Bonneville Power Administration (BPA)
Pacific Northwest Utilities Conference Committee (PNUCC)
Summary of June 18, 1998 Public MeetingDoubletree Hotel Spokane Valley, Spokane, Washington
The Bonneville Power Administration (BPA) and the Pacific Northwest Utilities Conference Committee (PNUCC) hosted a meeting to update members of the public on the subscription process and get comments on subscription and associated issues. About 25 people attended.
- Welcome and Overview
- Subscription Products
- Implementation and Pricing
- Outstanding Issues
Dick Adams, executive director of PNUCC, said the purpose of the meeting is to ascertain "what questions you need answers to before customers can engage in the subscription process." We also would like to find out "what do you need to know that you don't know now" and "what do you want to say that you don't think BPA has heard," he stated. Adams described the origin of the subscription process, and Carolyn Whitney of BPA explained how subscription fits in with the topics being discussed at BPA's Issues '98 meetings being conducted around the region. Charles Alton of BPA described how BPA intends to meet the requirements of the National Environmental Policy Act (NEPA) as it proceeds with subscription. He noted that BPA will tier the Records of Decision for subscription and its Business Plan, and he explained the public processes that will accompany the tiering process. Alton indicated that BPA is considering three options for "the tiered Records of Decision process" and hasn't decided which to use yet.
When does BPA issue a Record of Decision on subscription? asked Rob Walton of the Public Power Council (PPC). At the time we offer contracts, replied Alton. What's the latest on the schedule? asked Richard Heitman of Inland Power and Light. We are not announcing any schedule changes today, responded Syd Berwager of BPA. We've heard from customer groups and others that we ought to delay subscription, and today, we want to hear what you think about the schedule, he added. Adams noted that the power rate case is scheduled to begin September 1 and the transmission rate case is to be held in 2000.
Walton pointed out that several environmental groups have filed a notice of intent to sue BPA if it signs contracts for the 2001-2006 period that commit the output of the Lower Snake River dams because of the possibility those dams might be taken out and their power not available to BPA. If your question is, is this in the scope of BPA's Business Plan EIS, the answer is yes, responded Alton. This notice isn't on NEPA grounds -- it's on Endangered Species Act (ESA) grounds, Berwager noted. Yes, but I wouldn't be surprised if NEPA is next, stated Walton.
Kathy Hoffman went over the products the Subscription Work Group has been discussing. A subscription right, she explained, is the right to buy an amount of power at BPA's lowest cost-based rate for a defined period of time. We are talking about price, not supply, Hoffman stated. If a preference customer puts a load on us, we'll meet that load, she said. Subscription is a matter of buying at the lowest cost-based rate, Hoffman continued. The PF' rate is the lowest cost-based rate, and PF" is a higher rate, she noted.
Hoffman explained the product list contains core subscription products, customized subscription products, and non-subscription products. The three core subscription products (full service, firm power block, and partial service) would have posted rates, she said. Hoffman pointed out that the partial service product is still under development. Customers should know, she said, that "whatever you need, we can tailor a product to meet that need." If, for example, a customer wanted a four-year contract, which would have different flexibility from a five-year contract, we would negotiate it, Hoffman said. [We could give customer the opportunity to take the posted rate product for the first four years of the five-year period posted rate and zero in the fifth year. When additional flexibility is desired, such as shaping beyond that included in the posted-rate product,] part of the product would have a cost-based rate, and part would have a negotiated price, reflecting the flexibility portion, she stated. So you would pay a different price for a four-year product than a five-year product? asked Walton. Yes, the rate case will assume the full service, posted rate product is a five-year product, Hoffman replied. If you want a four-year product [spanning the last four years of the five-year period], that changes the risk for BPA, and it would be negotiated with your BPA account executive, she stated. The price would have some adder or subtractor for flexibility and might be higher or lower, Hoffman said.
So is it that "the sum of the parts should be greater than the whole?" asked Byron Wagner of Big Bend Electric Cooperative. No, the partial service products team is developing a product that doesn't put more risk on BPA than the full service product, replied Hoffman. The whole isn't equal to the sum of the parts either, she said. Your price ought to reflect your cost and your risk, stated Heitman. I would think you could sell a one-year contract less expensively than something you have to fix for five years, he added. Full requirements customers should get the cheapest rates because of their willingness to put all of their load on BPA, commented Wagner.
