Tapping the Energy Efficiency Resource (Transcript)

Summary: Presentation at the February 22, 2006 Council meeting by Ralph Cavanagh and Jim Lazar, experts on utility regulation, talking about how removing regulatory barriers (decoupling) can make conservation a win-win for utilities and their customers.

Also see video of the presentation.

Transcript

Karier: Welcome everyone. If everyone could have a seat, please. We’re ready to start. This afternoon for the first hour here we have a discussion about decoupling and someone pointed out to me that there is one side that will be arguing about decoupling and the other side will be arguing for coupling, I guess that’s the opposite. This is an issue that came up when the Council developed its Fifth Power Plan and we looked at the regulatory incentives about conservation, and we knew that this issue was an important one to resolve in the Northwest. Fortunately we have two experts with national reputations with expertise in this topic. So they have generously agreed to be here and I think I’m going to turn this over to Charlie [Grist] who is going to do the introductions and set the rules.

Grist: What a good turnout. I get the pleasure of introducing these two guys. On my far left is Mr. Ralph Cavanagh. Ralph joined the Natural Resources Defense Council in 1987 and he has been

Cavanagh: 1979!

Grist: Excuse me, I’d better put my glasses on. That’s what it says here. So 1979 where he’s been defending the nation’s resources and environment ever since. He is senior attorney at NRDC; he also co-directs the NRDC’s Energy Program. He has been involved in the regulatory affairs of the West, the Northwest and California, for decades and he has really proven to be a tremendous asset for positive change in energy efficiency and environmental matters ever since. And I really mean that, Ralph.

Cavanagh: Unlike most of his introductions!

Grist: Ralph is the founding father, for example, of both the Northwest Energy Efficiency Alliance and I think had a hand in creating the Northwest Energy Coalition that you all remember. I have a word of warning about Mr. Cavanagh - he is a fast talker. So don’t blink!

Now, on my immediate left is Mr. Jim Lazar. Since before the Council even got started, Jim has been a consulting economist with expertise in electric and natural gas ratemaking and resource planning. He engages his expertise in rate cases, regulatory forums and authorships on articles on innovative resource planning and incentive regulation for utilities. He consults around the world on regulatory projects, including here in the U.S., Canada, New Zealand, Brazil, China, India, Indonesia, the Philippines, Namibia and I think Mozambique. If I didn’t include some countries, please forgive me. And if any of you have ever found yourself on the other side of the table from Ralph in a rate proceeding, and I hope you haven’t, you’ll understand why he’s widely regarded as a fearsome opponent in those proceedings, and well respected.

So, Jim, too, has been a great resource to the Pacific Northwest on mattes of energy efficiency and policy. A strong ally for the Council’s mission ever since the get-go; and he sits on the Council’s Regional Technical Forum.

So between these two guys we have something like 25 years of combined experience

Lazar: 50 combined.

Grist: Jim is way better at numbers than me. Fifty years combined experience on the issue of reducing disincentives to conservation for utilities through the making of rates. We’re lucky to have them both here to explain the nuances of this issue. We have a format set up. There is an outline that is floating around here that these two gentlemen have agreed upon. It consists of six parts. Each of them will address three parts of this outline. They will alternate discussing each of these three parts of the outline; six parts total; with equal time allocated to each man. They can split their 15 minutes any way they like, but when your 15 minutes gentlemen is up, you are done. And we have prepared for you a clock, chess clock, which the men will use to time their presentations. So when you finish with your section, hit the space bar and the clock will switch over to Mr. Lazar and back and forth you’ll go. Fifteen minutes. Are there any questions. There will be some slides. I’m at your beck and call. Any questions from the audience.

Cavanagh: Thank you Mr. Chairman. It is an enormous privilege for me to resume a conversation with this Council that for me began at the very first meeting of this body. It is also a great privilege to have the conversation with my friend and colleague of many years, Mr. Jim Lazar, and if he should from time to time fall into error in the minutes that follow, I want you all to know that a career of contributions to the public interest in the Northwest will more than overwhelm any modest affront that I will feel in the process. And I think you’ll be intrigued at where we agree and where we disagree.

