The Giga-NOPR

The Giga-NOPR

October 01, 2002

The US government published 600 pages of proposals at the end of July that the newspapers said could transform how electricity is produced and sold in the United States. The following are excerpts from a discussion that took place by phone in mid-September among a group of regulatory experts. The experts addressed whether the new proposals — called a “notice of proposed rulemaking,” or “NOPR” — are as significant as the press claims and, if so, why and what is in them about which any well-informed CEO of a power company or banker lending to finance power projects should be aware. The speakers are Julie Simon, vice president for regulatory policy at the Electric Power Supply Association, Vito Stagliano, vice president for transmission policy at Calpine Corporation, David Reich, senior manager, technical and legal analysis, at Mirant Corporation, Dr. Robert Weisenmiller, one of the leading experts on the California power market and a founder of MRW Associates, Inc. in Oakland, California, and two Chadbourne lawyers, Lynn Hargis, a former assistant general counsel of the Federal Energy Regulatory Commission for electric utility regulation, and John O’Sullivan, who held the same position as Hargis at FERC and was later chief advisory counsel to the commission. The moderator is Keith Martin.

MR. MARTIN: Global Power Report said in an article on August 8th:“The Federal Energy Regulatory Commission has taken probably its most sweeping and profound action ever to define the electricity marketplace . . . .” An Energy Business Watch flyer for a seminar said the giga-NOPR will “profoundly transform the wholesale electricity markets.” Julie Simon, is the giga-NOPR really that significant, or is this an exaggeration?

MS. SIMON: Yes. It’s a huge next step for the federal government to recognize the need for a single transmission tariff to ensure that all users of the transmission system take service under the same tariff conditions. From our perspective, representing the competitive power supply industry, inability to get access to the grid on equal terms with utilities has probably been the biggest impediment to workable competition in the industry. For FERC finally to recognize this and to take steps to remedy it I think is incredibly significant. MR. MARTIN: Dave Reich, do you agree with that assessment?

MR. REICH: Definitely. I echo what Julie said. This is truly huge. Taking decisions about use of the grid away from the investor-owned utilities — requiring them to turn the grid over to an independent transmission provider — will go a very long way to complete open access for anybody who requests transmission service. It will do away with a lot of the discriminatory behavior that independent generators have had to put up with for the last few years. MR. MARTIN: Vito Stagliano, isn’t there more to the gigaNOPR than just more open transmission?

MR. STAGLIANO: Yes, though I view it as less earthshaking perhaps than does the press. It is important to see it in context. FERC issued this new proposed rule in order to rectify its 10-year failure to address discrimination in the wholesale power market. It had issued two previous orders, both of which were essentially ignored by the utilities that control the grid. This new order is simply one more in a series that began with Order 888 in 1996 to try to address a discriminatory situation. It also establishes a rational market in which to trade wholesale power, but the anti-discriminatory part of it is, in my view, the most important aspect of what the FERC is doing.

MR. MARTIN: Bob Weisenmiller?

MR. WEISENMILLER: On the significance, it is an attempt to take the idea of comparability of service to its ultimate resolution. Along with that, the federal government is trying — with standard market design — to put in place the remaining pieces of the puzzle that one needs to get workable wholesale power markets.

Single Transmission Tariff

MR. MARTIN: Moving to what the government has actually proposed, Julie Simon, what should bankers and CEOs of independent power companies be aware has been put on the table?

MS. SIMON: The single tariff is probably the single biggest thing. I think the push towards a standardized market design is also very, very important. We’ve seen that, as power markets develop, for a whole host of reasons — ranging from just the way people are used to doing things, to software development and so on — you can have real disconnects between markets that interfere with the free flow of power or so-called seams that prevent power from being moved easily between regions where it can be best used. As you drill down, there are some other really important concepts in the NOPR itself. The Federal Energy Regulatory Commission’s approach to market monitoring is very significant. There will be a very strong role for the market monitors in the regions, as well as the FERC staff, to play with respect to market monitoring. There is an indication that the government is interested in invasive approaches, similar to those that are currently used in New York and California and with which we are less than comfortable. We think well-designed markets should not require this type of intervention. Then there is the proposal — which is new from the FERC’s perspective — of a resource adequacy requirement—

MR. MARTIN: Julie, let me stop you there and focus on the single transmission tariff. What does “single transmission tariff” mean?

