate, per se. they're just raising their rate for transmitting our power through their system and distributing it. so, really, it eats into the margin. and, so, instead of paying them 1.2, we're paying 3.4 and we're still charging the same amount. and, so, that's the challenge. >> so, prior to some of these challenges coming into effect, we had a balanced plan. if you pretend you're in february of 2013, the last time we presented a balanced financial plan, fiscal year-end '16 would look like the slide you see in front of you now, where our operating costs would have increased. our capital program would still be quite robust.

and we would not be dipping into reserves, but rather, we would be enjoying the proceeds of a debt financing to pay for a share of our capital improvements. so, that was the plan for hetchy power after our last correction -- corrective action to bring our plan back into balance. >> could you briefly describe what was the financing, what it looked like? >> so, you can see the financing proceeds here. our plan was to go out to our rating agencies with the first-ever hetchy power plan of finance, get a rating, and be out in the market just like the wastewater and water enterprises are funding their capital programs through debt financing. >> we've never done that before? >> no. >> so, [speaker not understood]

2003, is that correct? >> the voters gave the go ahead ~ for spending up to 100 million in revenue bonds. we have -- we have done some modest revenue bond financing. and by modest, i mean we took advantage of some of the federally sponsored programs. we didn't have our own independent credit rating and a plan of finance behind that. and it's very modest in comparison to what we were proposing to do under this plan. even this plan is quite modest compared to water and wastewater are doing at the puc. it shifts us into that more standard utility practice of having a credit rating and borrowing to fund the long-lived assets we rely on to provide service. >> just trying to figure out why we've never done this before. so, there was some change in

that allowed us to do it or the puc didn't have that before ~? >> i think it was a combination of factors. one being we had a fairly robust fund balance which made it so you could just cash fund stuff. and now as we've eaten into that cash fund balance and as we've seen the cost of doing business increase, that we find we can't enjoy that luxury. so, the plan was to go out into the market and use bond proceeds to fund much of our capital programs. but as the general manager alluded to, we're fag challenges that weren't anticipated when we put that financial plan together. specifically, we're seeing

essential capital improvements that we hadn't anticipated. that balanced plan that i just showed you a picture of assumed we were going to spend about $545 million in capital improvements over the 10-year plan. we're expecting now to see an increase of 883 million in that 10-year plan. that is largely due to one asset, frankly. we have a tunnel that conveys water from o'shaughnessy dam to our power houses in moccasin. that tunnel is showing signs of deterioration and signs of a major rebuild being necessary to the tune of about $650 million is the estimated cost at this point. so, as i said, that's the largest component of that expected increase. we're also seeing the increases

in the pg&e transmission and distribution costs that we just talked about. it's about 16 million a year for the increases for those two cost components. and our current interconnection agreement with them also includes a banking feature that we expect to lose which will cost us on net about 2 million or over 4 million, yes. >> commissioner breed. >> thank you. i wanted to go back to the tunnel. it's my understanding that before the bond was introduced that the bond was introduced for puc, i forget what year that was, but that the department was aware of the issues with the particular tunnel, but it wasn't included as part of the bond. so, i just wanted to find out if that were actually the case. >> yeah, it actually predates me, but i heard the same thing

so i inquired. as i understand it, unless you'd like to -- >> no, you can go ahead and then i'll add. >> clean up, thank you. the tunnel, you know, the efforts that we went through with the water system improvement program were reliability focused, seismic -- seismically focused. the problems with the tunnel are not seismically -- it's not related to seismic issues. it's just age. so, it was not included in the water system improvement program because of the difference in scope of the effort. >> the other issue, when we formalized the water system improvement program, is that we really focus on seismic and, so, we looked at facilities that were close by the seismic faults. however, we knew there were some issues with mountain tunnel, so, we have it in the 10-year plan and it's a joint asset, which it's jointly owned by water and power.

