Bonneville Power Administration (BPA)
Pacific Northwest Utilities Conference Committee (PNUCC)
Summary of May 27 & 28, 1998 MeetingsBPA Rates Hearing Room
Members of the Subscription Work Group debated whether they could finish their work by July, with some arguing it could take another six months. BPA presented its latest thinking on implementation, describing several options, including a "bigger pie plan." The residential exchange came to the fore in discussions of firming nonfirm resources, and the wires-charge bogeyman appeared when the group tried to nail down contract principles. About 45 people attended. The next meetings are set for all day June 3.Index (click item to move to topic)
- Process or Progress
- Gauging the Inventory and Devising Implementation
- The Cost of Firming Nonfirm
- Contract Provisions
- Contract Features Take the Floor
PNUCC director Dick Adams said some participants do not think the group will finish by late June and have recommended extending the time. Others say "we know all we are going to know" for BPA to get subscription going, he reported, suggesting that for some issues, "declaring victory means we've gone as far as we can in this forum." At a minimum, people want to know what BPA is planning to do, Adams said. It would be nice, but unrealistic to expect consensus, he added.
A public agency customer said his utility sent a letter asking BPA for more time. We believe there are significant unresolved issues, and that argues for a "more protracted schedule," he said. He suggested the work group continue until the end of 1998, with a BPA rate case beginning in early 1999. We have recommended there be no rate case "until the issues have been wrestled to the ground," he stated. We would support a more deliberate process, too, a public interest rep said. There are issues that interlock with other processes, he stated. The biggest issue is stranded costs, he continued, adding that there are proposals afoot to handle it through contracts. It is also unclear how much power the residential exchanging utilities will want, he added.
Does BPA have the ability to change the schedule? a customer rep asked. The reasons we want to start subscription July 1 are still there, according to Syd Berwager of BPA. Our experience with presubscription indicates there are customers who want to fill their portfolios now, he said. The market looks good, and "if we delay a year or a year and a half, who knows," Berwager stated.
A public agency rep said the group should decide what remains to be done and "do it." If we get to June 24 and there are still more issues, "let's line them up and deal with them," he suggested. My clients want to do business July 1, he said. It's important to get this right, an aluminum company rep stated. BPA is in Washington, D.C. now "agitating for a wires charge," he said, adding that subscription has to give BPA the opportunity to cover its costs in some other way.
If we delay, shouldn't BPA be able to enter into contracts with those who want them? a customer rep asked. Cost shifts are a fundamental concern, an IOU attorney replied. Let's quit spinning our wheels and get to work, another participant suggested.
We need a commitment that BPA will not sign contracts before this is all figured out -- I'm worried about BPA "giving away the store," a public interest rep said. The concern is that we will end up like we did with the DSI contracts, a customer rep said. "You're walking toward subsidies," she said. The question is whether early signers get a better deal than later signers, she stated. That's always a possibility with negotiations, a group member replied.
We have not dealt with the issue of cost and risk shifting, an IOU rep said. As long as there is uncertainty about it, "we are cruising for a fight," he added. A public interest rep asked how new preference entities would become qualified and what price those customers would pay. It's important to time subscription and the rate case so you do not "King's X" the consensus that is being built here and in other groups, a tribal rep observed.
Do we have a principle that says there will be no cost shifts? a customer rep asked. You have no way to measure without a benchmark, she added. We have to talk about the details, another participant said. The principles on the slice product would be a good set to start with, an IOU rep stated. If we decide what contract terms should be included to help BPA manage its cash flow risks, that could abate some of the concerns about risk shifting, a participant suggested. A customer rep suggested the contracts that have already been executed could limit choices or shift risks.
Adams said he and Berwager would look at the list of remaining issues and focus future meetings around them. A customer rep asked if BPA would "memorialize" the conclusions of the work group before subscription begins. A BPA attorney said the purpose of the group was to help resolve issues raised in the Regional Review and provide guidance.
Berwager presented BPA's calculation of what its firm power inventory will be for subscription. According to the staff's chart, BPA has 7,820 MW of "gross firm resources under critical water." Of that, 1,440 MW is committed to treaty and nonsubscription contract obligations, including presubscription sales. The total available for subscription is 6,380 MW. The Regional Review's estimate of total eligible load was 9,710 aMW. Berwager pointed out that presubscription sales included 980 aMW of "subscription-eligible contracts signed by public utilities." [Here is a PDF version of the "Inventory" handout.]