Now the issue before us is really I think best understood is how to get the incentives right for some of the most important institutions in the region, who are dealing with our top priority resource - energy efficiency. And the question there, and what I’m going to try to do in my introduction here is to lay out the problem and a solution. And we’ll return to it. Jim and I won’t exhaust this issue in the next 30 minutes, and the most important part of this program is the interchange with all of you. But it couldn’t be more timely. Now the fundamental problem is - and from the very beginning when energy efficiency investment by utilities as a resource, as an alternative to power plants, was invented here in the Northwest, and from that point in the late 70s and some of you were present at the creation, the issue has risen repeatedly - how can utilities be reliable, committed partners on energy efficiency when their financial health is tied to how much electricity they sell. Now this is a real problem, but my principal message is it is a problem that is relatively easy to solve, the solutions are at hand and all four Northwest states are grappling with them at the moment. We have a chance to get this under control in a sustained way, really for the fist time. And I think it is urgent that we do so because although I take enormous pride in the region’s record on energy efficiency over the last 25 years, there is an undeniable roller coaster pattern to that record. Stops and starts, strong progress at times of stress followed by periods of inattention and of serious fall-off, and that’s documented superbly in the Council’s website.

So how do we end the roller coaster? Well, a critical part of ending the roller coaster in my opinion is breaking the link between utilities’ financial health and the amount of electricity they sell to their customers. Now first of all, why is there a problem? Many of you would expect if utility sales drop, well the cost of buying power and fuel would drop at the same time, so what’s the problem when utilities sell less in terms of their financial health? The problem is that utilities recover in addition to the variable costs, fuel and power as electricity use goes up and down; they are recovering in their kilowatt hour charges also the fixed costs that are needed to keep the system up and running and recover the costs of investments already made. Every kilowatt hour sold has a chunk of fixed costs embedded in it. Usually 40 to 60 percent of the cost of that kilowatt hour represents fixed costs that don’t vary with the amount of electricity used. Now you could solve that problem by inflicting whopping fixed charges on every customer so that you paid a big electric bill regardless of how much you used. Neither Jim nor I thinks that’s a good idea. So the question is: is there anything else you can do to break the link between the utilities’ financial health and the kilowatt hour sales on the system. Charlie, if you could put up the one slide that I had asked you for. I wanted to just give you a quick illustration of just how big a problem this is using one of our hometown utilities in the Northwest. This is from my testimony last year before the Idaho PUC. Every year the Idaho Power Company needs to recover about $300 million to just meet the fixed cost needs of its system. That’s the authorized fixed cost revenue requirement that the Commission has approved. And the Commission, when it sets rates, adopts a forecast or approves a forecast of kilowatt hour sales and in order to recover that $300 million, Idaho Power needs to hit the forecast, needs to sell the number of kilowatt hours assumed when the rates were set. If Idaho Power sales are less than the forecast, they won’t hit their authorized fixed cost revenue requirement and obviously their financial health will be adversely affected. To give you a sense of the magnitude of the problem, for this small to medium-sized utility, about 1,800 average megawatts of sales, call it 2/3 the size of PGE in terms of annual kilowatt hour use by its retail customers. If Idaho Power is successful in persuading its customers to use 1 percent less in a year, there is an automatic hit in terms of reduced recovery of fixed costs of about $3 million. You keep it up for five years, five years of saving 1 percent a year, and I hope no one here thinks that’s an impossible challenge, and you’ve got a $40 million plus penalty to the company, automatically and invisibly delivered, even it if recovers all the costs to the conservation programs. So as punishment for doing well on conservation, Idaho Power gets hit with a reduced recovery of the fixed costs that it was authorized to recover by its regulator.

What do you do about this? Well, the decoupling solution is to introduce a small regular true-up in rates. Every year you compare how much they actually recovered of that $300 million in Idaho Power’s case, how much they actually recovered, compare it to the amount they were authorized to recover and true-up. If they under-recover, they get it back the next year; if they over-recover, which is possible if sales go up, they have to give it back. So decoupling is not an automatic rate increase or reduction, it is an adjustment to make sure that the company’s ability to recover the authorized fixed costs that its regulators approve, isn’t affected by changes in kilowatt hour use. I think that’s a good idea. I’ll leave to Jim the next part of the introduction.