and, so, we have in our 10-year capital plan about $100 million to go in and reline it. and, so, that was the original plan. and then while going in there, doing more investigation, we had an engineer look at what the impacts would be. and given the fact that it could collapse, we are now very concerned that not only we wouldn't be able to produce power, but it would shut off the water supply to san francisco. and, so, when we developed the we step, it was about seismic reliability. and we knew it was an issue with the lining, but we didn't know the magnitude. and, so, we did put the 100 million in our 10 year plan to address it, but we didn't anticipate this much. so, the other thing i wanted to also identify, there are other projects that we've put in the program and they increased in size, like cal var ~ calaveras, for example. we want to let you know once

you get involved and start seeing more, some of the scope increases. >> i guess i was just really concerned that since this particular tunnel provides, i guess, over 80% of the water to the bay area and san francisco, this kind of concern probably should have been discovered and addressed many years ago. so, i guess i'm just -- now, you know, a significant cost. now it's something of an emergency. now the possibility of it impacting, you know, how we can move forward even with our clean power program and other things just really disturbs me. >> well, let me just point out the water system improvement program we started in 2002, $4.6 billion, we recently invested in that. and i tell you, those projects to me were very important because they're right by seismic faults. and, so, you have to

prioritize. the system is over 100 years old. so, we know we need to reinvest in there. we can identify 7, $8 billion we need to invest in there so we need to prioritize. so, we did the best prioritization at the time with the information we knew. we came up with a program with $4.6 billion to address that. so, yes, you can look at the system and there may be other parts that are getting old that we haven't really evaluated. the other thing, keep in mind is that you just can't shut down the system and expect the whole system. you have to deliver water most of the year. and, so, it's very rare that we can actually go in these tunnels. for example, irving ton, we haven't shut that tunnel down forever and, so, we, you know, are now able to -- we punched a hole through and we're probably going to bring that online so that we can have a chance and look at irving ton tunnel. we haven't even looked at it, but we knew it was very vulnerable. so, yes, we probably should

have looked at it, but just like all the rest of the infrastructure, we just started in 2002 to start addressing these issues. >> and, so, when are we -- are we pro proposing potentially another bond measure to assist us in these efforts or what's the plan? ~ >> so, the plan is we're going to look at what are the alternatives. so, right now we're looking at maybe doing a bypass tunnel and that's where the $650 million -- but we're looking at other alternatives to try to reduce the cost. our wholesale customers, water customers are very concerned because you can buy power. you just can't buy that amount of water. and, so, they are very concerned. they're asking us questions about it. and, so, this is one of our top priorities, this mountain tunnel. >> thank you. >> i think commissioner breed's question, though, was around financing. what were you looking at to finance that $6 45 million? >> so, what we wanted to do is

currently the asset is ~ a joint asset. 55% is on the power side, 45% is on the water side. and, so, we are looking at how we can finance it given the fact that power enterprise has a financial problem. and, so, this is one of the thing that we are working with staff and working internally to first see if we can reduce the cost, look at other alternatives to look at ways that we can assist in financing this so it won't have a major impact on the water side. >> so, why is it that power is 55% water, 45%? it seems like the revenue that's generated from the water side ~ would be much greater than the revenue generated from the power side. i imagine it's like night and day the difference between the two. our water from hetch hetchy come right through the mountain

tunnel, right, it doesn't have any other place it goes so it's -- all the water in our system goes through there. seem like that would be the larger bulk of what would be paying for the cost of the mountain tunnel, the water. >> so, it's an agreement that happened in 1985. >> the water sales agreement? >> well, where they identify the proportion cost of these assets, 185. what was the rationale? >> you know, we are continuing to research the rationale. i don't have a good answer for that question. >> i would love to hear that rationale. it doesn't make much sense to me, and if there's a way that we can have a new rationale, that would be great. >> and we're looking at that as well because -- but we have to work with our wholesale customers because, of course, they want to make sure they pay their fair share and their definition of fair. and, so, we're starting to have those conversations.

>> do you have a sense of when you'll be able to finish those conversations? >> we're moving swiftly on all fronts and this is one of the biggest issues that we're facing. not only on the power side, but on the water side. >> so, then, the final challenge is the cost we are incurring to meet new regulatory requirements. the western electric coordinating council, the national electric reliability council implements reliability standards nationwide and within the west. they are an arm of the federal regulatory energy commission and they've gotten much more diligent and involved in how utilities, electric utilities operate their system. electric utility system are interconnected and a problem on one entity system can cascade into another's.