Are there any more presubscription contracts pending? a customer rep asked. I think we're done, Berwager responded, and a BPA staffer noted that three presubscription contracts are unsigned, but are included in the totals. She also pointed out that the final Biological Opinion for steelhead could affect the firm power inventory.
Berwager outlined BPA's "discussion paper" on implementation, listing conditions that have changed since the Regional Review made its recommendations. The expectation was that BPA would have difficulty selling its inventory, and there would not be competition for cost-based power, he explained. With market forecasts now indicating BPA will be at or below market, there is a risk we'll be oversubscribed, Berwager said. [Here is a PDF version of the "Discussion Paper" handout.]
The paper describes seven approaches to implementation, four that are consistent with the Regional Review's recommendations and three that are not, he said. Plan A envisions an "open window," during which BPA would take requests from all comers for the term of subscription. Plan B calls for a "bigger pie," under which BPA would serve all loads included in the Regional Review's Phase 1 and up to 50 percent of Phase 2 load. Under Plan B, BPA would make purchases to firm up to 530 aMW of nonfirm energy.
I don't see why 50 percent is an appropriate constraint for the IOU exchange loads, a PUC rep said. For Plan B, we assumed half of both the exchange and DSI Phase 2 loads, Berwager responded. What would be the rate impact of the purchases needed under Plan B? a public agency rep asked. Do these meet the legal criteria in the Northwest Power Act? a customer rep asked. Another participant asked if BPA had run its repayment study from 2001 forward. Staff said no. I'm looking for whether any of the approaches have consensus, Berwager said.
Another option would be Plan A and meeting all of the requests, an aluminum company rep said. It's an option that should be looked at, he said. What legal obligation does BPA have to serve the DSIs? the PUC rep asked, adding that there was none. A tribal rep asked if a newly formed public agency would be in Phase 1. We have to sell to qualified customers, a BPA attorney responded. Formation of a public agency takes many steps, and an entity could come in once it is formed, he said. Why go through all of the steps if you would not be eligible for Phase 1? the rep asked. If an entity becomes a customer, then we can negotiate, the attorney responded.
The options other than Plan B have little likelihood of satisfying all of the customers, a public agency rep observed. My clients are willing to keep the exchange going, and we are not opposed to converting the exchange to a power transaction if it does not mean higher rates or less supply to meet load growth, he said, noting that the 7(b) rate test is still relevant. You can't assume the rate test does not exist, he added.
We need to know what products and services BPA will offer, as well as pricing details, so customers can decide whether they want to participate in the bigger pie, a customer rep said. We are thinking here that the bulk of our sales will be in the core subscription block, Berwager said. That's our philosophy -- our first priority will be to sell as much of the core products as possible, he added.
There are just two approaches: allocate a fixed amount to each customer class or meet the demands that are placed on you, an aluminum company rep said. Either approach could involve making the supply bigger, another participant observed. The critical items are the starting rate level and the magnitude of change, given the intent to firm nonfirm with purchases, he said. Some customers would prefer to buy less at a lower price than more at a higher price, an industrial customer said. "If growing the pie is expensive, that may not be where we want to go," he said.
An IOU customer pointed out that firming nonfirm energy could mean buying over 1,000 aMW in January and February. It's a shaping issue -- it's not just 230 aMW over time, he said. There was more discussion of what it would take to determine the rate impacts of firming nonfirm and whether the 7(b) rate test would be applied. It was presumed by some that the rate test would be ignored, a participant pointed out, adding that "people are still saying we don't need legislation." We have asked the Transition Board if it is realistic not to have legislation, an IOU rep stated.
What about recall rights? a public agency rep asked. We did not presume we would exercise recall rights, Berwager responded. If the contracts are giving us good revenue, purchases would make more sense, he added.
Berwager went on to explain the other options on the chart, including a "least purchase," under which BPA would meet Phase 1 loads and sell as much power as possible to the DSIs at 100-percent load factor. There were also "maximize exchange load" and "public preference plan" options listed. BPA staffers said they had not done a rate impact analysis of the options.
We need additional cost information, a public agency customer said. Are any of these attractive enough to focus our analysis? Berwager asked. Only Plan A (open window) and Plan F (public preference) are legal, another customer rep observed. We'd say these are all legal, a BPA attorney stated. These are not allocations of power, they are estimates based on the Regional Review, he pointed out. BPA will have to purchase power if it gets requirements requests that exceed inventory, he said.