Lazar: So where did coupling come from in the first place? Simply stated, utility rates are the quotient that results from dividing costs by sales. Rate design is a little more complicated than that, but that’s really the basic formula. Coupling is a result of the traditional regulatory framework together with some very good public policy decisions by regulators. The two key elements are the use of what we call test year ratemaking and the use of rate designs that generally look forward to long-run costs, don’t look at short-run costs. Both of these are great ideas on their own; they have some unintended consequences for the sharing of risk and for energy efficiency programs. In setting rates, either at a public utility or a private utility, the decision makers use what we call a test year to measure costs, revenues and sales volumes. They set rates that are designed to produce the right amount of revenue based upon a normal level of costs and a normal level of sales. There are a lot of ways of measuring a test year; Washington and Idaho are historic test year jurisdictions; Oregon is a future test year jurisdiction; Montana kind of does things its own way. Test years look at the actual or budget years data and then make adjustments to the costs and revenues and sales volumes based on known and measurable changes. All of the adjustments are subject to controversy and that’s pretty much what rate cases are about. Weather adjustments - huge controversial issue. Rate of return, big controversial issue, and they go on from there. But there are a finite number of adjustments and the participants in the regulatory process focus on the ones that are important. The basic theory is that as new customers come to the system sales grow, expenses grow, investment grows, and revenues grow all more or less in lock step. Now of course costs and revenues and sales and weather don’t exactly follow the script. When things get out of line and profits decrease, utilities file for rate increases. When things get out of line and profits increase, utilities run and hide from the regulators and typically are successful for a while. Utility investment in energy efficiency is a deliberate attempt to deviate from the script of growing costs and revenues and sales. You are spending money to reduce sales when the formula is based upon increasing sales, producing the increasing revenues to cover the increasing costs. That’s where decoupling or other alternatives can have a role. Under some circumstances, reduced sales increase profits. I believe this is currently the case for both Idaho Power and Pacific Power because their retail rates are lower than wholesale market prices, and any kilowatt hour not sold at retail can be sold at wholesale with a larger profit margin. For the BPA-dependent utilities, typically their prices are well above the BPA wholesale rate, and if their sales decline in the short-run, they lose distribution margin as Ralph has described, and their net operating income declines. Now if BPA had tiered rates, most of the publics would be in the same situation as Pacific and Idaho, reduced sales would avoid about as much wholesale power cost as the utilities would lose in retail revenue.

Cavanagh: The other thing that I think is important for the Council to be considering as it looks at this issue is just where are we in terms of our regional consideration of the fundamental question of what incentive do utilities have to pursue conservation? What are we doing to make sure that utilities that do it well are more profitable or in better financial health than utilities that do it poorly? And as Jim has just properly acknowledged, this is an issue for both public and private power. Public power doesn’t have profits, but it has the same issue of recovering its fixed costs, covering its debt for investments already made. This problem of an adverse linkage between reduced use and financial health is there for both public and private power.

So where are we in the region; where are we nationally on this issue? Nationally, the upsurge in utility investment in energy efficiency of the early 90s caused an interest in these issues which was overtaken almost immediately by the upsurge also in the interest of restructuring the electric industry and taking utilities out of the business of investing in energy efficiency or any other resources. In systems that restructured and took utilities out of the resource investment/resource management business, obviously decoupling is not an issue, resource procurement is not an issue, the utilities are out of the game. For utilities that are staying in the game, which is in most of the country and all of the West, these issues are resurfacing now with a vengeance. So as Jim mentioned, in Washington this is before the Washington Commission in the context of PacifiCorp where there is a joint proposal by NRDC and PacifiCorp before the Commission; in Idaho a proposal by Idaho Power which NRDC supports is before the Commission; Montana is looking hard at this issue as Northwestern confronts the implications of the significant expansion of conservation investment that the Council’s recommendations will require. And here in Oregon, the Oregon Commission has really been leading with Northwest Natural on the natural gas side, adopting a decoupling mechanism that has been widely praised and I think approved with a very compelling independent review that the Oregon Commission requested. So the issue is very much on the table but unresolved. We’ve got important decisions to make. In California, a state I almost never mention in this room without a curl if at least not to my lip, to most of the lips in the room, it is important to note that this decoupling system has basically been in place and it is part of the regulatory landscape. It has been around since ’81. It was briefly suspended in the late 90s when California, as part of an adventure in electric restructuring remembered fondly by no one in this room, decided that a nifty thing to do would be to freeze electric rates indefinitely. From time to time that has had some political appeal in the Northwest as well. Of course if you freeze electric rates you can’t do modest regular true-ups in rates, which I’m suggesting is the obvious solution to this problem. And so California dropped its decoupling mechanism when it adopted the rate freeze. What happened next is well known by everyone in this room. It is an experiment no one in California is inclined to repeat. The decoupling mechanism is back in place and is supporting greatly enhanced energy efficiency investment. And the one respect in which I think it useful to invoke California to this audience is that for the first time in my career, working in both California and the Northwest, there is now a gap of 50 percent in terms of the relative level of effort on energy efficiency between the California utilities and the Northwest utilities. That is, as a fraction of system use, California is trying to save roughly 50 percent more than the Northwest. I find that intolerable. And I urge that one of the reasons to me to take seriously the prospect of getting these incentives right is to get us back on track to recovering all those lost opportunities associated with the efficiency we know is out there and cost effective but that we’re not getting at the moment.