Walton asked about the "retail access insurance" product. Hoffman explained that the core and customized products would be take-or-pay. If in 2003, legislation passes that says a utility's consumers can access the retail market and the utility loses load as a result, the utility has a continuing obligation to pay for the load it signed up for, she said. BPA is offering several ways to mitigate that, Hoffman stated. First is the retail access insurance product, which "is like car insurance," she said. You figure out the extent to which you want to be insured, and if you lose that load, you don't pay for it, Hoffman explained. The second way is the retail access remarketing product, she said. If a utility loses load, BPA would remarket the power and credit the money back to the utility, minus the service fee negotiated for the remarketing product, according to Hoffman. The third way is through a contract, she said. We can structure a contract to include a provision that allows a utility to convert lost power to excess federal power, which the utility can market on its own, Hoffman stated. Fourth, you can partner with us and Morgan Stanley to find something to meet your risk needs, whether it's hedging, options, or something else, she explained. And fifth, you can do nothing, and wait and see if retail access comes, Hoffman said.
Are you considering folding those costs into full requirements costs? asked Wagner. We haven't resolved that -- we're still trying to identify the separate risks, Hoffman replied. The risk varies from customer to customer, based on their load profile, noted Berwager. One concept might be that we'd cover for residential and small commercial load loss in the basic contract, but not for large industrial load, he suggested. "You're making too big of a deal of this," commented Heitman. Administratively, it's a big headache -- how are you going to police your customers? he asked. BPA has said time and time again that it will be at or below market -- so who's going to lose customers? Heitman asked. We have to be prepared in case there's a market swing, but I think we'll be at or below market, responded Hoffman. I'm confident we'll be at or below market 90 percent of the time for 95 percent of our customers, but there may be some opportunities for marketers to "cherrypick" at some times of the year, Berwager stated. If that happens, we want customers to have some motivation to manage that risk, he said. We've wrestled with what to do if we get into a market where prices are below BPA rates, like it was a few years ago, Berwager continued. If BPA loses sales that cover its costs, the costs shift to other customers, he said.
But if you sell to a marketer who sells into the Inland system, and then charge Inland a retail access fee, "you've made it on both ends," but what about the utility? asked Wagner. Some Montana utilities have opened up their systems and are subject to a retail access charge, noted C. T. Beede of BPA. If they let retail customers go, we impose a transition charge of two to three mills, he said. It's not difficult administratively -- the customer tells BPA each month how much power is scheduled into its system, and we apply the charge, Beede said. That's Montana law, not Washington law, commented Wagner. You're still selling to the marketer and charging the customer, he added. Chances are the marketer can't buy power cheap enough to do that, stated Beede. Then if there's no problem, fold it into full requirements costs, recommended Wagner. In Montana, they get a transition charge, and the retail customer has to incorporate that "in doing the arithmetic," commented Adams. The customer may still decide it's a better deal to go with the new supplier, he noted. "If it's been unbundled correctly," stated Tom Schneider of the City of Helena and the Montana League of Cities. You're telling us if BPA sells to a marketer that captures your load, and you have a continuing take-or-pay obligation, "it doesn't feel right" -- thanks for the comment, said Hoffman.
Walton asked, with respect to the retail access insurance product, if there were four customers with the same size load, would BPA charge one customer more because its risk looks bigger? Non-subscription products are available to meet the special needs of any customer and are intended to be negotiated between the account executive and the customer, replied Hoffman. Negotiations will take place over a year and a half, she noted. I assume that if there are comparable risks, the customers are all negotiating in the same time period, and the market "is not going nuts," the price will be about the same, Hoffman said. But if there are major market swings, they won't be the same, she stated.