MS. SIMON: You have a situation currently where utilities are required to charge independent generators the same tariffs they use for their own wholesale transactions, but not for their bundled retail transactions. Under the new proposal, there will be something called simply network access service. It is a single approach. Everyone using the grid will be subject to the same tariff and the same requirements for scheduling, information disclosure and so forth. This new network access tariff will be used for all of grid services, including the transmission component of bundled retail service that the utilities currently secure for themselves, sort of offline from the current open access tariff.

MR. MARTIN: I read in one of the flyers for conferences on the giga-NOPR that “the sweeping changes in transmission pricing could dramatically increase sales by low-cost suppliers into distant higher-priced markets.” Vito Stagliano, do you think that might be one result from a single transmission tariff?

MR. STAGLIANO: It is the not the single tariff that will ensure that, but rather the requirement for equal access to the grid. It is possible currently for an independent producer to be interconnected to a local grid, but without having the ability to move its power on to the grid or beyond, because of congestion or because the local utility has laid first claim on the scarce capacity on the grid for moving its own electricity. The NOPR will address the issue of how equitably everyone will have access to that grid. This is a necessary step in creating a competitive market. This access issue, and the discrimination that is associated with it, were at the core of two previous orders by FERC in 1996 and 2000. The fact that the federal government has had to issue this new NOPR is evidence that what it did earlier to address the discriminatory access part has not worked to date.

MR. MARTIN: Dave Reich, are there potentially other consequences to this part of the NOPR — the single transmission tariff and equal access? MR. REICH: Actually, there are. FERC has set up the transmission pricing so that the “load,” or person buying the electricity, will pay for transmission service when it ultimately takes power off the grid. FERC wants to vest control over the grid in “independent transmission providers,” or “ITPs.” In the future, you would be able to move your power from grid section to grid section controlled by different ITPs without having to pay a separate transmission component to each ITP. Thus, load in a distant service territory could contract with a distant independent generator and be able to buy power across several systems, and not have to pay transmission charges except to the ITP where the load is located.

MR. MARTIN: Anyone else, are there potentially other consequences to this part of the NOPR — the single transmission tariff and equal access?

MS. HARGIS: Just one thing: a lot of the opposition to the NOPR has been from regions of the country that feel they have low-cost power and are afraid that that low-cost power will leave and go to other areas where people are willing to pay more. FERC responded that this will not happen because utilities in these regions are free to contract long term for their power and keep it at home. This regional conflict has spilled over into Congress. The governors and regulators from these low-cost regions are trying to get Congress to block implementation of the NOPR.

MR. MARTIN: Which regions of the country are most concerned about their low-cost power going elsewhere?

MS. HARGIS: The South and the Pacific Northwest, and parts of the West.

MR. MARTIN: Another thing in the NOPR — Julie, correct me if I’m wrong — is that utilities will be required to turn over operating control of their grids to third parties by — is it 2003?

MS. SIMON: Yes. I am not exactly sure of the deadline because it may have been extended.

MR. MARTIN: Is that new, or is that something FERC has been trying to do all along?

MS. SIMON: It has been trying to get to this concept of independent control over transmission for many, many years.

MR. MARTIN: Let me return to a concept we were discussing a moment ago. One expected consequence of the NOPR is there will be no more favoritism for native utility load. Is this because of the single tariff or because an independent party will control the grid or for another reason?