Lazar: There are a number of alternatives to decoupling that I think merit some consideration. The first and the one that we have for most of the private utilities is to have some high-cost resources on every system. We have pretty low average costs in the Northwest but our short-run marginal costs, burning gas, and our long-run incremental costs, building wind farms, have costs that are quite similar to what the rest of the country faces. By happenstance, the costs of our short-run resources and long-run resources are about the same as our rates. Pacific Power’s current rates in Washington average about 5.4 cents, 3 cents for power, 2 1/2 cents for delivery. But if sales increase or decrease, Pacific’s choice is to run the Hermiston gas-fired plant, buy power from the market. If sales decrease it can sell power to the market or back down Hermiston, and all of those have costs that are about the same, maybe a little higher than their revenues. The key here is that Pacific Power is not an island utility. The example that Ralph provided applies to an island utility, and I do a lot of work with island utilities. It doesn’t have just a single generating resource that it can ramp up and down; it has a portfolio of resources from hydro and coal with very low running costs to gas with much higher running costs. It can sell into the market; it can buy from the market. Their short-run marginal costs are about the same as their long-run marginal costs; about the same as their retail rates. In economics we call that equilibrium. Gas is the marginal resource in the region and up and down the West coast. And if every utility sees the cost of gas as a marginal cost of power, then they are going to see something that looks a lot like the retail rates. If their sales go up, they won’t increase their profits; if their sales go down, their profits won’t decrease. I also have one table that I want to share with you that looks at Pacific’s rates in Washington of 5.4 cents a kilowatt hour. Pacific projected the average wholesale rate over the next five years would be 6.9 cents a kilowatt hour, meaning every lost kilowatt hour of retail sales increases their profits by a penny and a half. The very circumstance that Ralph posited for Idaho if applied to Pacific would make the company a $10 million profit if customers conserved 1 percent a year, but if you superimpose on top of that the reimbursement for fixed costs that NRDC proposed of another $21 million, the company would have a $31 million bonus from the decoupling mechanism. Decoupling has to be done right. But if you have high-cost resources, you may be decoupled anyway. So have some high-cost resources in the mix. If the function of decoupling is to make utilities profit neutral to changes in sales volume, I think the Ralph proposal for Pacific Power went a little too far.

The next alternative is what we call a lost margin recovery mechanism - is to simply calculate how much energy the utilities’ conservation programs saved, calculate how much profit they lost as a result of lower sales volumes and give them a credit in their ratemaking formula to recover that. It is nothing more. There are a lot simpler and smaller, limited in scope, than a decoupling mechanism. You are only truing up the efficiency, not the variations of sales volumes, which can vary due to business cycle, vary due to weather, vary due to a lot of factors. But lost margin measures are not just better than decoupling; they are also worse. They can create perverse incentive to fib about how much energy programs are saving, and for utilities to take credit for things they didn’t actually do like energy codes and appliance standards. I’ve worked in Hawaii with a lost margin recovery mechanism, and I’ve witnessed that perverse incentive.

The third alternative is a rate design based on short-run marginal costs, and Ralph alluded to this. A BPA-dependent utility that can get all the power it wants for about 3 cents a kilowatt hour could simply set rates of $30 a month plus 3 cents a kilowatt hour and it is decoupled. If its sales go up, revenue goes up by 3 cents, short -term costs go up by 3 cents, profits/net income doesn’t change. Same thing if sales go down. And many of BPA’s public utility customers have moved this way, with monthly fixed charges as high as $25 compared to about $6 for the private utilities in Washington and zero for the private utilities in California, under California’s decoupling mechanism. What’s wrong with that? Well the big problem is it encourages excess of usage. Because the end rate is a lot lower than the incremental cost of power. It is unfair to small users who must pay as much as big users for access to the system. And really that’s not how markets work. Airlines have high fixed costs but they recover their costs one seat at a time. Oil companies have high fixed costs for refineries and pipelines, tankers and wells, but they recover those costs one gallon at a time. Actually this problem is one of the key reasons that led to the passage of the Act and the creation of this Council. Public utilities through the rate design were inviting growth based on penny power when new resources were costing nickels and dimes. But one clear way that Bonneville could address this would be to implement any of the many tiered rate options to insure that essentially every customer sees the much higher than BPA market prices as their short-run marginal cost of power, these short run marginal costs through the wholesale rates through the retail rates to the customers.

The final option I want to talk about is -I’ll call it conserveco, is to take the conservation responsibility away from the utility and give it to somebody else. Give it to somebody who doesn’t have the conflict between achievement of cost-effective results and enterprise profitability. Oregon has done this with the Energy Trust. Vermont has done this with Efficiency Vermont, and frankly, both are working very well. I’m highly attracted to this option; my experience has been that stand-alone efficiency companies take their work very seriously, don’t get sidetracked and provide excellent value to billpayers. They can cooperate and coordinate with utilitiesto put extra focus in geographic locations or seasons where it’s needed. I urge the Council to work with BPA and the state commissions to implement the Energy Trust concept regionwide.

