Bonneville Power Administration (BPA)
Pacific Northwest Utilities Conference Committee (PNUCC)
Summary of June 3, 1998 MeetingBPA Rates Hearing Room
The work group talked about products and recall rights, considered tools to predict and mitigate stranded cost problems, and agreed that the residential exchange is a major unresolved issue. About 35 people attended.
Next meeting: June 17.
- Core Power Products: Another Look
- Sizing the Problem and Tools to Solve It
- Get on Board for Issues '98
- Another Round on Recall Rights
Maureen Flynn of BPA made a presentation on core products and pricing concepts, asking the group to identify "outstanding issues that are on the critical path to subscription readiness." She distributed a handout that showed three core power products, arrayed with "questions remaining" about each, and the forum where those questions would be resolved. The three core products would be tied to posted five-year, cost-based rates, and the pricing of "below the line" products would be by "open-market bilateral negotiations," Flynn explained. She indicated that some parties have raised questions about specific unbundled products and said that the partial products team needs to try to resolve those questions. The Subscription Work Group needs to handle questions remaining about PF' and PF'' rates, Flynn noted.
For the full service product, the work group needs to decide how to treat load growth, she continued. Flynn said that two types of firm power block products -- "flat" and "shaped with parameters" -- are under review by the partial products team. The team is also talking about two types of partial service product: "EZ flat customer resource," in which it is easy for BPA to know what a customer's load is; and a second product labeled "variable customer resource." Flynn said the partial products team would meet again June 10 and June 16.
Q, A, and Comments. Are the above-the-line products those that will be cost-based in the rate case? she was asked. Yes, Flynn replied. The group asked clarifying questions about the details of the products and how they might work. The concept of partial requirements is important to my clients, said a customer rep. I'm encouraged by what I see coming out of the partial products team, he continued. Some of our utilities have taken their post-2001 plans to their boards, and it definitely looks like there will be BPA participation in supplying that load, he stated. Let's do what we need to do to push this forward, he added.
A public power customer rep commented that the firm power block product is not usable without some of the unbundled components. To describe three products in isolation "is something short of a full picture," she said. You need to include the unbundled products necessary to make the requirements firm block work, and they need to have posted prices, she added. She said a group is working to identify on-the-shelf, cost-based products that BPA should offer and that it will get the product descriptions to BPA before the next partial products team meeting. We are working to make sure the partial service products have the features customers need, said Flynn. I expect that we will look at each other's product lists and identify what needs to be in the core products to serve requirements load, she stated. A DSI rep wondered if BPA was relying more on "rules" than pricing in some of these products, and he urged the agency to rethink its approach and "use pricing more than bundling."
Another concern raised by a public power rep involved eligibility and pricing. BPA has tried to follow the Regional Review's suggestion of the highest two consecutive years of the 1997-2001 contract period to limit the amount of power public utilities can purchase at the lowest rate, she said. Our problem is having a limitation on these utilities' legal ability to access federal power from BPA, she added. Another public power rep said it's not clear where and when the issues of eligibility and the PF' and PF" rates will come to closure. I'd like to have the issue engaged or know when it will be engaged, he said. That issue falls under the implementation approach discussions the work group has been having, responded Syd Berwager of BPA. We've presented some options, but the group hasn't reached agreement on the approach, he stated. It's a critical issue, and this group and this region need to deal with it this month, Berwager said.
When should we take up the eligibility question? inquired Dick Adams of PNUCC. The group agreed to do it at the June 17 meeting. The question is, will BPA sell to customers who come forward or not? said a DSI rep. I'd want to know who wants to buy before I made the decision on who can buy, he added. "It's a chicken and egg discussion," a participant observed. How should we make the discussion on the 17th the most fruitful? asked Adams. "Read the Northwest Power Act," replied a customer rep.
BPA should be prepared to talk about its resource acquisition plan because there's a relationship, suggested another customer rep. If BPA is oversubscribed, what you do with resource acquisition affects "how many people are in line," he added. It's been suggested that we talk about a stranded cost mechanism, which will determine how risky the product is and how much demand there will be for the product, said a public interest rep. If we know the product includes option fees and rate adjustment clauses, then there might be a more realistic basis on which to decide what you want to buy, he continued.
A regulatory agency rep said the renewal option should appear on BPA's product list. Above or below the line? a participant asked. We've said it would be below the line, Berwager replied. A customer would elect to buy a renewal option as part of its contract decision, said the agency rep. How do we deal with preference customers who don't have to purchase an option to get cost-based power? asked a public power rep. If a customer wants a right to the lowest-price, cost-based power in the future, we're talking about an option fee, said Berwager. Preference agencies have the right to the lowest-price, cost-based power without having to pay an option fee, said the public power rep. Will the partial products team finish developing products by the 17th? asked Adams. That's our target, Flynn replied.