What do you mean by "negotiations?" asked Wagner. If you had four customers talking about the same product at the same time, it would be the same price, but if it is at different times, there could be different prices, replied Beede. Behind the account executives, there are "pricing people" concerned about consistency, noted Hoffman. The price depends on the risk you're trying to ensure against, stated Garry Thompson of BPA. It's not a posted price, it's a tailored price, based on your conditions and the time the product is being discussed, he said. So it's not negotiated? asked Wagner. It may not be -- BPA will have pricing guidelines, replied Thompson. It will be different from a posted rate, added Hoffman. I thought negotiations involved sitting down and arriving at a price within a range, said Wagner. The account executives will get pricing guidelines from headquarters, said Berwager. There are terms and conditions to be negotiated, but there would be pricing guidelines behind that negotiator, he stated.
What about load gain pricing? asked Heitman. There is a load growth product, which we would sell as non-subscription power at the PF" rate, replied Hoffman. With a limited inventory and a lot of demand, we thought we could run out of PF' power before we'd get to retail access load gain, and so we decided that power would be sold at PF", she continued. We would include load growth with full service purchases, but if you don't buy full service, you won't get load growth at the PF' rate, Hoffman said. You'll get your load met, but maybe at PF", she added.
Would you explain the difference between load growth and load gain? asked Heitman. Load growth would occur within metering boundaries, and load gain would be something scheduled to another territory, replied Hoffman. We can't identify load growth "to a gnat's eyebrow," she added. We went to the Subscription Work Group with the idea that we'd provide it for full service customers at the PF' rate, and for partial service customers at the PF" rate if they want BPA to follow their load growth, said Thompson. The work group hasn't made a decision on the issue, he noted. Load gain is something that is not on your distribution system, and as to how that affects full service -- we haven't gone down that road yet, Thompson said. Another way to do it, he continued, would be to take the allocations recommended in the Regional Review -- the average of the two highest consecutive years' entitlements in the 1997-2001 period -- and say, that is your take at PF', and anything above that is your load growth and would be sold to you at PF", Thompson said.
For utilities with generation, there's a risk to BPA associated with backing up how they operate their generators, noted Hoffman. The partial service team is working on that and making significant progress on the risks associated with partial service products, she pointed out. The work group has said, there should be no shifting of risk among customer classes, and we're working hard not to mix risks among customer classes, Hoffman said.
Hoffman explained the slice of the system product, noting it is something that some customers have asked BPA to offer. Essentially, "you look at BPA's costs and generation and slice it off," she said. It's taken six months to figure out what is meant by the costs, system operations, and flexibility they want, Hoffman said. The "slice team" has more meetings scheduled through August 5, she noted. The generating publics won't be ready to sign anything on July 1 because the slice discussions will still be going on, Hoffman stated. She noted that BPA has five principles with respect to the slice product. All our products will meet these principles, Hoffman added. A proposal for selling a slice of the system must not:
- Shift risk or costs to other Pacific Northwest purchasers.
- Shift risk or costs to the taxpayer.
- Enable slice purchasers to avoid current or future costs of fish protection and enhancement.
- Interfere with BPA's system operating decisions.
- Require change in federal law.
If the slice team develops something, would it be a subscription product with a posted price? asked Adams. We haven't put it on our list of products -- if it goes on the list, I think customers would want a posted rate, replied Hoffman. It would be cost-based with a subscription right, but it would be hard to determine a posted rate, said Berwager. Most of our posted-rate products have billing determinants based on megawatts or megawatt-hours, he noted. It seems to me if we have a limited supply of product, you would have to do the slicing before you do a rate case for subscription power, Hoffman said.
What does principle four entail? asked Jeff Schlect of Washington Water Power. The slicers wanted to make decisions on water coming out of the dams, but BPA thinks it has to be the one to determine how to meet non-power constraints in order to make sound operating decisions, replied Hoffman.
Walton asked for an explanation of the product titled "option for follow-on subscription rights." The concept stems from the Regional Review, explained Scott Wilson of BPA. With the option, you can sign up for five years and pay an option fee to secure rights to cost-based power in the future, he said. What if you are a full-service customer? a participant asked. If you sign a 10-year contract, you don't have to pay an option fee, said Berwager. It's for those who only want to make a commitment for five years and to decide later whether to buy up to that amount, he stated. What if you decide to go back as a full-service customer post-2006? asked Dave Hagen of Clearwater Power. What if you diversified before 2001 and decide in 2001 that you want to be full service? asked Tom Richardson of Cheney Light. We're still working on the extent of the rights to get subscription power in 2001-2006, Hoffman replied. The option fee only assumes the right to buy at the lowest rate BPA has available, said Berwager.