Cavanagh: There are a number of alternatives to decoupling which Jim outlined that he doesn’t very clearly doesn’t believe in and I join him in his skepticism. Let’s dispense quickly with those. The option of trying every year to calculate how much the utility saved or helped to save and “give them back that money” is untenable. The incentives are perfectly perverse. The most profitable conservation programs are those that look good on paper and save nothing in practice, because then you double recover. You are faced with waves of cumulative cost increases over time because every year you have new lost revenues to recover on top of last year’s programs and once you’re four or five years in, you have a cascading problem. And it’s an unwieldy litigation-driven mess, whereas I’m talking about an annual adjustment in rates that’s pretty much automatic and that requires the equivalent of a single employee with a calculator and a half-hour of spare time and one afternoon a year. I’m talking about adjustments based simply on comparing the actual recovered fixed costs with the authorized and truing up. I am not talking about a litigation-driven effort to calculate how much you save from every program. I think Jim is right to say that’s a bad idea. Jim is also right to say you shouldn’t solve this problem by inflicting very high fixed charges on customers so that the utility recovers its revenue regardless of how much energy they use. That kills off conservation incentives and is unfair to customers that use relatively little energy like low-income customers.

Where I think Jim goes astray is in two places. First of all I don’t have a problem - he thinks you solve the problem if you introduce an independent body that is in charge of the conservation programs. I have no problem with the Oregon Trust model - I love the Oregon Trust, but I think it works best when the utility is a partner, an engaged partner, a supportive partner, which I think is exactly what we’re heading to in Oregon. Not either/or, but both. And the model we want is one in which all of the participants are engaged and motivated, including the hometown utility. I don’t want to leave them out. I want them as a partner in the process because I’ve seen how well they can do, working largely in my case with utilities across the entire region, all of which have a great story to tell on this score. So I don’t want to give up on the possibility of a motivated partner in an Oregon Trust if we have an Oregon Trust and of course in the other Northwest states we don’t. But Jim therefore is I think driven to - the one place where we disagree is his suggestion that the wholesale market solves the problem. That whenever retail sales go down, no problem because there’s a wholesale market. You can just resell into the wholesale market, so what’s the problem? Well, the problem as everyone here knows who is a historian of wholesale power markets is that over time wholesale markets are almost always well below retail markets. The situation Jim is describing is a bizarre historical anomaly in that at the present wholesale markets are temporarily above the retail markets, but if you look back over the quarter-century and more that we’ve all been doing this together, Jim will not be able to show you a table in which that has persisted for any length of time. So I think it’s fair to say that no utility in the region takes seriously the prospect that it can make up in the wholesale market what it lost in the retail market. If Jim could predict gas prices five years into the future with confidence, he would have no need to be spending his time as an undercompensated public interest economist. And his calculations, the wonderful calculation he put up on the board, basically presumes that he can predict, or PacificCorp to be fair can predict, because he is using PacifiCorp’s prediction, what will be happening to gas prices over the next five years. I will note that between the time that Jim filed his testimony opposing NRDC’s proposal that the present wholesale gas prices dropped in half. It is a tremendously volatile market and the notion that you could count on wholesale revenues to solve your problem is I think flawed to begin with and further flawed as I want to assure my Idaho constituents. In the state of Idaho any revenues earned in the wholesale market by Idaho Power have to go right back to the customers. So they are not available to solve the decoupling problem and that’s a pretty strongly embedded tradition in most regions and for most utilities. Jim is right that for PacificCorp in Washington that is not the situation at the present time. There isn’t such an arrangement in place. The Washington commission is now in the process of deciding whether to adopt one. But the wholesale market isn’t the answer for most utilities most of the time, both because it is usually well below retail, and because utilities making transactions in the wholesale market have to give their gains back to customers and I think that’s a principle many in this room would support.

I am left therefore again to return to the fundamental point, though. I hope what the Council will do is keep its eye on and indeed it has over the course of its history, the importance of getting the incentives right on energy efficiency. And that has two dimensions. And this is the point I should make in closing. One is to remove the financial obstacle associated with the decoupling issue that Jim and I have been talking about. The other is to create some prospect of reward. Decoupling is a necessary but not sufficient condition. You also want those who do well to have a chance to do well by their shareholders and customers by being able to share some of the gains that conservation brings. And if you think about it from the standpoint of a utility executive, you can earn on transmission lines, you can earn on power generation, where are your earnings opportunities on energy efficiency? And the answer in most of this region is depressingly slim and we need a good answer to that question in addition to the decoupling question, but my view is with all of the region’s regulators engaged, with you paying attention, we’re going to get there. Many thanks.