Slice Talk. Adams brought up the slice of the system product, stating that it seems the product "has not evolved enough" to assume it can be completed this month. There's no mutual agreement on it, agreed Flynn. There isn't mutual agreement on any of this, observed a public utility rep. There is a schedule of public meetings on the slice into August, he noted, adding "when the new Administrator takes office, the whole schedule may change for everything." A participant asked for an update on slice issues. The two biggest outstanding issues, said the public utility rep, are: what costs are appropriate to include in the slice, and what information exchange is necessary to make the product workable. We are waiting for BPA to respond to a list of issues we gave them, he added.
Have any antitrust concerns about collusion among utilities come up? asked a regulatory agency rep. We are talking about information on future system operating conditions, such as nonpower constraints on the operation of power resources -- we're not into secret information, replied the public utility rep.
A customer rep said the transition cost issue continues to be a problem impeding subscription development and that subscribers may not sign up until they know how stranded costs will be addressed. The questions associated with the issue are: What is the size of the problem? and What tools do we have to meet the risks and address potential problems? He said a subgroup is meeting to discuss these questions. The group assumed, he noted, that if there are major system configuration changes, that those who ask for the changes will also bring the solution of how to pay for them. We are trying to devise a program that leaves BPA with sufficient reserves at the end of the 2002-2006 period to be able to address future risks, he explained.
Northwest Power Planning Council staffer Pete Swartz described a stranded cost simulation computer model being used to assess the "size of the problem." It looks at different scenarios for system generating capability, costs, and how much revenue BPA could get if it sold power at market prices, he said. The scenario presented assumed the cost of power at 20.7 mills per kilowatt-hour under average water conditions (using the "transport plus" fish cost scenario and the third of eight fish scenarios) in terms of expense, Swartz said. He noted the analysis has no treatment of the exchange in it.
Swartz produced graphs of BPA net revenues with reserves in various years. He said the graphs represent the benefits and costs the system "throws off" in each scenario. The model shows, according to Swartz, that in the first five-year period, 2002-2006, there are unlikely to be major cash flow problems if BPA sold power at market prices. In the second five-year period, 2007-2011, about half of the time, there would be no problem, and half of the time, there could be a sizable problem. Another Council staffer noted that the model is just one analytical tool and that BPA rates would not be set at market prices. The bottom line, said Swartz, is that if you go into the second five-year period with an $850 million target level for reserves, there's a high probability of "getting through the stretch."
There are several other fish cost scenarios this model didn't look at, and this isn't one of the most costly of them, said a public interest rep. This is a tool to tell you what kind of utility different levels of revenue might have under different circumstances, and it also tells you the limitations on using reserves, he said. We analyzed the Clean Water Act scenario with $850 million in reserves, and there were no cases when $850 million was enough to get you through at low-market prices, said Swartz. This is a low-market case -- it isn't where people think the market will be, said another Council staffer. If you increase the low market by 10 percent, it makes a big difference, noted consultant Al Wright. This is extremely sensitive to a 1 mill change in the market, and people should be aware of that, he said.
The customer rep who kicked off the presentation noted that the subgroup is discussing the tools available to mitigate cash flow problems. The first set of tools to look to includes reserves and Section 4(h)(10)(C) credits, he said. The next set involves BPA cost reductions, he stated, noting that the Council's analysis does not take into account cost cuts recommended by the Cost Review. Other tools in this category include net revenues for risks, option fees, an additional line of credit, hedging, and indexed rates, and if those tools aren't sufficient, we could look at interim rate adjustments, a wires charge, or an emergency 7(i) rate case, he stated. He said the subgroup will meet at PNUCC June 12 to talk more about the issue and the sequence in which the tools should be used. The point is, he summed up, "the risk is there, but there are many devices available to deal with it." We need to clarify the model's analysis and how it informs the problem, said Adams. He requested the work group meeting on the 24th include more information on the magnitude of the problem and prioritizing the tools.
Berwager handed out a Risk Management Fact Sheet prepared for BPA's upcoming Issues '98 meetings. He said the fact sheet deals with the problem of BPA's risks, but presents the analysis in a different way from the previous discussion. It addresses other risks besides fish, he noted. Berwager pointed out charts in the fact sheet that show Treasury payment probabilities arrayed against different subscription rate scenarios. The three charts show a base case, rates adjusted to provide $100 million higher net revenues annually, and a third case with $100 million lower net revenues, all for the 2002-2006 period. On each chart, the green areas represent a Treasury payment probability of over 88 percent, without any contingency mechanism; the blue areas show that Treasury payment probability would be below 88 percent, unless you use such mechanisms; and the red areas show times when even if you used the mechanisms, the probability wouldn't reach 88 percent, he noted. Berwager said Byrne Lovell is the BPA contact for the risk management paper, and Helen Goodwin for Issues '98 in general.
