Can you not at LEAST accurately word your premis? That SUBSIDIZED renewable energy is a risk?

One would think that to make that case, one would at least use an accepted basis. Instead, the author makes the case that renewables are variable and unpredictable but then uses a flat baseload graph to show that the ratio of peak load has increased 20%. Which is it? Logic would dictate that each region should be considered on the ratio of each type used there and the amount of spinning reserve available. Consider wind (fully unpredictable but biased against peak) vs. geothermal (baseload) vs. solar (fairly predictable but biased toward peak) and you'll see different energy risk amounts.

The idea that subsidies for renewables in general creates a monopoly is also false. A monopoly has market control that can be weilded over its competition. Is this really possible with the heavy competition between the different renewables for said subsidy? IMHO, it simply removes a portion of the entrenched monopoly.

In comparison to any rational evaluation of total subsidy estimates (see above, ranges from $4 billion to $1 trillion), $4 million is quite small to cause so much concern from authors in this site. What's the real problem?

I don't really understand this article.

The author cites 'QF' without explaining what it is. Let's see....

Hmm, I think QF refers to "Qualifying Facility". So I think the disaster the author refers to was the PURPA regulations of the 1980s. This led to the poorly executed windfarms at Altamont and other places, and in general, a lot of waste. OK, I get that.

But like so many other utility-perspective folks, the author quickly tosses in a what? 20% renewable load into a location? Instantaneously? Is that realistic? I've had this same complaint about utility folks before. They scream bloody murder about the problems of 10-20% renewable load, so that we can't even get it to 1% to see how the darn thing will work.

As they say, "Lead, Follow, or Get Out of the Way". And utility interests do not seem to be showing leadership, nor are they willing to accept leadership from others.

As solution to this problem (the author does not provide one, as far as I can see) I would suggest more liberal pricing/subsidy for renewables up to a certain amount of baseload (say 1-2%) and then re-examine things at that time.

Rather than writing a report on the problems with (renewable) energy subsidies, why not write a report on how our entire utility system will not and cannot encourage energy conservation, because it attacks their bottom line? [Even though this is clearly in the consumers' and the country's best interest.]

I admit I don't understand the mindset of utilties as they fret about pennies when their whole world (onset of lower cost renewables, likelihood of a carbon tax, potential for PHEVs, options afforded by smart metering, etc.) is on the verge of massive changes, whether they care to acknowledge them or not.

Since we are going there, the major impediment is the HUGE free rider problem. If I install a renewable at my location, I get the benefit of not paying for electricity. Every OTHER user on the system is getting: reduced competition for dispatched power (open markets advocates should be unanimous that the impact should be to reduce prices for everyone else); reduced need for infrastructure - both transmission and distribution - reducing need for utility investment with resulting increase in reliability. But the person installing that renewable gets nothing but the reduction in their bill.

The problem is that there are all sorts of economic inefficiencies in the existing system. This article was not an assault on renewables - that's why the term wasn't in the title. And, yes, subsidized energy is better but, currently, nuke and coal don't have a carved out market place. I would rather the renewable market get subsidies like coal and nuke than the current RPS standards AS A MARKET STRUCTURE.

Other points, "dropping" 20% into a market is exactly what some of these RPS standards in essence do - have them by a given date - in Colorado it's a constitutional amendment. And, unlike oil and gas, power production is a conversion market - production doesn't decline except by retirements. Therefore, absent an abandonment of investment, encouragement of investment in one resource does ripple through the system.

The article is to point out the unintended consequences that can occur from the choice of the mechanism used to encourage investment. I left out the argument that portfolio structures are really the subsidy used by policy makers who don't want to confront the cost issues of subsidies by making them a hidden portion of the utility bill rather than having to vote the subsidy.

I want renewables to succeed. I work in the renewables area all the time - but setting up a structure that is counterproductive to financial acceptance by rate payers of the impacts of renewables seems a less appetizing choice.

I think your point is the first line of your second paragraph, namely (paraphrasing) "Beware! RPS will be PURPA all over again." And though you've been a bit dodgy with this point, this article IS about renewable energy, and not subsidized energy in general.