As we go into subscription, if you have some outside load -- say, for example, it's 90-10 -- and you want to come back to BPA, do you come back at a different price? asked Wagner. It could be -- we'll be getting into that discussion, said Berwager. How did that come about? asked Wagner. Public power argues that if you combine several unbundled products and apply to meet your requirements load, you get to buy at cost-based rates, isn't that so? asked Walton. We're not sure yet -- the partial service team is working on that, replied Berwager. The full-service product doesn't need any "below-the-line" products, except maybe the option fee, said Hoffman. It's everything, except transmission and figuring out how to deal with retail access risk, she stated.
Berwager explained that BPA expects to have about 6,400 average megawatts (aMW) of inventory available for subscription. We've made presubscription sales totaling about 980 aMW to subscription-eligible customers, he pointed out. There is also the Portland General Electric exchange settlement, which is out for public comment, Berwager said. There isn't unanimous support for BPA signing that, and we will make the decision whether to do so in the next few weeks, he stated.
The inventory numbers set the stage for a discussion of why one utility could buy power at one rate, but have to pay another rate for the rest of its load, Berwager explained. The debate is over how much of the 6,400 aMW is available to what customer groups, he said. The work group adopted an approach to subscription last winter that stemmed from the Regional Review, which thought BPA wouldn't be able to sell all its inventory, Berwager continued. This "open-window" approach involves BPA selling to all customer classes simultaneously, with BPA reserving enough power to meet later requests of publics, IOU exchange loads, and the DSIs, he said. BPA would periodically assess how sales are going during the 27-month window, and if sales are slow, BPA would look for other markets to sell to, Berwager stated.
Since last winter, new price forecasts of BPA's costs versus the market, including those made by the Northwest Power Planning Council's "Aurora" model, show that buying from BPA will be a very good deal, and so the problem has become how do we decide who can buy at the lowest cost-based rate, he said. The Regional Review recommended that subscription have different "phases," with Phase 1 consisting of public utilities who could subscribe up to the average of their highest two consecutive years of purchases from BPA during the 1997-2001 contract period, Berwager continued. When you total that, it's 4,300 aMW, he said. Phase 2 power would encompass 2,040 aMW for the DSIs and 3,370 aMW for IOU/exchange loads, Berwager explained. Thus, there's 9,700 aMW in loads in Phases 1 and 2, but only 6,400 aMW available in the inventory, he said.
The question, according to Berwager, is how does BPA allocate 6,400 aMW among preference customers and others, including IOU exchangers, that have been purchasing from BPA. He explained that three ideas are under discussion. The first is the open-window approach, and the second is an approach in which BPA would establish one cost-based rate for specific subscription amounts, and a different cost-based rate for additional amounts of service, Berwager stated. Under the third approach, BPA would make purchases to firm up some of its nonfirm inventory, "to the tune of maybe 650 aMW," which would give BPA about 7,010 aMW for subscription, he said. We would still sell 4,300 aMW to preference customers, but we would also be able to meet half of the DSI and IOU/exchange Phase 2 loads at the lowest cost-based rate, Berwager said.
If a public wants to put 100 aMW on BPA, it could, but if only 80 aMW was its share of the 4,300 aMW, then it would get 80 aMW at the lowest cost-based rate, and the other 20 aMW at a different rate, he explained. BPA hasn't selected one of the three options, but it will have to before subscription begins, Berwager stated. Schneider asked about natural gas prices and the "drivers" of the Aurora model. Berwager said he would send information about the model to Schneider. The model is driven mostly by forecasts of West Coast natural gas prices, and the upper limit is a new combined-cycle plant, said Adams.