MS. SIMON: It is the result of two things. One is the independent control. The other is the requirement that utilities use the same tariff for their own native load service, because that is where a lot of the discrimination has crept in. They could do a lot of things to favor their own uses of the grid. It was very hard to get behind whether such uses were legitimate or not. The tariff numbers were not verifiable. The ongoing discrimination that companies like Mirant and Calpine have been wrestling with for years were largely a result of that distinction. Now there will be a single tariff and the grid will be independently managed. I think we have come a really long way. I think you need both. An independent operator, without a single tariff, will not get you very far.

MS. HARGIS: One other thing worth noting is that the federal government is asserting jurisdiction for the first time over bundled retail transmission — not just unbundled transmission. Bundled retail transmission rates have been left until now to the states. Included in that single transmission tariff that Julie is talking about is the retail tariff.

MR. MARTIN: What is the difference between “bundled” and “unbundled retail transmission?”

MS. HARGIS:“Bundled” is where the prices for the electricity and for moving the electricity are bundled together in a single rate. States historically had jurisdiction over that transmission as part of the retail rates. “Unbundled” is where each component — for example, the electricity as distinct from the transmission of it and the distribution of it — are priced separately. The state still has jurisdiction over the retail charge for electricity, but the federal government will not assert jurisdiction over the rate for retail transmission.

MR. MARTIN: Why should generators care whether FERC has asserted or extended its jurisdiction?

MR. STAGLIANO: Because it is very difficult for independent generators to determine how much capacity there is on any particular grid as long as there is a lot of bundled retail native load laying first claim to the grid. 12% Reserve Margin

MR. MARTIN: Dave Reich, FERC said in the giga-NOPR that it would like to see a national reserve margin of 12%. What does that mean, and how would it get there?

MR. REICH: This is part of the resource adequacy proposal. I think the federal government is going to leave some discretion to each regions to determine what an adequate reserve margin might be for it. For example, there would be some discretion for the West to have a higher reserve margin because of the amount of hydro resources. Other parts of the country might decide that 12% is okay. I think what FERC is trying to address with this proposal is to prevent future shortages and price spikes. By putting in place a nationwide reserve margin, there will be more uniform investment in new generating plants across the country, more stable prices, and basically a much better market situation.

MR. MARTIN: What does it mean to have a reserve margin — that there is unused extra capacity to generate?

MR. REICH: The independent transmission provider, or grid operator, will be charged with maintaining the reliability of the grid. As part of that, it will have to make forecasts of electricity demand and supply. You want the ability to call on additional supply that is in reserve for contingency purposes.

MR. MARTIN: Did you say the states will have, in the first instance, to make decisions about how to provide for that reserve?

MR. REICH: FERC is looking at trying to bring the states in as much as possible. They are better situated than the federal government to determine what level of reserves are necessary so that their retail consumers will be adequately served reliably. MR. MARTIN: Vito Stagliano, where do you think the reserve will come from?

MR. STAGLIANO: We all hope that the utilities will contract with independent generators for this incremental capacity. The resource adequacy requirement is a challenge to the states by FERC to take responsibility for ensuring there is sufficient supply to meet local needs. This is in sharp contrast to the position that California took a couple of years ago, where it assumed the electricity would come from somewhere and that it had no responsibly to ensure enough local capacity was being built to serve local needs.

MR. O’SULLIVAN: I think that is right on the money. The NOPR was a complete rejection of California’s idea that spot markets would provide pricing that would attract investment, in considerable part because the political system will not tolerate freely floating prices. It will not tolerate the kind of high consumer prices you see during periods of capacity shortage. It insists on price caps, but — at the same time — there is no rush to provide price floors during periods of excess capacity to balance out the lost revenues of the independent power producers that result from the price caps. I think this is a rejection of the idea of short-term markets as the primary market. It signals a return to a longterm contract regime as the basis for most power.

MR. MARTIN: Bob Weisenmiller, you made an interesting comment in June at the Chadbourne conference in Quebec. You asked:“Who is going to build power plants to supply the reserve margin ‘just in case’?” Is it reasonable to believe independent generators can be the source of the reserve margin?