I think the main problem with RPS is no one really knows the pain incurred (including market pain) to get to a particular percentage mark. I can appreciate that.

Though you don't say it explicitly, the main problem with renewables is that they are not an on-demand power source. If they were, 90% of your concerns would vanish. (A renewable homeowner would simply drop off the grid, or use much less power than before.) For small suppliers, most utilities employ net-metering. That would staunch excessive losses. And the RECs go to the utility, so they are getting something for what they are paying for. Maybe I'm too flippant or uninformed about all of this, but I can't see why this is such a huge issue for small levels of penetration.

And that's what they will be, for quite some time. A bill mandating 20% RPS does not necessarily make it so. It seems to me the problem that I don't appreciate (and should) is the time frame. If the renewables are introduced too quickly, then the system can't adapt and we have a repeat of PURPA.

Perhaps the problems this time around might not be so severe. 25 years of technical progress have reduced the costs of renewables (or should), and depleting resources and environmental concerns have raised the price of conventional power (or should).

Again, I have to lay this at the feet of the utilities. By doing nothing with respect to climate change concerns, and through poor nuke plant management, making the (U.S.) public scared to death about nuclear power, they've left themselves open to regulation by government authorities who we all know, are seldom wise enough to wield the power they can employ.

If your concerns are valid (there is some validity to them, but perhaps the problem is not as severe as you suspect) then the utilities are reaping what they've sown, namely working feverishly to hold onto a status quo that is slipping away from them.

If you look at the realities of a given area (even in Colorado), a high % mandate is still going to be phased in. These always happen in stages. Big project goes in, then review period while everyone prepostures for the next move, then they jump on it or wait til just before the deadline. All energy suppliers, as well as T&D companies, know what to expect long in advance.

My big problem with subsidies is that they predominantly favor maintaining the monopolies in place now and the majority of them are for show. There is no accountability in national research or in paid research. These places are a business without a product. Since this money ultimately comes from the industry as a whole, it's nothing more than a redistribution. An RPS is the only way I see to incentivise clean generation over dirty forms without the government handling any money. We need this isolation because of the immense power (no pun intended) the utilities have to game any government money. This way all the money stays in the industry.

Regarding the idea of free riders, I just don't agree that it's a negative. Anyone spending their own money for clean energy should be 'paid' for making a change on their own. They don't get this in any other form. The existing grid has already been paid for so all they owe for is the maintenance which they reduced due to decreased load. Their neighbors benefitted here too and paid nothing. Since the overwhelming majority of DG is solar, it usually flattens out the peak cycle which reduces peak prices, T&D peaks and overall fuel usage. This (plus the usual DG benefits) easily outweighs their new maintenance cost? The utilities don't get charged for their societal externalties, so I view this as their charge rather than renewables' subsidy. After all, isn't the end goal to get completely off fossil fuels?

This shows the main difference between this era of subsidies vs. past times. In the past, we wanted anything we could get to add to our capacity. This time, we're trying to replace an undesireable entrenched industry with a fledgling one. If the day comes when this RE component hits a high enough concentration that it has a measurable negative effect somewhere, someone will recognize the need for more diversity and the pendulum will swing somewhere else.

You misunderstood me about free riders. My argument is that someone installing point of use renewable is getting vastly UNDERCOMPENSATED for their investment and the rest of the grid is getting a free ride. Just as my market structure point was oriented, the distortions in this market are such that someone investing in this technology could end up at a competitive disadvantage to someone who doesn't. LMP - while very accurate at allocating existing capacity in the grid - will actually transfer value from people who reduce their use of the grid to people who stay locked to the grid. Much of the structure reinforces the existing paradigm rather than shifting value to people who create it.

For the case in which a point of use (POU) renewable source is capable of supplying all of the needs of the host site 24/365, I accept your contention that the owner of the POU renewable may well be undercompensated. However, I have great difficulty envisioning how that undercompensation might be redressed.

For the case of a POU renewable which is capable of providing a fixed demand level 24/365, which is some fraction of the needs of the site, your general argument in the article applies.

For the case of a POU renewable which is capable of providing some varying portion of the demand of the site over some portion of the day on most days of the year, the argument gets far more complex, since the utility must be in the position to distribute energy to the site to meet some or all of the demand on what is functionally a "no notice" basis; and, the utility or ISO must be in a position to transmit that energy; and, the utility or a group of generators must be in a position to generate that energy.