Where do new qualifying public loads fit into these scenarios? asked Schneider. In the open-window approach, if you could come in quickly, you would be able to buy, Berwager replied. Under the other two options, there would be no power at cost-based rates, he noted. If a customer has diversified and then wanted to "undiversify" and put all its load on BPA, what would happen? asked Walton. If a public like Cheney has diversified, under the last two options, the diversified part of its load wouldn't be in the 4,300 aMW -- it would be at another price if the utility decided to go back to full service, Berwager replied.
Have the legal aspects of this pricing scheme been fleshed out, and is this a draft proposal or further along than that? asked Schneider. The last two options have been discussed as concepts by the work group, replied Berwager. The work group has also discussed BPA's ability to differentiate rates, and BPA has told the work group that we think we can differentiate rates for cost-based service, he said. That's not unanimously agreed to by our preference customers, Berwager noted. The discussion is continuing on this -- "it is one of the big ones," stated Adams. It's "the big one," said Berwager. He pointed out that under the third option, as BPA "grows the pie," additional costs would go into the melded lowest cost-based rate, and the melded rate would go up as you firm up nonfirm, Berwager stated. This option needs more analysis, he continued, adding that the region is focusing on the idea of making the pie bigger without moving to something that looks like allocation. BPA doesn't allocate power -- we're talking about how much power to sell at the lowest cost-based rate, Berwager continued. The Northwest Power Act gives BPA the ability to acquire resources to meet certain loads, he noted.
Walton pointed out that some IOUs have argued that BPA shouldn't "grow the system," but that BPA should sell residential exchange power to them. That's doesn't seem like a logical argument, he observed. I talked to the Oregon Public Utility Commission, and Commissioner Eachus said he thinks that some system expansion to meet IOU exchange loads makes sense, said Berwager. Walton noted that Steve Weiss [of the Northwest Energy Coalition] has raised the idea of creating a "paper utility" for residential exchange customers in Oregon. New customers could be a big issue, he stated.
It's tough for us to decide on subscription since there is no rate and no way to know about transmission, said Hagen. We would like to see concurrent power and transmission rate cases, he stated. I've heard if utilities subscribe before the rate case, there would be off-ramps in case BPA can't meet the rate established in the rate case, Hagen said. The question is, if a utility signs a contract before the rate case, what would it look like? said Berwager. One idea is that a utility would just sign up for the PF rate, whatever it is, for 20 years, he stated. Another is for BPA to do contracts at the PF rate, but to put a rate test in the contracts, Berwager said. If the rate test were at 24 mills, for example, and if the rate went over 24 mills, a customer can decide not to buy, he stated. A third idea, according to Berwager, would be to put "a collar" or rate boundaries on PF rates. We've decided we can't do that, he said.
Our current thinking is the first option -- you sign up for the PF rate with no rate test, Berwager stated. To get agreement on a rate test number would be a big debate in the region, he said. Isn't this more complex for people who have diversified -- wouldn't it be harder for them to know whether they want to buy and how much? asked Walton. I agree, replied Berwager. There are many uncertainties associated with signing subscription contracts before the rate case, he said.
We have scheduled to start subscription in July and the rate case in September -- should proceed on that schedule? Berwager asked. Will you negotiate with others if we can't do deals soon? he inquired. We don't have but 25 percent of the information we need, on items such as transmission, the Low-Density Discount, and the General Transfer Agreements (GTAs), to be able to make decisions on subscription, said Hagen. If we could get some answers on the transmission side, it would really help, he added. The question is, according to Hagen, under the open-window approach, if we wait until we have the information, will there be any product left for us to purchase? Would you purchase from others? asked Berwager. We have some options, Hagen replied. How fast should we make the decision? asked Berwager. I'd like to see the Transmission Business Line and the Power Business Line get together so we can see the numbers, Hagen responded. When do you want to see BPA's options with more detail? Berwager asked. I'd like to see transmission rates in the six months past the first of the year, Hagen replied.