MR. WEISENMILLER: To get to the properly functioning market, you must address the question who will pay for the spare capacity. What FERC seems to be saying is let’s move to a contract approach, as opposed to, say, a merchant plant approach, where people would build plants on the assumption that — when the markets got tight — the pricing would cover their costs, even if it was a one-in-three or one-in-five year occurrence. As John said, we now know that when that one-in-three or one-in-five-year price spike occurs, it will be politically unacceptable. The only way you can really get that additional capacity is with the contract model. Now, the government must still work out a lot of details in terms of how much reserve is required and who pays for it. In the West, an issue will be who is creditworthy enough to contract? Actually, given the current state of the industry, creditworthiness has become an issue on both sides of the equation.

MR. MARTIN: Any other thoughts, anyone, about the 12% reserve margin before we move to the next topic?

MR. STAGLIANO: Yes. It is a major policy decision by FERC in the sense that the federal government has accepted the fact that they are probably going to be unable to create entirely competitive wholesale power markets. So it will rely on long-term contracts in order to meet the requirements of customers. That is a kind of revelatory position on the part of FERC. One of the issues in California was the fact that the market was dysfunctional within California. Had there been a market that covered the entire Western interconnection, then we probably would not have had the crisis that developed in California in late 2000 and 2001. FERC is conceding the limitations. It assumes that California still will have only a California market and that the rest of the country will have localized, regional or subregional markets that cannot be made entirely competitive. It could have gone the other way.

MR. O’SULLIVAN: I read it as a broader rejection of the notion that as-available power in spot markets is the same thing as long-term committed capacity. It is a rejection of the economist’s model that says short-term pricing will pay the owner of each type of generation an amount to cover the difference between the cost of a peaker and the cost of his plant. FERC has said, whether or not that is true in the abstract, we now know the political system will not tolerate the high prices in times of capacity shortages that are necessary to make investment in generation economically attractive. In any event, the investors no longer trust the regulators or the markets, so they will not invest, and we will not have enough capacity. There is a very big question that Lynn Hargis started to raise about whether the FERC has the legal authority to do what it is doing, but I think it is doing exactly the right thing.

MS. HARGIS: The question I have is how does this part of the NOPR fit with curing undue discrimination in transmission? What does FERC point to as its legal authority for this part of the NOPR?

MR. REICH: This is one place where I do not think FERC went far enough. It is merely recommending that loadserving entities contract for the amount of reserves they need; instead of putting in place a mechanism to ensure the reserves, FERC merely put in place penalties for parties who fail to do it.

MR. MARTIN: So this part of the NOPR is a little disappointing?

MR. STAGLIANO: It is less disappointing than it is not very well thought out. FERC believes that local load serving entities will assume the responsibility for contracting for all the electricity they need, plus a reserve margin. It may be, in the end, that those load-serving entities will find it simpler merely to pay the penalty in the spot market when they run short than to commit themselves to longterm contracts with people who will provide reserve capacity.

MR. MARTIN: I read somewhere that utilities will be penalized if they are short on power and have to take from the spot market during a shortage. You just referred to this. What is the penalty in such cases?

MR. STAGLIANO: The penalty would be the equivalent of whatever the spot market price would be at that time. However, since the spot market price is subject to price controls imposed by FERC, in terms of both a regional bid cap, plus an automatic mitigation procedure, the utility already knows how much exposure it is likely to have, and it may prefer to accept that price rather than negotiate a long-term deal.

MR. MARTIN: So there is no separate penalty; it is just the utility will have to pay spot prices during periods of shortage? MR. STAGLIANO: That’s right.

MR. O’SULLIVAN: There is also a suggestion that when there have to be curtailments, the systems that are short will be the ones curtailed first.