For the non-POU, non-24/365 renewable source, which is the issue in most RPS cases, the argument becomes more complex yet, as you suggested in the article when you avoided discussing it. In that case, there is a guaranteed market for the output of the renewable, but no guarantee that the renewable source will be able to serve that market 24/365; or, on any other guaranteed basis, such as 6/365 or 8/365.

The POU solar thermal / thermal storage / Stirling generator case that intrigues Todd is very different, from the point of view of the utility, than a solar electric or wind farm installation without storage, for a whole host of reasons.

With regard to Jim's point on scale of demonstration, the utility industry resistance is based largely on the PURPA experience and the industry's knowledge of how state utility commissions view precedent. The immediate financial impact of allowing some fraction of 1% of small customers to net meter is indeed negligible. However, the precedent of net metering for POU generators would become lethal at substantially higher percentages, especially since the net metering customers would, by definition, be taking power from the distribution / transmission grid and the generators at certain times or under certain conditions which might not be predictable.

State-level RPS is a recognition that utilities must be forced to use renewables, which suggests either that the utilities discriminate against renewables without validity, or that renewables add costs and a degree of difficulty and a degree of uncertainty to the supply / transmission / distribution management process that utilities believe will adversely impact rates and reliability. While there are those in this discussion who have difficulty attributing rationality and fairness to utilities, I am obviously not one of them. I have no difficulty understanding that a 20% RPS in a market with 10% conventional capacity reserve margin (especially if that 20% includes substantial solar or wind generation) poses some unique challenges to grid system reliability.

Many salient points:

Compensation structures are am issue. Some of the incentive programs - ConEd's location based demand offset is an example - strive to do so. And I agree that net metering in certain cases (especially wind) can OVERCOMPENSATE for energy consumption (if I net meter off peak $40 power shedding with $200 on peak demand the result benefits the on site generation to the detriment of the grid). And, yes, the PURPA siutation is one I lived through.

That said, there is real value to all concerned in distributed resources - both megawatts and negawatts. It may be that utilities need a great array of contract resources to deal with this. Since utilities are very capital investment oriented, I could see the utility being allowed to "incentivize" a portion of the cost of and end user's investment in relation to the relief if gives to the system - a reverse congestion fee if you would. Possibility would be for the utility to grant a dollop of congestion rights to the user - in markets where they exist - to the user who reduces demand on the peak and the utility gets the guarantee of the reduction or the consumer pays the congestion charges. There are a lot of ways to skin this cat - the question is whether what is being done is the bureaucratic answer or the correct answer?

My assessment - the bureaucratic answer. My assessment for the future - the bureaucratic answer.

One of the great problems with managed markets is that the market managers have to be smarter than the market. I am still waiting to see that situation for the first time!

Ed

Independent Market for Every Utility Customer - Preliminary Business Case

Independent Market for Every Utility Customer - Part 2 - Market Operation

It's funny about ideas. it'll go no-where no matter how asiduously promoted until it reaches just that one individual with the correct combination of contacts and interest.

Len,

It is both what we have now and what you advocated in your articles, although in different forms. My point still holds; the market manager must be smarter than the market, which is the collective intelligence of all of the market participants. I ain't seen that happen yet! I will be truly amazed if I ever do see it.

Ed Reid

Looking over your deregulation article - interesting idea. Couple of comments - one, the market you envision is another excellent method - LMP is actually another - of managing existing generation and capacity. Where is the mechanism for creating the investment signal for investment? There are a couple of my old articles on Pulse that discuss the inability of a conversion market - such as electricity - rather than an extraction market - such as oil and gas- to create the FORWARD price signal necessary to attract investment for a stable supply scenario. Markets focused on allocating existing capacity are prone to boom/bust cycles (look at plywood) and rely on price rationing in real time to accomplish production management. I am not sure the retail electric market will accept such a solution.

The market manager - due to the instability noted above - ends up having to manage monopoly rent situations. PJM has already started down the political nightmare of realizing its market management function is just PUC lite - I am not sure that problem is not endemic to your solution.