Lazar: Decoupling represents a pretty significant departure from traditional regulation. And my only concern is that it may significantly impair the principal benefit of traditional regulation, which is a strong incentive for utilities to control their costs. It also represents a significant shift of risk from shareholders to billpayers, particularly with respect to sales variations driven by weather and the business cycle. Electric ratepayers need to get something for taking on this risk. The package I think can be better for investors, better for billpayers and better for the environment. So I want to talk about some elements for fair and effective decoupling. First, the utility needs to make a significant commitment to invest in energy efficiency. A utility that is granted a decoupling mechanism needs to make a commensurate commitment to invest in all available cost-effective efficiency. This means meeting or beating the Council’s targets. California utilities are doing better than the Council’s targets, and we can, too. For many utilities it is a modest increase, although within both the public and the private utility sectors there are some eagles and there are some turkeys. This was not a part of the Pacific Power proposal that Ralph and I debated earlier this year. The second element is progressive rate design. Under decoupling utilities no longer have concerns about either revenue stability or sales volumes. Therefore, they should embrace rate designs that clearly reflect long-run marginal costs for all incremental sales for all classes of customers. The California utilities have moved this way with zero customer charges and very steeply inverted residential rate designs that start at 11 cents and go up to 33 cents. BC Hydro is doing so for all of its classes. The highest allowable monthly service charge should cover only meter reading and billing expenses -- those that are really incremental with the customer, maybe $5 a month. The end blocks of service should represent the long-run incremental costs of peak-period power supply plus the long-run incremental costs of peak-period transmission and distribution capacity. That’s in the neighborhood of 10 to 12 cents a kilowatt hour. This was not a part of the Pacific Power proposal that Ralph and I debated earlier this year.

Third is a capital structure adjustment. Utilities typically carry about 45 percent equity in their capital structure. Equity is the expensive part of the capital. Debt is the cheap part. Because the rate of return is high and taxes are high. A utility that is protected from the effects on net earnings of sales variations due to weather and business cycle and other factors by decoupling needs less equity because its earnings aren’t as volatile. Booth Moody’s and Standard and Poors have recognized that risk mitigation means a need for less equity. A lower equity capitalization ratio means lower bills to consumers, without reducing the rate of profit that the shareholders receive. There are simply fewer shares because there don’t need to be as many because the earnings aren’t as variable. In the Pacific Power case that Ralph and I debated, I calculated that a 2 percent reduction in the equity ratio would mean about a $1 million savings, which would be enough to increase the conservation budget Pacific had to exceed the Council targets. I think that’s a conservative estimate of the benefit of decoupling alone on the capital structure. This was not a part of what Ralph and I debated earlier this year.

Fourth is a collar on rates. Decoupling should not result in huge swings on customer bills. An increase or decrease of more than 3 percent in any one year should be avoided and spread out over two or three years. This was a part of the proposal that Ralph made in the Pacific case that we debated earlier this year.

And finally there should be scheduled periodic rate cases. Historically regulation has been based on cost and the test-year mechanism has worked quite well for about a century keeping revenues in line with costs. Decoupling on a revenue per customer basis is a significant departure. We shouldn’t let it go too long without a reality check back to costs. The California utilities do rate cases every three years. That seems like a reasonable interval, but that was not a part of the proposal that Ralph and I debated earlier this year.

There you’ve got five elements. I think put together decoupling can be a positive. Without the elements it is not.

Karier: Thank you. And we’re going to open it up for questions but I didn’t know whether you wanted a last comment on the five elements.

Cavanagh: Not allowed. If the Council Members want it, I’ll be happy to do it.

Karier: Okay, we’re opening it up to questions. Actually I had one which was a story I read in the paper, and I think it was the state of Missouri which had passed a decoupling kind of procedure and then energy prices went up because of the context of the recent run-up in energy prices and in response the customers cut back their consumption and the decoupling mechanism required an additional increase in prices. Once people realized it they were befuddled I think by the implications of the decoupling. What happened was a rise in prices because of fuel prices and because of decoupling caused another price increase, and in response there was kind of a political uproar about what did we do here, and there is at least some kind of effort to roll back decoupling. So can decoupling create those sort of impacts?

Cavanagh: This is why I think Jim is right to say that an important aspect of the mechanism to remove this objection. The objection in Missouri was not well taken, but it became a political football, and the way you avoid the political football is you collar the amount of rate impact a decoupling mechanism can have. I’ve analyzed all of the major Northwest systems now. I think you can make this system work within at most - the 3 percent limit that Jim proposed is I think reasonable, and I would not expect any Northwest system to exceed it in order for the mechanism to operate and I would not frankly expect any system anywhere in the country to exceed it. And then the question becomes is a 3 percent adjustment up or down politically impossible? And you look at what that means - it is about a nickel a day for the average customer. It is probably not the stuff of populist rebellions most of the time in most of the country. What you do have to be careful - I think what the real populist anger in Missouri was over the bill increases associated with rising gas prices, which were real and substantial. And of course the best antidote to that is an expanded energy efficiency effort to take the pressure off the system. And Jim is also therefore I think right to insist that part of this has to be a visible commitment by the utility system to very significantly expand its conservation effort, and that allows them to show that they are doing their part to help customers cope with the real problem, which is the underlying rate increases from the fossil fuel price increases, which are a lot more than 3 percent.