Most utilities want to know what the price will be, stated Wagner. BPA is concerned that other suppliers will sign up utilities, but the marketers are waiting for BPA to set the price -- they aren't making offers anymore, he said. We are concerned about losing sales, stated Berwager. We think now is a good time to make deals while the market looks good, he added. Your costs are still pretty fixed, said Wagner. What you are looking at is fish costs that aren't fixed, he added. I don't see others stepping in until you establish the price, Wagner said. We had a panel of IOU marketers at a PPC meeting, and I got the impression from them they are not ready to compete, stated Walton. Some publics want to sign up soon, and a delay works against them, he said. I've heard both messages -- delay and don't delay, Walton noted.
What phasing should we implement? asked Thompson. Do we open the window to all? he inquired. You don't need phasing if you set the parameters for allocation, said Jake Eimers of Idaho County Light and Power. If utilities know what they can request to buy, you don't need phasing, he added. Thompson asked what if the publics don't sign up and the DSIs take their allocation, and then BPA says, we'd like to sell more to the DSIs. Give us a date certain and tell us if you don't take it by then, we'll sell it somewhere else, replied Eimers.
PPC has argued that under current law, you must sell net requirements service to any preference customer at the lowest cost-based rate and that you don't need to "grow the pie," said Walton. I'm not buying that whole statement, said Berwager. If the only group that buys subscription power from BPA is the publics, it wouldn't play well in the region or in Washington, D.C., where there's interest in selling BPA, he stated. If there's a regional agreement on the benefits of the system being shared, as a region, we can protect against those arguments, but if there's no agreement in the region, that will be more difficult, Berwager said. With a larger public utility base, BPA would run into load shape problems -- we would have higher "peaky" load and have to buy more power to cover the peaks, observed Hoffman.
What do you propose? Wagner asked the BPA reps. We don't have a proposal on the allocation issue -- it's a tough question, replied Berwager. We have a new administrator, and we need to do more analysis and get the information in front of her, he said. The region is discussing it, and we hope consensus will come out of those discussions, Berwager stated. While we don't have a proposal, we do think "the sky is not the limit" on how much we would expand the system, he continued. Also, we're not interested in staying with the exchange as it has been, as a financial transfer, Berwager said. That makes much less sense in a competitive market than it did in 1980, he added.
Thompson asked if the "expand the pie" option were used to address the exchange problem, and it meant the PF rate would go up, is there concern on the part of the publics that they won't get the megawatt benefits, even if they may get a political benefit? I think it's "really shaky" for new and partial customers, responded Schneider.
Adams mentioned several outstanding issues, including the residential exchange, stranded costs, load growth issues, BPA's future role in the acquisition of new resources, and the slice product. Walton added transmission rate case timing and the GTAs to the list. Hoffman pointed out that BPA has been working on the partial service product in the hope that customers would want to buy it, rather than pursuing the slice. There's been progress on developing the partial product, but we don't know if it will ultimately meet customers' needs, she said.
Will Washington, D.C. demand answers to the stranded cost and fish issues before allowing subscription to go forward? asked Walton. I think so, replied Berwager. Treasury wants a lot of protection in the contracts, he noted. So you'd resolve the stranded cost issue in contracts? asked Walton. If there isn't a solution everyone agrees to, there would have to be pretty open-ended language in the contracts, and customers might not find that workable, responded Berwager. It would be better for the region to resolve the issue, he added.
Adams pointed out that the Subscription Work Group has meetings scheduled through July. There's been a lot of discussion and analysis -- now we need to see if we can package these issues in a way the region can support and BPA can move forward with, he stated. Another outcome would be that we close down the work group because it will never reach consensus, and then some big uncertainties would be taken into the rate case, said Hoffman. The rate case is not the environment to get consensus -- it's better to try to get consensus before the rate case, said Berwager. Rick Itami of BPA noted, in response to a question, that BPA has challenged its staff to get customers details on the disposition of the GTAs soon after the power rate case concludes.
Adams noted that more information on the Subscription Work Group is available on BPA's website, and if anyone wants to get on the mailing list, they should tell him or Berwager. Whitney pointed out that the public comment period on subscription will close July 20. If there is a change in the schedule for subscription, we will provide public notice, she said.
Archive of content originally posted or last updated on: July 6, 1998.
Content originally provided by: Syd Berwager, BPA Power Business Line.
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