Three, and the biggest issue, is that the value of individual customer choices are, bluntly, too small for most people to take the time to worry. How many people program their TiVo to record programs? And that is something they really enjoy? If I am reducing 1 KW of sonsumption in a $500/MW market, I am only saving $0.50. The problem with very small numbers that aggregate up to large ones is getting each individual to spend their effort to pick up that $0.50. If they don't, the big numbers vaporize. How does the market manager address that?

This is pertinent to the discussion above because my point is that market structures that do not recognize what the market options are, who exercises then and WHAT they are worth will always have inherent flaws. It is better to create a structure that allows a balance of competing interests. Here is the simplest point I can make - until a market structure defines reliability to provide a level of service at A KNOWN COST TO THE CONSUMER OF THE TOTAL SERVICE and then allows the consumers, providers and suppliers to come to agreement on the level of service at the price the consumer wants and lets the CONSUMER say at that price I want less service, it will require significant market control of pricing by the regulator.

1) Where is the mechanism for creating the investment signal for investment? - None is required. All that is required is removal of current barriers to entry of small distributed CHP.

2) With existing transmission / distribution freed up for central Merchant Generating to simply exploit areas underserved by DG, no monopoly situation should develop.

3) When a homeowner can, by adding $30,000 to their mortgage eliminate eg. 80% of their heating, cooling and electrical billings I'd expect the installations to become as standard as hot water heaters are today. The co-gen appliances will replace furnaces, HW heaters, pool heaters with all maintenance included in a low anual-fee service contract from a local dealer. Operation of the co-gen units and smart meters is entirely contracted out to independent service providers who compete to sell the smartest and least intrusive and most cost-effective programming for the meters. And yes, Ed, the distribution utility is paid proper monthly fee to reward their investment and, iff competitive, compensate them for operating the billing system etc.

The only barrier to this happening is customer access to a market which fairly rewards it.

I fail to see your concern.

My expectation is that small gen is a big chunk. However, the $30,000 addition also presumes what annual maintenance cost? American housing stock energy consumption is much higher than it needs to be, why? Because homeowners don't invest as heavily in energy measures as they could.

The system REALLY has to change if small gen is the preferred form of gen addition, why? Because the ISO and the utility are still on the hook for reliability of power. If I replace 80% of my power needs, is the utility only responsible for the ongoing 20% or, in case of failure of my system, are they responsible for 100% of my power and LIABLE if it doesn't show up. Also, what if growth outstrips small gen additions, what is the mechanism for signaling needed additions and who makes them?

I love small gen POU investments. I think they are the most rational method for supplying a significant portion of the market needs. But even this mechanism requires a well thought out market mechanism that allocates responsibilities, liabilities and authorities in a manner that achieves the intended goals. Grafting new programs on a flawed system can just create greater instability - back to my initial report.

The only other necessary signal is increasing prices.

Great replacement for LMP - won't create a stable market though. Sorry, the math doesn't work - you are only allocating existing capacity, there is no mechanism for attracting investment. And before you say "increasing prices", the problem is that increasing prices for real time power is NOT an adequate price signal for stable capacity.

For quite a while, Len has been selling a system for an energy only market design like the one being used in Australia. In the last comment before EnergyPulse “closed” from “Active discussions” and “Highly Read” the article The Dawn of Electricity Competition: Efficient Prices and Efficient Choices, I covered said mechanism. This is what I wrote:

The quote "markets deal in one commodity that is produced and consumed at the same instant" is an special characteristic of power systems which requires activities like those (1 - long term planning, 3-5 years; 2 - resource adequacy, 3-6 months; 3 - operations planning, 1-2 weeks; 4 - day ahead scheduling, 12-24 hours; and 5 - real time security, 5-180 minutes) identified by Joe Chow et al “Electricity Market Design” paper published on the November 2005 Proceedings of the IEEE.

As far I know, Australia has tried to develop an “energy only” market, which as Lasantha explains is not working properly for retailers, as i.e. [Lasantha said] “The problem is that pool prices are way too unpredictable and volatile for effective price management,” and “Marginal bid sets pool price but that is dependent on market power, network conditions and previous investment decisions,” means that important activities mentioned above went missing from the Victoria [Australia] design.