Lazar: After the decoupling mechanism was implemented in the state of Maine and my colleagues in the regulatory assistance project were on the Maine commission at the time that it was implemented, it went along for several years with very small changes, but then the industrial economy of Maine went into a pretty serious slide and there wound up being very substantial decoupling adjustments to customer bills. And the residential and small commercial customers quickly figured out that they were getting the burden of the declining industrial sales and the mechanism was terminated. There are some lessons from that which I think Ralph has learned. One is leave the industrial customers out of the mix because their usage is volatile due to causes unrelated to conservation programs or weather or the other sorts of things that decoupling typically addresses. But clearly - I disagree with Ralph - I think you can exceed 3 percent very easily. I think Northwest Natural will exceed 3 percent in its warm mechanism, in either a very cold or a very warm year.

Karier: Okay, any questions. From the audience or anyone on the phone? Member Eden.

Eden: Thank you, Mr. Chair. The first thing I wrote down at the top of this outline was what Ralph or Jim said was reducing disincentives and that led me to the question that one of you asked which was “Where’s the benefit in the incentives? I think Jim said “where’s the earning benefit on energy efficiency?” And you zoomed through the five elements pretty quickly. I wonder if there’s a larger answer to that.

Lazar: In 1980 I lobbied the Washington legislature and successfully got for 10 years an increment in the rate of return allowed on energy efficiency investment over and above the rate on other utility investments. It proved out to be a badly designed incentive. The incentive was to invest as much as possible to get a high bonus return but to invest it in things that don’t actually save any energy so you don’t actually lose any sales or sales margin. So the design of incentives is crucial. We had another incentive mechanism in place for Puget in 1990 or so that was based on the quantity of conservation that they did and the cost of that. They took advantage of that mechanism, machined-gunned 700,000 low-flow shower heads in the sky, saved a whole lot of energy at very low cost, saturated one out of 10 identified markets, actually under-performed in 9 out of the 10 target areas, picked the cheapest one and seized the design of that incentive and made a bunch of money off of it. The commission caught on and killed that incentive and it killed incentives for many years thereafter. There design of the incentive needs to be very, very carefully put together or it will be gamed.

Cavanagh: But it can be done and the principal - it really is important to stay focused on this because of course if you don’t the only earnings opportunities a utility has are associated with power plants and transmission lines. So Jim got it exactly right but then the prescription is there for the incentive you want is performance driven, not tonnage of capital invested, but how much economic benefit you’re delivering to your customers. The Council has a rigorous methodology for helping you to assess how much you are saving from conservation compared to the alternative investment. The right incentive principle is shared savings. The utility gets to keep a fraction of the savings but it has to perform well across the full spectrum of programs that it offers. All of these principles are in the process by the way of being adopted right now in California as incentive mechanisms for energy efficiency, so there is an earnings opportunity. We need to do it here. There isn’t an earnings opportunity associated with conservation to my knowledge for any utility system in the Northwest. There are large earnings opportunities associated with coal-fired power plants and high voltage transmission lines. If we believe that this is our highest priority resource. If we believe that this is our best hope for an affordable and sustainable energy future, it is crazy that that situation persists. And I hope the Council Members will join us in encouraging their colleagues in both the utility regulatory sector, and also the public power dimension to this by the way is incentives to employees. I think Jim and I both feel strongly about this. If you ask the question, “how are employees compensated; what portion of their bonuses at the end of the year reflects the conservation record of the utility?” Is there any utility in the Northwest that ties bonuses to conservation performance? I’m not aware of one at the moment and that’s telling you something about how important management thinks it is to the financial health of the enterprise to do well on conservation, and we’ve got to do better on that.

Karier: Any other questions?

Nancy Hirsch on the phone: This is Nancy Hirsch with the Northwest Energy Coalition. Thank you to the Council for hosting this very informative and timely discussion. I won’t call it a debate. I was wondering if Ralph could talk a little bit about the progressive rate design concept that Jim talked about and the way they are doing it in California, and whether that would be a proposal that has merit in this part of the country.

