Snohomish PUD chief answers that and other questions
Herald writer Kathy Day talked extensively last week with Paul Elias, general manager of the Snohomish County PUD, about the crisis that prompted the district to raise electricity rates 33 percent for residential customers and more for commercial and industrial users.
Here are some of his answers:
Q How did we get into this situation?
A We had anticipated a rate hike in the next year and had planned to use our rate stabilization fund to offset the impact of the increase that we were looking at over the next few years, probably 4, 5 and 3 percent for three years. What happened was that the run-up in wholesale power costs in November and December consumed pretty much all of that money, so we don’t have that buffer to put into the rate increase next year.
All of the circumstances came together in "The Perfect Storm" analogy. At this time of year, we’re usually getting a lot of generation from California, and California is not providing that. I think they have about 33,000 megawatt hours of generation, and about 11,000 is off for maintenance or air quality (reasons). The point is that they just don’t have the generation to send us. …(Secretary of Energy Bill) Richardson ordered power sent to California, and people should see that as a very big problem. We have low rainfall so far, so the facilities we depend on for generating power, like our Jackson plant, aren’t producing as much. Fundamentally, the supply is very thin, so especially with the run-up and at a time when demand is high, I think there’s a certain amount of hysteria in the prices.
We find ourselves counting on prices in our rate proposals, but they’re not going to come down so far as they were before. They will be higher, but as part of our current rate strategy, we’re counting on them coming down.
Q Who’s to blame? Is it deregulation?
A I guess it’s because the wholesale market is in disarray. You have to point to what’s going on in California, how that’s really distorted the market.
One of my big concerns is that before deregulation, utilities always had an obligation to serve. While they tried to help adjust or improve economics, sometimes they had to do uneconomic things. …You have to buy that last megawatt hour; you always had to do that no matter what the cost.
Prior to deregulation, particularly in California, utilities were vertically integrated. They had generation, transmission and distribution that were all coordinated. At the end, they always knew they’d have enough generation. Now they’ve broken the model up and California utilities have sold off about 50 percent of their generation — and, I hear, are planning to get rid of it all. They’ve sold to merchant generators who run their plants to make money, to optimize their shareholders’ investments. They don’t have an obligation to serve.
Q Is there a solution?
A We’ve written to James Hoecker, chairman of the Federal Energy Regulatory Commission, to President Clinton and to President-elect Bush, saying that wholesale rates should be cost-based. Those prices need to reflect the cost of producing the electricity.
We also need to consider adding generation as well as renewables and conservation.
Q Is deregulation dead?
A It’s working in some areas. In Pennsylvania, for example, they have a mechanism that controls a run-up in prices. It’s a more cooperative effort between the utilities and the generators. Nobody really wins when prices run up. We will see significant restrictions on the producers as a result of what’s happened.
Q Is deregulation on the horizon in Washington?
A I think it’s off the table. My guess is that they’ve looked at California and decided not to try it.
Q Is there any way to predict how long the current situation will last?
A (Laugh) No.
One of my concerns is we know we need resources. We know we’ve had to rerate Bonneville (Power Administration) for the (protection of the) fisheries, so we’ve lost some there. When we began to think we might have a supply problem in the past few weeks and began to prepare for that, one of my concerns, knowing that we need additional resources, was not to be to appear to be crying wolf.
The worst thing that could happen is that we’d get through the winter without big problems and everybody would say, "Well, we thought you had this big crisis." … We have to be careful about how we give the message about the need for creating new generation. It’s not a question of building somewhere else. We need it in Washington … we need it someplace in the greater Puget Sound area.
Q What are options for new sources in Washington? What’s viable?
A We’ll have some wind stuff that’s starting to come up that’s looking pretty economic. With the rise in prices on conventional generation, it’s starting to look better. As you get closer to their production costs, it gets more economic. It’s valuable and it’s a resource, but it only happens when the wind blows.