The result is that the system does not operate on the normal state as high prices are correlated with low reliability. On slide 23 of my presentation [A Generative Dialogue to Reach the End-State of The Electricity Industry] I conclude that “power systems should be operated on the normal state.” It seems that the demand side does not participate in the remaining four activities which remain as supply side activities...

In reference to section B of ABACUS – wholesale competition – there are two elements: B1 – wholesale market competition – and B2 – demand response. In my comment above on 6.9.07, about the B1 and B2 elements, I mentioned slide 27 of my CMU presentation, under EWPC the competitive retail functions (including DR and Demand Side energy efficiency) complement each of the corresponding 5 activities within the time frames with: 1 - investments plans, 2 - resources available, 3 - outage coordination, 4 - load commitment and 5 - DR execution. As part of the generative dialogue, I propose adding the insights to upgrade section B of the ABACUS report.

I suggest reading about ABACUS on the mentioned article.

Almost ten years ago - in the very initial stages of the US and Australian deregs, I ran a project for World Bank in Colombia to design a wholesale power market. The result was the first option based capacity market (something JCAP and others emulate but not completely). The problem is that LMP (and your model) do not create an adequate long-term price signal for non-speculative system investment - either generation or transmission. I followed that up with a white paper for CAEM comparing open markets and cost of service markets as trading regimes (yes, cost of service is a trading market, it only has one buyer).

In a nutshell, the electricity market long term price signal in a rational hedign market is the cost of nuke or coal fired generation. This is below the replacement cost of other technologies. Therefore, until the front delivery periods get very short (California and PJM in the late 90s), the decision to invest in generation is a very risky business, causing the risk premiums to be high. But the long term price doesn't reflect that risk. So, over time, investment lags. When the shortage does creep in, the lag time for new capacity causes the front pricing to explode - with caps or regulatory action being the only brakes. This hyper volatility shows value that overattracts fast money, restarting the cycle.

The option based capacity markets that are developing are a start but they lack three important features of the market created for Colombia (unfortunately, it wasn't implemented). One, the capacity market is too short - you need a good five year forward period to stabilize the investment cycle; two, it lacks a customer participation structure - if done right it addresses the majority of the free rider issues for a period of time that does much to level the playing field; three, capacity markets have to address the issue of retail customer contract obligations and mobility - if a retail customer signs a three year retail deal, the system must enforce that obligation.

Long response but this is a soapbox I've been climbing up on for a long time.

The flexibility available is enormous. The key will be to ensure that the MM is always operating in the general interest and cannot be influenced by special interests, but that effectively applies to any system.

Hi Fred: EWPC has not been implemented anywhere yet. ABACUS Report ranks Illinois as having made medium progress. As Texas is in first place on ABACUS and is still far away from EWPC, Illinois is still way off.

There is a need to learn about what is emerging to address the real needs of society and end-customers. Customer participation as explained above and reccomended by Schweppe in the 80s went missing. Agreements of the weier sort, as you called them, were made as ommeltes which are very difficult and costly to undo today. The answer this time around was written (7 month plus days ago) in the post Let's Get Out of Back Rooms to a Generative Dialogue, to avoid the perverse socialism of deregulation. It is good to have skeptics like Fred to get the most balanced views.

Please remenber, "I am not my opinion" is the key generative dialogue instrument.

"that is simply a contractual issue between the retailer and its customers. If a retailer is unable to deal with it, then they should get out of the business."

Problem is that the cost of pursuing the customer is high compared to the damages. However, the death of a thousand cuts is a lousy way for a business to work. I actually like your meter model because the Market Manager could allow a company to manage the meter and "block" a competitor if they have a valid contract. Curious if you see that function there?

Deals for flip the switch service, especially during the transition, as explained in "The Dawn of Electricity Competition..." article mentioned above, might be available for a market segment, if customers find them useful and are willing to pay the price. Yes, the idea is to let customer have real choices that will be dealt in many different and creative ways by the development by retailers of innovative business models under retail and wholesale competition.