Price Caps

MR. MARTIN: Next topic: Julie Simon, the NOPR proposes circuit breakers or price caps designed to limit the prices that generators can charge. How does this work? MS. SIMON: It creates what is called a “safety net bid cap” of $1,000. The idea is that if prices are running up quickly, some amount of demand would, under normally competitive circumstances, get off the system. But we don’t have in place yet all the right mechanisms to send those price signals and let load do that.There is also the concept of “must-offer obligations” that would be negotiated in participating generator agreements in particular locations in order to address more limited kind of load pocket problems.

MR. MARTIN: So this part of the notice — the bid caps and must-offer obligations — are they aimed at dealing with California-type problems, or are they aimed at a broader problem? MS. SIMON: I think both California and broader. They are aimed at preventing future Californias. We will have mechanisms in place before the fact with which people can work so that we don’t get into the kind of crisis mentality we had in California. However, I think the thing that they are really doing with respect to California is approving an “AMP,” or “automated mitigation procedure.”There is a requirement that if an independent transmission provider wants to use additional mitigation — that is, beyond the $1,000 bid cap and the limitations in the participating generator agreements — then it must come back with some kind of a showing that such steps are warranted. This is an important recognition that the type of heavy-handed approach that was used in California can be counterproductive for encouraging new investment. A lot of power plants that were planned for California are being put on hold right now.

MR. MARTIN: Because of the price caps, or for other reasons?

MS. SIMON: It is a combination of reasons. But frankly, the current price cap in California is $91.68, or something like that. That is not the right price signal for power plants that are on call for periods of peak demand. It is hard to build a peaking plant at that level of return.

MR. MARTIN: Other thoughts from people on the call about this part of the notice, the part designed to deal with market distortions or disruptions? Why is this significant for generators? What should a banker or CEO of a generator take from it?

MR. STAGLIANO: Its significance for generators is that FERC thinks it must impose price controls in order to respond to the politics of marketing power. Markets do not operate efficiently with price caps, no matter what the level of those price caps is. Rather than focusing on creating a broader, deeper, more liquid market that goes beyond the limitations of a single region or a single state, FERC fell back to the loud demands of the state utilities commissioners who would like to see wholesale prices limited to some extent by retail rates. I think that is what the NOPR does.

MR. WEISENMILLER: Another point to take from this discussion is it will be very important what the precise details are and how this part of the NOPR is implemented. It has not been particularly well thought out. You could see a lot of investment put on hold until the industry learns the details.

MR. O’SULLIVAN: That investment is on hold now anyway, isn’t it?

MR. WEISENMILLER: Yes, but it may remain on hold while people are working through how this part of the NOPR will be implemented.

Tradable Transmission Rights

MR. MARTIN: Dave Reich, we have talked so far about the single transmission tariff, the requirement that utilities turn over operation of their grids to independent third parties, the 12% national reserve margin, and the bid caps and must-run obligations. Is there anything else in the giga-NOPR that is important for generators to know?

MR. REICH: Underneath the single tariff, there are the congestion revenue rights that FERC proposes to create and that would be tradable.

MR. MARTIN: What are those?

MR. REICH: Basically, you would have a defined path from point A to point B on the grid. What the commission will put in place is locational marginal pricing, so that every point will have a price associated with it and if there is congestion, there will be different prices between the two points. That price difference times the amount of power flowing between the two points is congestion revenue. A customer who holds a congestion revenue right between point A and point B could avoid paying the congestion revenue between those two points.

MR. MARTIN: What are the tradable rights?

MR. REICH: FERC has proposed that each point-to-point customer and network customers would have congestion revenue rights based upon their historic usage of the grid. Paths such as the A to B example would be assigned to each transmission customer based upon his historic transmission usage. A customer could trade or sell the right associated with those paths to receive or avoid congestion revenue to another company that values those rights more than the original holder of the congestion revenue right. Over the course of a 4-year transition period, the commission will probably move to an auction approach, where you would go from basically physical transmission to financial transmission. That’s also a pretty big step under the NOPR.