To move the ball forward "without restarting the 1979 wars," what's wrong with BPA asking customers to state their intentions? asked one participant. If the response is 5,000 MW or 7,500 MW, it would suggest whether there will be "haves" and "have-nots," he said. That would be an unreliable gauge, according to several participants.
Are we operating under 18-year-old assumptions or are we looking to "the new world"? a customer rep asked. That's what keeps tripping us up, she said. How much of the old do we want to take forward? she asked. We can go the litigation or the Congressional route, but either of those argues for working through the issues here, a public agency rep said. At some point BPA has to do business, so we are better served by having a resolution -- we need to find our way through this, he added.
To know whether we can implement subscription within the current law depends on knowing what the demands are, a state agency rep pointed out. And whether the demand is within the limits of the inventory depends on two factors: price and contract provisions, he said. If we can get clarity on those two things, we may not be that far from getting a handle on it, he added.
If the system has to grow, does the 7(b) rate test trigger? It's extremely important to know, a public interest rep said. I would ask public power to think hard about standing on their legal position and not sharing the benefits of the system with exchangers, he said. If only public power supports this system, it cannot hang on, he added.
I don't think you can expand the pie enough, a customer rep said. According to the Regional Review, BPA is not in the acquisition business, Berwager stated. So that exacerbates the question of who gets what, a public agency rep said.
BPA staffer Barney Keep explained an analysis of what it would cost BPA to purchase power to meet 1,000, 2,000, and 3,000 aMW of additional load under average and 1939 water conditions. The analysis takes into account the need to shape the purchase, as well as a "market multiplier effect" of up to 15 percent, Keep stated. Our trading floor noticed that when we go into the market, prices go up, so we included that effect, he explained. In order to meet the additional load, BPA would use power it normally sells on the nonfirm and spot market, so there is a revenue decrease factored in, as well as an increase associated with selling an additional 1,000 to 3,000 aMW, Keep said. It would increase rates .3 mill per kwh to purchase an additional 1,000 aMW under average water, and it would cost 4.3 mills under 1939 water, he concluded. Keep also noted that certain operational effects and transmission constraints on power imports could have a rate impact.
Looking at this as a business decision, BPA would be better not to buy to firm nonfirm, a customer rep observed. Some have said if our purpose is to provide benefits by giving lower rates, it may make sense to purchase, Keep replied. You only see the measure of rate impacts here, another customer rep pointed out, but there could be costs if BPA has to make an exchange settlement with the IOUs.
The IOU residential and small farm loads are currently met with IOU resources, a public agency rep said. If BPA agrees to meet that load, the consequence is the IOU resources are freed to the market, so what happens to the revenue they get for that power? he asked. "Why are we torturing ourselves with this" and putting BPA in the position of purchasing if that load is being served? he inquired. "Because you have been so successful in labeling the exchange a subsidy," an IOU attorney responded. What we are talking about is the allocation of benefits, she stated, and some of those benefits have been called a subsidy. State regulators have advocated converting the residential exchange to a power sale so the benefits are not at risk, she explained. "That is the political reality, and that is why we are talking power instead of money," she added.
At less than average water, it would cost BPA from 0 to 5 mills to buy and meld power to serve an additional 1,000 MW, Keep continued. This shows the risk of setting rates based on average water if you get low water -- you need to marry this up with a risk strategy, he added. Have you thought about the risk of providing dollars versus power to the exchange? an aluminum company rep asked. Cash is "hard-wired in," and power is not, he added. Another participant suggested the IOU resources freed up by the exchange could be made available to BPA.
If BPA's current power resources do not meet the load, is there a different way to get to the same spot? a public agency rep asked, suggesting a "financial arrangement" could make sense. There's a political problem, a public interest rep said. What if, for example, you sold all BPA power at market and gave PF customers cash instead of power, he posited. It's a "politically dangerous deal" that you can't guarantee like you can a power contract, he said. A participant pointed out that the Northwest Power Act allows IOUs to meld the cost of their resources with the federal system. "Most of the mischief" from the residential exchange provisions took place in the region, a public agency rep said.
If we don't settle this issue, "it unsettles everything else," a public interest rep said. The PUCs would have jurisdiction over any IOU resources freed up by the exchange, he noted, adding that it could take years to broker a solution that involves connecting those resources to an exchange purchase. But reaching an exchange power sale may be equally unlikely, a public agency rep suggested. There may be a combination of cash and a power sale that could serve as the first step in a deal, a public interest rep suggested. Group members agreed to mull things over before continuing to discuss the exchange.