Scott Wilson of BPA recapped Regional Review recommendations on long-term contracts and noted that the fact BPA's inventory may be limited raises issues about the priority of service, the firmness of BPA sales, and whether some sales would be subject to recall. Recall damages a customer's assurance it would receive the long-term benefits that were an important basis of its decision to enter into the transaction, he said. Wilson noted that at the last meeting, the group discussed six options on this topic, and a seventh was suggested. He said BPA now proposes to deal with the recall issue in long-term subscription sales of surplus power with a two-step approach. In step one, BPA would, before recalling any power being sold under a long-term surplus subscription contract, give its PF, IP, and PF exchange customers the opportunity to reduce their BPA purchases up to the amount BPA would otherwise recall, Wilson explained. Step two makes use of an indemnification clause that would be included in FPS subscription contracts, which would provide a purchaser the difference between the market price for the power and the BPA PF rate if the power is recalled, he said. Unless we hear something different, we'd like to go forward with this approach, Wilson stated.
The problem I have is that you're teeing this up as a finalization of the issue when the residential exchange is completely unresolved, said a DSI rep. You can't get buy-in without an understanding of how to address the exchange -- that's the bigger issue we have to agree on, he stated. This doesn't seem to be a recall -- you're just trading dollars, commented a customer rep. This says, if we make surplus subscription sales, this is how we'd do it, stated Wilson. This assumes that you get the benefit if the benefit is there long term, said Berwager. As long as you purchase an option to renew, said a public interest rep. Don't take this idea off the table, and in addition, you could say that IOU exchangers could sign up for five years, and if they buy an option to renew, they'd all have rate protection, he added.
A public power rep suggested that the indemnification clause would provide an economic advantage to an entity whose power is being recalled over a purchaser whose power is not. Preference customers would bear the cost of this "subsidy" -- the money has to come from somewhere, and it doesn't come from surplus sales, she said. The question was, is there a solution that works under the existing statutes and implements the Regional Review, and this does it, said a regulatory agency rep. As a practical matter, BPA wouldn't do recall -- it would buy power and spread the costs among everybody, said a DSI rep. The cost could be assigned to the entity that causes the recall, suggested a public interest rep. We can come to closure on this, but we have to say it can't be implemented without resolution of the exchange issue, said a DSI rep. We have also not solved the PF' and PF" load growth issue, noted a utility rep.
A public interest rep said the issue of new publics needs to be on the work group's agenda. I've heard talk of a Montana buying cooperative forming to serve Montana Power's residential and small commercial default load, he added. What if the city of Portland votes to become a public? How would that be treated? he inquired.
Can we say this works as a concept, but there is a bigger contextual issue that needs to be addressed? Wilson inquired. It's a provisional proposal on the table, said public interest rep. Don't think that it's going to drive other issues, cautioned a utility rep.
Exchange of Opinions. Should we put the exchange issue on the agenda for the next meeting? asked Adams. We need to better define contractual terms and conditions before we can deal with the exchange issue, said a regulatory agency rep. The overriding issue is implementation and how customers fit in and what the resource inventory is, said a customer rep. I don't sense the will of the group is to get into multilateral discussions on contract issues -- there's a sense we've done enough, said a DSI rep.
We could talk about the exchange in general terms, and once we find out what people want to buy, it may not be much of a problem -- we could come in with the numbers and then have the discussion, said a public interest rep. Nobody knows what they are going to do, and there's no way to assess the magnitude of the problem, a customer rep responded. The perception of the situation now is totally different from when we started on this, he stated. The only model to look to is the phased approach, based on the law, he continued. The idea that BPA can manage through subscription won't work -- you can't assess how large the preference customer pot is, he added.
But you can get a "going-in" agreement on some things, said a public interest rep. We're "high-centered" on the issue of allocation, he continued. Part of it is a numbers discussion, part is a legal discussion, and part is a principles discussion, he said, adding that the task is to reconcile those three into a going-into-subscription formula. Unless you change the Northwest Power Act, there is only one way to proceed, responded the customer rep.
The phased approach won't work without a price, and you can't have a price without a presumption about what you do with the exchange, said Berwager. A cash buyout would produce certainty for the exchange, said a customer rep, adding that he isn't endorsing that approach. This process won't make sense until we agree on the exchange, said a DSI rep. The Regional Review said BPA should offer products to customers willing to bear the risks of buying them, and then at the end, if there's a problem, a stranded cost mechanism may be necessary, said another DSI rep. What's happening is you are picking and choosing from the Regional Review, and you won't get agreement, he said. Circumstances have changed since the Regional Review, stated a public interest rep.
Maybe we can do "an initial skirmish" on the exchange on the 17th, suggested a customer rep. Yesterday BPA made a presentation on subscription to the Oregon PUC, and the commissioners were definitive about their opinions, said a participant. The commissioners said: exchange benefits should be delivered through power, not cash; 50 percent of the eligible load should be taken as a minimum; there should be the same terms and conditions as those for sales to the publics; and given the changed circumstances, having BPA go into the market to acquire resources is acceptable, he reported. The big question is: do you do an allocation or meet loads, commented a DSI rep, adding that that issue should precede consideration of other issues, such as BPA's resource acquisition plan. The group decided to cancel the meeting scheduled for June 10.
Archive of content originally posted or last updated on: June 15, 1998.
Content originally provided by: Syd Berwager, BPA Power Business Line.
Content currently provided by: PBL Requirements Marketing - PS.
Page maintained by: BPA Web Team.