As ones warms up on the shift, one can get carried away with other examples, like a deficit areas that arrives at when at a given location there is a large generation capacity outage. You would charge your PHEV at home and go to the mall with the highest LMP because of the outage. What I am showing is that there are also oportunities in space with the PHEV, in addition to time opportunities.

The “prolog” argument led to a scramble egg End-State which in many cases cannot be unscrambled. As can be seen in slide 11 of the CMU presentation, an inferior development path is selected to the End-State of the power industry, which got “phase locked” with the trade, contract, regulatory, and ownership arrangements. The result was kept on the 2005 Energy Bill, where the “native loads” were legally preserved, as is shown on slide 14 “creating a big barrier to the development of the resources of the demand side.”

By the way, EWPC is neither a pure central planning, nor a pure open market. As shown on slide 36, there is 1) an ultraquality controlled market, with performance regulation of transport and system planning, operation, and control, and 2) wholesale and retail competitive markets, under prudential regulation of non-real time generation and retail.

Those steps are so obvious it's painfull to observe the present situation / mess. IMEUC takes one good long step, and is flexible enough to be adjusted in future to deal with any problems.

The obvious location for the controller is in the meter, as all necessary information is available there, and in any case it needs to incorporate a) remote disconnect, eg motorized 2 pole breaker b) optional local generator anti-islanding / grid-isolated generating controls and disconnect / motorized breaker / and perhaps even synchronizing logic and generator excitation management for VAR supply if the market will purchase at a high enough price, c) provision to interact intelligently and profitable with several grid-wise PHEV's and d) the filters to restrict the local powerline carrier signals from passing out onto the distribution system while still actively communicating via BPL with the central market for price signals, weather forecasts etc.

But maybe it's only me who thinks these steps are obvious?

A minimal agreement proposal under the generative dialogue that avoids monopoly markets on wholesale and retail, open to be enhanced, is as follows:

Slides 7 to 13 of the CMU presentation present 8 possible End-State, only one of which is the generic market model paradigm: retail competition with active demand and ultraquality transportation. That is the essence.

To take the best development path, including necessary transitions, to the End-State means eliminating "native load," and energy only markets at the outset, to avoid costly intermediate transitions. Those two eliminations are a prerequisite to an effective system, with wholesale and retail competition demand integration, and transportation reintegration.

There are key elements that will require standards to complete the detailed cooperation on market vs. market competition, hopefully under global institutions. However, most technological and business solutions belong to the company vs. company competition.

In summary, a general agreement is that we should do without regulated price controls on the retail and wholesale markets (that is how the EWPC paradigm came to being on EnergyPulse with the intention to replace the faulty deregulation paradigm). I suggest that regulators worldwide should shift from price regulation to prudential regulation, under a global institution.

With all due respect, the last thing we need is another "global institution". The next-to-last thing we need is an existing "global institution" with expanded scope or powers.

Thanks for your timely opinion in response to my call to enhance my humble proposal.

First I make a quote about the need for institution innovation. Eamonn Kelly, the CEO of Global Business Network, wrote on “Powerful Times” that: "Nation-states, especially the wealthier ones, tend to set their own rules and guard their autonomy, choosing on a case-by-case basis whether to join treaties and conventions and abide by international standards. They continue to have extremely important sway over multilateral institutions; the voting rights at the United Nations, the World Bank, and the International Monetary Fund, for example, all privilege the most powerful nations. Yet while the concept of the nation remains dominant, there has been relatively little true innovation in the exercise of national governance.”

Now, I will explain why I think we should be open to both possibilities for now. Venues like EnergyPulse.net are giving us space to think aloud of alternative institution innovations. For example, the institution might house worldwide utility regulators, with a very specialized agenda, similar to that of telecommunications - the International Telecommunications Union. Which institution were you thinking of?

I originally had written WTO and then recalled that energy and environment had been dealt at length on the WTO, but somehow nothing has been agreed to locate it in any institution.

By the same token, If there are institutions which are outdated, I think we should push to close them out.

I agree with Ed on this one for several reasons:

First, the structure of the generation assets and the transmission network will require significantly different infrastructure models - a microgrid or non-grid structure for an emerging electrification system will require fundamentally different rules than a fully developed hard grid such as the US or EU.