MR. MARTIN: Have we covered all the main points about the giga-NOPR or is there anything else people want to mention?

MR. STAGLIANO: I believe that we have covered the main points.

Subtle Consequences

MR. MARTIN: Does the call by FERC for a return to a longterm contract regime offer some hope to generating companies that — without waiting for everything else to be sorted out — we can start getting back to financeable contracts?

MR. STAGLIANO: My sense is that comfort in the industry will not come until all of these cases before the FERC, brought by people challenging previous contracts that were entered in good faith, have been resolved satisfactorily. I will withhold judgment as to what is acceptable in the marketplace until all of these challenges have been settled and we see where we come out.

MR. MARTIN: Dave Reich, do you agree?

MR. REICH: Completely. It’s hard to take comfort in the notion that we will voluntarily enter into a long-term contract, and that the terms of the contract will remain in place over the life of the deal, when customers are still filing complaints, and the commission is still setting them for hearing, and we are stuck having to litigate the terms and conditions of contracts that were mutually agreed to when the contracts were signed. Until those cases play out, there is really not a very high comfort level going forward.

MS. SIMON: I think what the commission has done is to reopen the question of who should be building new power plants.

MR. MARTIN: How so?

MS. SIMON: Seventy-five percent of the investment in generation that has been made in the last three years has been made by the competitive industry. I think the question that the NOPR is asking — not directly, but it is raised indirectly by the resource adequacy portion of the NOPR — is, are we going to go back to integrated resource planning and have utilities build generation again? Our side of the industry has proven that we can build stuff faster, less expensively, cleaner and so forth. But I think some people may take this as an indication that the utilities are meant to get back into the building business. It is not at all clear that we will continue to build 75% of all of the new capacity in this country.

MR. MARTIN: So FERC has thrown that decision about who builds back to the states?

MS. SIMON: I think indirectly FERC has thrown it back to the states. FERC has not totally left it up to the states. But for example, one of the things that we have been talking to people about is a requirement that the resource adequacy be competitively bid. There is no requirement in the NOPR for that type of an approach. Now, FERC may have just taken that for granted. However, it is something that I think we must raise in the comments. I think FERC has been intentionally vague in the rulemaking because it did not want to dictate to the states how they could be involved in this process. FERC has opened the door to a partnership here. It really wants to work with the states, and the NOPR is not particularly prescriptive about how this will be done.

MR. O’SULLIVAN: It also raises a question for regulatory lawyers as to who would have the authority — depending upon how this adequacy initiative is structured — to approve the prudence of utility purchases. Is it the states or the federal government? Generally, since most of the electricity was ultimately going to retail customers, the states have done most of that. But I think it is possible, just as the FERC is declaring its jurisdiction over the transmission component of retail sales, that it could also make pre-emptive judgments about the prudence of a purchase — if it has the authority at all under the Federal Power Act to go ahead with the resource scheme.

MS. SIMON: There’s an additional problem that I think we’ll hear in the comments from some of the utilities that are under rate freezes.

MR. O’SULLIVAN: You are exactly right.

MS. SIMON: Some of the utilities that are currently under rate freezes are very concerned about whether or not they will be able to ensure a flow-through of costs in state retail rates. That will be for the lawyers to sort out.

MR. O’SULLIVAN: Assuming FERC has the authority to begin with to do the resource adequacy part of the NOPR, if FERC approves the prudence of the purchases, then that is probably pre-emptive; that is, the states would be under an obligation under the supremacy clause of the US constitution to allow the utilities to recover their payments.

MR. STAGLIANO: My belief is that instinctively, state regulators will feel much more at ease if the new capacity that is built is somehow integrated into the rate base, thereby avoiding questions about whether or not a particular contract is prudent. It is for this reason that they feel much more comfortable with rate-based new investment. We now have anomalous situations in places like Louisiana, where the local monopoly utility is actually talking about building a new nuclear power plant. The last time I looked at the economics of nuclear power plants, they worked only when the investment was written off as stranded investment, not when it was newly made. So, we are going to encounter, I think, difficult situations in most states, where there will be this tension between what the state public utility commission would rather do, and what would otherwise make economic sense to do.