Cavanagh: Sure. What I understand Jim to mean by progressive rate design, and I agree with him, is that the principle ought to be that the more you use, the more you pay. The discredited alternative was the norm in the Northwest for many of the years following World War II. Now recognize that at the retail level the more you use, the more you pay, which means that the customer is paying more and more as their use goes up. It worsens the problem decoupling is designed to solve because more and more of your revenue is associated with those last few kilowatt hours, and if consumption goes down the impact on the utility’s financial health is disproportionate because you’re charging more for those last few kilowatt hours. So at the retail level progressive rate design makes the problem worse and makes decoupling even more important. I think Jim is right that at the wholesale level if Bonneville were to adopt such a system it would be a helpful step in the right direction in terms of giving better incentives and better rate signals to Bonneville’s wholesale customers, but I don’t think he was making that claim in the context of retail rates where the progressive rate designs that both he and I favor make it even more important I think to do these annual true-ups on its revenues. Imagine PG&E is making 33 cents a kilowatt hour on the last few kilowatt hours of sales and those are the kilowatt hours that are first to go when the conservation program kicks in. In the Northwest the progressive rate designs are a whole lot less steep, but even in the case of PacificCorp in Washington, PacificCorp is charging more for the last few kilowatt hours than the first few and it underscores I think the perspective that I have on the need to solve the problem.

Lazar: If all of the utility’s resources had the same cost, what Ralph is describing would indeed be a problem, but they don’t. The inverted rate designs in Washington for Puget, Pacific and Avista can be looked at as selling the limited amount of hydropower at a hydro cost plus delivery. The limited amount of coal power at coal cost plus delivery, and the variable amount of gas-fired generation at a price that reflects the cost of that gas-fired generation. It is a cost-based inverted rate design. It recognizes that the usage in the tail-block, typically space heating - in cold winters there is a lot of usage; in warm winters there is not - is a risky load to serve and that should carry a cost premium. So it is actually not worsening the problem for a utility that has a portfolio of resources that includes some low-cost, stable-cost resources - hydro, coal, nuclear, whatever they might happen to be - and utilities that have some high-cost, variable-cost resources like gas. The problem for the Bonneville-dependent utilities is while Bonneville sees the market price, it is either a buyer or a seller in the market at almost any time, and it is seeing that 6 cent market. The wholesale customers are not. The situation in California is pretty radically different. The average revenue for Pacific Gas and Electric and Southern California Edison is about 15 cents a kilowatt hour. Their incremental market price is about 6 cents, the same as ours. The average rates for our Northwest utilities is pretty close to 6 cents, very close to the market rate. If the Northwest utilities see the market rate, they shouldn’t have very serious impacts on net revenue as sales volumes change, whereas the California utilities from a 15 cent base absolutely will, even if their average costs, because their average costs are way above market marginal incremental, short-run incremental, long-run incremental, any measure of the cost that is incurred by the utility when sales volumes change.

Karier: So you’re saying decoupling makes more sense in California than it would here.

Lazar: It was invented in Maine where you had 10 cent utilities with a 4 cent incremental power market. It grew up in California where you had 15 cent utilities with a 6 cent power market. It makes a tremendous amount of sense. All of the problems Ralph describes are very true in a system where the short-run marginal cost is dramatically lower than the system average cost. In the Northwest I think our problem is that particularly the Bonneville-dependent utilities don’t see the market.

Cavanagh: It is however sobering to recognize - Jim has made the case as persuasively as only he can for why any sensible utility executive looking at the current market, looking at the current price trends, would go after conservation with everything they had - and would have been doing so for a number of years now. It is sobering at least to recognize that the actual record of performance has been somewhat different. So the sobering thing to take away is the utility leadership across the region appears to have a somewhat different perspective than Jim does about the nature of the opportunity and since they really matter in this equation, it is important to look at it also from their perspective which is what I’m trying to do and see if we can make things better in a way that also makes things better for customers. Jim has added a lot of tremendously useful suggestions there, I want to emphasize that to all of you. I think he’s going to have a profound effect on this. I hope he doesn’t in the end prevent the effort from going forward because the notion that everything is fine the way it is, which he could be heard to be saying just doesn’t square with the experience all of us have had in watching the actual performance of our utilities.

Lazar: One thing, I did actually do a regression of utility executive compensation against sales volumes and yes, there is a linear relationship. Executives of bigger utilities make a lot more money than those smaller utilities, measured by sales volume. The relationship to revenues is actually much weaker than the relationship to sales volume, so if you are trying to get - we do have a little problem out there in the way executive compensation works. The state commissions could address that. They could tie allowable executive compensation to measures of performance that matter to consumers, including energy efficiency programs or noble energy acquisition/customer service, that sort of thing.

Karier: With that I want to thank our guests for coming and giving us a very enlightening presentation.