Generation of choice today is gas-fired, combined-cycle combustion turbines. With rising natural gas prices, what’ll happen is you manage your gas supply portfolio in some way. Does it isolate you from swings in the market? No, but it does isolate you from panic run-ups.
Q Are old sources new again?
A On solar and so forth, the changes are to the plus side as they get more economic. … Unless there’s some sort of technology we don’t know about, nuclear power is dead. … There’s money in the budget for next year to look at fuel cells and see how they are applicable to use, partly to understand them.
Q Has the Northwest been spoiled by low rates and become complacent?
A I guess my answer would be no, because we’ve had people conserve. We’ve had tremendous results from our conservation programs. … There is some economic incentive. Why would you conserve if you have low rates? … I don’t think people waste energy. I think they’re very respectful.
Q If people are already conserving, what can they do to lessen the impact of this rate hike?
A All of us, when we’re not watching, get a little lax about rules, which rooms we heat, turning off lights. I know I’ve started looking at the house again, saying, "We don’t really need to heat this room. We don’t use it very much." Be after the kids, turn off the lights, cut the long showers.
Q Where does the PUD buy its power and why does it have to buy outside of Bonneville Power Administration?
A: Currently, we buy about half from Bonneville and the other — about 40 percent — is under long-term contracts. We get our own generation from Jackson (hydroelectric plant) and some from Kimberly-Clark. We have some market exposure for buying energy. We try and close our future positions. We’re closed out for January; we’re covered at a reasonable price, compared to today’s rates.
The problem is how do you do longer-term planning on what historically you expected to have. As you get closer, you’re buying to close that position in any one month. You look at the weather and, typically, our risk management calls for us to be no more than 25 megawatts short and 50 megawatts long in the same month. So you get to that month, you’re in that month and you get a weather report like we did (two weeks ago) that it’s going to be abnormally cold, and that puts you out of what you had and into the market, and the market is spiking, so we found ourselves buying in that market. It could just turn the other way and be unseasonably warm. We’d have been long and selling. You’re talking 25 or 50 megawatts on 1,100 megawatts (average usage at this time of year).
If you’re selling now, you would sell at market rates. That’s it, fundamentally, up until November, particularly through the summer. We were selling; we were buying. Essentially, we were in balance.
Q: Where does the district buy power?
A: Avista, Portland General Electric – those are the two long-term contracts. We buy from Chelan or Grant PUDs, lots of people.
Q What can the district do to plan for the future?
A Short term, we can control our costs. We’ve done a good job. Our costs break down as two-thirds wholesale power and about one-third actual operating expenses. We’ve been driving operations down and for the next five years have plans to continue to drive that down. That takes some rate pressure away from customers. We also have to balance that with our liabilities and debts.
We need to be very good about watching the market. We’re going to get to (our new Bonneville contract) in October. That will afford some market protection, at least as we understand it today. … To get to Bonneville, the road’s going to be bumpy over the next nine months until we get there. When we get there, it will be less bumpy, more predictable.
Long term, it goes back to what the commission decided when they decided to go with Bonneville. … we are going to continue to have some exposure to the market. How do we best mitigate that? Do we enter into long-term contracts, hedges, whatever you want to call it? It will take the fluctuation out that we’re experiencing. We won’t be actively in the market, but we’ll still be there.
We need to continue to press conservation … look at building resources. There’s a lot of interest in building resources today. Perhaps we need to find a partner in some sort of resource development. We need to look at other alternatives, like possible additional transmission. Are there resources available in Canada or someplace like that? I don’t know, but we need to leave no stone unturned in looking out how to mitigate our exposure to the market.
Q Is there anything you would you like to say to customers?
A How do you tell the customers we’re trying to do a very good job here? As a public entity — they own it — the reason we’re more successful in terms of the market is that we don’t have any margins. Well, that’s not quite true, but it’s so close to being true … we do try and collect a little money to buffer rates and so we’re not deciding where the break’s going to be next month. At times, we have a little more money that’s collected and that’s turned back to customers. We act in their best interests.