Timetable

MR. MARTIN: Julie Simon, what’s the timetable for this NOPR, comments and then what?

MS. SIMON: FERC issued an extension of the comment deadline last week, and so comments are now due November 15th, with reply comments due December 20th. I think that makes it unrealistic that we will see a final rule in the first quarter of 2003. I expect them to get a final rule out in the late spring. Others may have other ideas. Then the implementation is obviously going to take place over a number of years. There are different phases of implementation. For example, the congestion revenue rights that David Reich mentioned are initially allocated and then transitioned to an auction over several years.

MR. O’SULLIVAN: You have to allow in your schedule for litigation. MS. SIMON: Normally, FERC’s approach is not to incorporate that into their process. It assumes that you don’t unscramble these eggs. It has a pretty good track record of winning the big ones. So FERC generally puts these things into place, everybody gets used to them, and litigation goes on a parallel track. To date, no court has been willing to stay any of these FERC rulemakings, but obviously, that would be a huge delay if a court were to actually stay implementation of the rule pending some type of judicial review.

MR. O’SULLIVAN: If we were looking for renewed investment in generation or transmission, that is not going to happen until the litigation risk is gone, right?

MS. SIMON: I think it’s hard to know. I think the power prices right now are sending a signal that there is adequate investment for the short term. If you look at the NERC reliability studies, at least through 2005-2006, we are seeing very high reserve margins. Obviously, we have a lot of regulatory uncertainty and a lot of overhang in the industry for a whole host of reasons. But a change in any one of those reasons could turn the industry around. If the economy were really to pick up, for example, and power prices were to begin to reflect the reduction of a capacity margin, people might respond to price signals very quickly. They do not need to be $6,000 price signals in order to make new investments. But obviously, the more stable a regulatory climate, the better for additional investments.

MR. STAGLIANO: The trouble with the FERC schedules is that they almost are never real. We were on one schedule with Order 2000, which has essentially been abandoned by the new schedule for this NOPR, which may drag out for the next four to five years. What that really means, aside from the uncertainty for new investment, is tied to the issue of what you do with the investment that is already in the ground. The discriminatory regime that the FERC is trying to address with the new NOPR, will remain in place until the final rule takes effect, which means that we have, at least in my view, four more years of slogging through the present unhealthy situation before we get to a probable, although not a definitive, end with a competitive market.

MR. MARTIN: Does anyone believe that the uncertainty surrounding the rules during this period that the NOPR is being discussed will make it harder to finance new projects?

MS. SIMON: I don’t think it makes it easier. But as Vito said, and as I said earlier, I think project financing turns on a ot of criteria, and regulatory certainty is obviously one of those. The more certainty the better for investment in general, but that is not the only factor at which people look. Overall, this NOPR is definitely a positive for the industry.

MR. MARTIN: Dave Reich, you are in Washington. Is there any danger that Congress will block parts of this?

MR. REICH: We have certainly been monitoring that. There are members of Congress who would like to delay its implementation.

MR. MARTIN: Western and southern regulators are the most unhappy with this. Is this because of the potential export of low-cost power that Lynn Hargis mentioned earlier?

MS. SIMON: I think it comes from, in many cases, a concern that their vertically-integrated utilities are not going to retain the competitive advantages that they have currently, which is obviously — as we’ve been talking about for the last hour — the goal of this rulemaking. I think in some states, there is also a real hesitancy to trust a federal approach right now.

Final Thoughts

MR. MARTIN: Let me try to sum up and ask for reactions. It seems that one part of this proposed rule is a single transmission tariff and equal access to the grid. That part is seen universally by generators as a plus. Does anyone disagree?

MR. REICH: It is a huge plus. It is also one of the things that can be implemented very quickly by FERC.