An IOU rep said a subgroup met to talk about cash management and uncertainties posed by such things as water conditions and changes in system configuration. One of the ideas is for BPA to sell the right to purchase in advance of a power delivery, he said. BPA would negotiate a way for customers to pre-pay and secure future rights to purchase, he explained. An aluminum company rep said if the largest revenue problem for BPA would occur after the 2001 to 2006 rate period, "we should start looking at a longer-term arrangement." Several of my clients are thinking about longer-term arrangements and internalizing the risks of the system within contracts, he said. Off-ramps become important under these circumstances since "no one is going to take on big risks like system reconfiguration," he added.
Would you try to identify the potential costs of such risks over a 10-year period? a participant asked. That's one way, the aluminum company rep replied. My clients see both market and cost risks, he said, and the cost risks need to be capped. BPA would have the ability to adjust rates, and there would be off-ramps, he explained. We find it "totally unacceptable" to divorce long-term risks from benefits and believe there is a group of customers who would "take a shot at the risks for a shot at the benefits," he added.
Could you relate this to the "options" mechanism we concurred on four months ago? a public interest rep asked. Under the options concept, BPA accumulates money up front, whereas this is a tool that is used only when necessary, an aluminum company rep responded. We did not see the option fee "as storing dollars in the mattress," but a mechanism that would be triggered when it is needed, the public interest rep answered.
We're more interested in a contract that is "coterminous" with a rate we know, a public agency rep said. Have we settled the question that a preference customer without an option would not have a claim to power at PF' ? a public interest rep asked. They have the right to return, but price is the issue, a customer rep responded. BPA's position is that the price for the returning customer would be different from the price for the customer "who stayed the course," but a utility may want to fight that, he added.
One big issue is how one party's contractual form could affect the risks and costs of others, a customer stated. Maybe this is a place we need standard terms across all contracts, he suggested. BPA seems to have the potential for cash flow problems, and I'd be interested in contractual terms that we can show DOE to say we have dealt with stranded costs, an aluminum company rep said.
We have two options, a participant suggested: come up with standard contract language about recovering costs not covered by the rates, or put together a mechanism that actually does it. There is a third option -- we can sign what BPA offers and say, "hey, that works," a public agency rep stated. If we deal with the financial uncertainty in contracts, the stranded cost issue becomes smaller, a public interest rep pointed out.
What is DOE's current view of stranded costs? an IOU rep inquired. DOE has indicated it "does not want to weigh in and wants the region to come forward with a proposal," according to Bob Procter of BPA. He said in presubscription contracts, BPA tried "to hold the wires open for costs," adding that in its Issues '98 process, BPA will offer something similar to the "Smith/DeFazio" proposal, which is a wires mechanism with FERC designing the allocation. The Administrator would have discretion to implement the mechanism, and appeals would go to the Ninth Circuit, Procter explained. "We had to put a stake in the ground someplace, knowing there would be disagreement," he stated.
I'd propose "a cost recovery stack" that includes reserves, option revenues, and a CRAC, a public interest rep said. Those get you a long way toward covering the costs in the first rate period -- a transmission surcharge would be "the last resort," he stated.
Do you intend to leave the post-2006 period uncertain and plan on a wires charge? an IOU rep asked. We have several alternative ways to deal with this in the contracts, another participant responded. We can do 2001-2006 contracts and worry about what to do next in 2005, or we can get into longer-term deals, he said. The notion of signing a 20-year contract "does not pass the laugh-out-loud test," a public agency rep replied. "We took a 20-year bite last time, and now we want to take smaller bites," he said. Where we go now depends on what we are trying to solve -- if we're trying to solve a problem that occurs between now and 2015, "we have a hell of a pickle," he added.
The problem is achieving subscription in a way that Treasury says is adequate, a public interest rep said. I'm trying to see that we end the rate period with healthy reserves so we have something to take to DOE that says the Northwest has gone a long way to solving its problems, he added. BPA ought to internalize the power risks into power rates, an aluminum company rep said. You are asking them to exclude the transmission system, and "I'm not ready to go there," a public agency rep responded.
What cash flow and cost recovery mechanisms are we willing to agree to? an IOU rep asked. I don't want shifting of unrecovered costs onto the wires where they are paid by my clients, who did not have the opportunity to participate in the benefits, she stated. The group listed several options for cost recovery, including: appropriate level of reserves, prepayment of power for later delivery, contractual rights with an option fee, and a CRAC. A pre-sale of post-2006 power is not mechanically doable for the Washington PUDs, a participant stated.