MR. STAGLIANO: I tend to be a skeptic about the ability of the FERC to police what it issues as orders. This discriminatory issue has been around ever since we’ve all been around. FERC has simply not been able to resolve it. So the fact that the FERC issues an order, or several orders, is no guarantee that it will impose discipline to comply with that order on the part of the people who should.

MS. SIMON: I understand where Vito’s coming from, but I think this is historic in the sense that the FERC for the first time is asserting jurisdiction over the transmission part of bundled retail service. Regardless of whether or not FERC accepts the independent power industry comments on the notice, the statement in this rulemaking that the federal government intends to go down this path — it is huge and should not be underestimated. It is a sea change in terms of the federal government’s willingness to attack the problem of discrimination.

MR. MARTIN: The next part of the giga-NOPR is a mixed bag from the generator’s view — the national reserve margin of 12%, the notion embedded in the proposed rule that there ought to be more long-term contracting for the power. For generators, it is a move in the right direction, but the details have not been filled in and, when the details are filled in, they could lead — at the end of the day — to more construction of new power plants by the regulated industry, not by the competitive industry. Is that a fair summary?

MR. STAGLIANO: If the resource adequacy requirement is market-driven — in other words, if it is managed through some sort of open bidding process — then the possibility of addressing it correctly is high. On the other hand, if it relies entirely on bilateral arrangements, in the absence of a competitive bidding process, I believe that it will have problems being implemented.

MR. MARTIN: Dave Reich, do you agree?

MR. REICH: No, not on the bilateral part. As long as the states have some sort of competitive bidding process, like Julie Simon was talking about, where we can compete and the decisions are based upon who is the lowest-cost supplier, and then you enter into a bilateral contract to provide the electricity, then those kind of details will work for us.

MR. MARTIN: The last segment of the giga-NOPR is the circuit breakers, price caps, things like that. Is it fair to say that generators are not especially pleased with this part of the giga-NOPR, because of the potential for distortion in price signals and the potentially deleterious effect on new investment?

MS. SIMON: We have real problems with the way the mitigation is currently designed in the rule. The commission recognizes some important concepts about the need for generators to recover their investments. There is some positive language in the giga-NOPR for the first time. The proposed mechanisms are problematic. However, the commission has recognized some important things about the interplay between price mitigation and the need for people to recover their costs in some type of a capacity payment. FERC had not shown it understood this before. The commission has not taken the right steps to fix that problem, but it has at least recognized the problem. That is important.

MR. O’SULLIVAN: There is language in the NOPR indicating that the commission is not convinced that, even without constant price caps or the constant threat of price mitigation, there will be sufficient investment in generation on a timely basis to avoid the sort of vicious circle of capacity shortages and high prices and the re-imposition of price caps. FERC said the fact that the political system has been so ready to oppose price caps effectively moots the debate; investors will not invest where they’re shaved on the high side and not supported on the low side.

MR. STAGLIANO: A key issue with the price mitigation part of the NOPR is, how much discretion will be allowed to the states to apply the mitigation measures? If FERC allows flexibility in implementation to permit regional variations, then you can be sure that the regions will take full advantage of the variations that they want. California is already unhappy with the $92 price cap that is currently in place. I don’t know how it will be happy with the $1,000 one. The issue is how all of this laudable intent will be carried out in practice in different regions of the country.

MR. REICH: This is where the devil is in the details. Depending upon how the commission decides to price those mitigation measures, they could have a chilling effect on the market.

MR. MARTIN: Bob Weisenmiller, you get the last word.

MR. WEISENMILLER: I think you started out with the question of is this really important. I think we have hit the ways that the giga-NOPR could reshape the industry. FERC has articulated a vision. It wants to move away from the merchant plant model to more of a long-term contract model, and it has articulated an intention to involve the states in that process. We are moving in the right direction.There is an awful lot of work to be done,and there are a lot of details still to be filled in."