If we talk in the abstract, "we create fear and loathing," a participant observed. If we put this in context of what we know about the problem, it won't be as insurmountable as it seems in the abstract, he added. We could take the presubscription approach, which includes standard language that BPA's and a customer's legal rights "are what they are," a public power rep suggested. I'd suggest long-term, adjustable-rate contracts with off-ramps, an aluminum company rep said. We ought to consider a prohibition against wires fees, he stated. BPA's bottom line is it has to cover costs, a customer rep responded.
What is the magnitude of the problem? a participant asked. If we had a common understanding of the range of risks, we could put together an inventory of tools, he said. We've done a lot of that analysis, a Council staffer said. You haven't considered the costs in a rate case environment, an IOU rep pointed out. The Council staffers said they would distribute their analysis of potential future costs to the work group.
We can talk about contract provisions to align the risks and the benefits, an IOU rep said. For example, with the level of reserves, what are you starting with and what do you build into rates, she stated. All of the customers have advocated tying dam removal to congressional de-authorization, she pointed out. Can we carve out that cost from what we need to recover? she asked. The Congressional decision should be tied to how to fund the removal, a participant agreed. Then you need a contract provision that says, "the cash management mechanism will not include dam removal," the IOU rep stated. Adams suggested that a small group work on building the steps for addressing the cost recovery issue.
If we are trying for a package, I'm willing to talk, a public power rep said. I can talk about these mechanisms, but you have to have a package for BPA to stay whole, and BPA has to be able "to go to the wires," he stated. If the power customers are taking the risk without the wires as an option, "you won't come to closure with me," he said. We are talking about ways for BPA to meet costs without going to the wires first, a customer said. "We in no way see a wires charge as the first horse out of the gate," Procter stated.
Would you deal with a wires charge affirmatively in the contract? Adams asked. I would, and if others won't, that's a problem, a public power rep said. Are you saying this is a mechanism we have to keep on the table, that even before we impose cost-based rates, we need a wires charge? an IOU rep asked. If people are saying they will spend 90 percent of their energy on the topic of reserves and other mechanisms because we can't have a wires charge, I'd say "let BPA propose something," and we'll see how we like it, the public power rep responded. A wires charge is part of any solution -- it's needed to secure the net-billing agreements, another public power rep said.
Is it sufficient for BPA to say in the contracts that it has authority to impose a wires charge? an aluminum company rep asked. BPA says it has "unfettered authority" to impose a wires charge, a public agency rep responded, and he suggested the reason to include specific contract language is to limit that authority -- "you can say, this is what we'll pay, but no more." He pointed out that if such provisions were to apply to everyone, they would need to go into transmission and wheeling, as well as power sales contracts. The reciprocity issue will get interesting, an IOU rep observed. We ought to have another plan, she urged. "There could be a stampede for long-term transmission," a public power customer said.
The participants agreed a small group should develop a comprehensive package and bring it back to the work group.
BPA intends to be ready to make subscription sales starting July 1, according to BPA staffer Scott Wilson. He offered the latest version of nine contract features, ranging from the types of contracts that will be available to the treatment of customer resources. There were a number of questions and comments and a suggestion the group revisit several items on the list. I have a problem with that -- there has to be a more productive way than "a group grope," a participant stated. The concern is in areas where BPA starts to allocate the risks and rewards, an IOU rep said. If we are not all accepting some level of risk, "the wheels will come off this buggy politically," he stated. What you're suggesting is that the partial-service contract not impose any more risk than the full requirements, a BPA staffer observed.
You need to fly the provisions by the customers, the IOU rep suggested. This is not a decision group -- we are trying to come up with principles, a BPA attorney stated. We would need to have a Record of Decision if we put out contract language, he said. You need to fly some trial balloons, the IOU rep responded. What if there is not agreement? another customer asked. We'd proceed, the attorney responded. Our mission is to sell power -- what comes out of this group are principles and guidance, he stated. Will we see the principles or will this be done contract-by-contract? a customer rep asked. Contract-by-contract, the attorney replied.
Let's have a list of the 10 most important issues next time so we can focus our discussion, a customer rep suggested. At some point we need to declare that we've given enough "air time" to some issues, Adams observed. I'd like to know what BPA is going to do, a public interest rep said. It's not good for BPA politically to have these decisions come out piecemeal, he said. BPA should be able to state its position -- at least in a verbal report or a brief paper, a participant agreed.
Archive of content originally posted or last updated on: June 15, 1998.
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