Second, bureaucratic structures tend to be much less dynamic than markets need. I would prefer a recognition of the appropriate market dynamics necessary for stability with a corresponding set of principles at the local and national level. The ability of the ISOs in the US to develop differing structures is a benefit, not a detriment.

Three, the differing infrastructures of local or regional markets can lead to very different clearing and credit needs. For example, in Colombia, the market model we used looked at margining of forward generator sales based on water reserve levels - the key factor for energy production from the primary resource - hydro. This would be completely inappropriate, for example, in ERCOT. These types of distinctions would be well nigh impossible to implement in a global structure.

MIT The TECH (quite benevolent)

Witness: David Malungisa (ZIMBABWE) - {angry view}

"I accuse the British government, the World Bank and the International Monetary Fund for ignoring the real problems that we confronted at independence such as racial and class inequality and the unfair land ownership structure in Zimbabwe. Instead, these institutions disenfranchised us and, working in cahoots with our elites, imposed a system of free market economics which they called Economic Structural Adjustment Program. Their promises of milk and honey have turned to nothing but an Extended Suffering of African People."

In general my immediate reaction to international institutions is negative, but I'm not sure that is based on more than a general impression from media unfounded in accurate research.

I am glad of the interest that the idea of global institutions had taken. Thank you for your input on the proposal.

I think my suggestion has been extended further away from its intended scope, which has to do with the business side more than the technical one. The issue is the suggestions that I wrote "I suggest that regulators worldwide should shift from price regulation to prudential regulation, under a global institution." The idea is to make a large shift from price regulation on retail and wholesale markets to prudential regulation of retail and generating activities. I strongly believe that a global prudential regulation will be most useful as private operators - retailers and generators - do mergers and acquisitions on a global basis that changes the competitive environment everywhere from time to time.

Regulation of the transport system was not suggested to be changed to prudential regulation and will remain as a controlled market activity.

I hope the intended idea has emerged.

The other suggestion was about standards, and since this is not the issue, nothing further will be added at this time.

In response to the comments by the author, I like to give a second though - thinking aloud - to the need of electric power systems from a systemic perspective. The job of the system planner should be to make sure that systemic risk of system failure is properly managed.

I agree that a supply side focus, like the original thermal based oriented Standard Market Design proposal did not met the needs of the western hydro based orientation. However, by integrating demand in the 5 activities from planning to real time operation is a different ball game.

This time systemic risk is enabled using a demand side complementary approach, which can be aided by differing development of the resources of the demand side can be develop without interfering with different infrastructure models.

In addition, the concept of ISOs was designed by leaving physical distribution separate from transmission initially. That is, active demand was not considered.

In summary, I think there is a space for global system planning and design under EWPC to manage systemic risk, without interfering with differing infrastructure models. It is not an either/or issue, but a both/and one, as Eamonn Kelly explains in “Powerful Times,” that we need a new kind of thinking to live with dynamic tensions. This particular issues are at the interface of system planning, control and operation and prudential regulation.

New comments are most welcomed on the generative dialogue.

Systemic responses - yes. I am just not convinced that global structures for something as regional as power grids makes sense. For a number of reasons - first, central structures, by their nature, are much less dynamic and have major issues dealing with differentiation (the concept of fairness and equality creeps into what is a regional allocation of resource issue and the system will implode). Second, power grids and structures have a major impact on inter regional competition and economics - I can just see a global entity trying to remove inherent competitive advantages, yikes.

I must admit, I can see a consensus globally on the framework of a stable market - but I think the implementation has to be non-global.

I will not try to convince Ed, Len or you or on the idea that global structures make sense. What I will try to do is to ask all of you to give me the benefit of the doubt on them.

There were two or three very likely scenarios when deregulation fever started more than a decade ago. After the dot.com bubble what's emerging is for new technologies to impact electric power businesses. A paradigm shift is in the works, which corresponds to the proposal above, which has been questioned so far on the suggestions about global institutions.

A stable market framework will come from a robust market design and architecture. The paradigm shift towards the framework is not about deregulation, but about re-regulation from price controls to prudential regulation of wholesale and retail markets. I think it is not advisable to take sides, but to allow the paradigm to emerge. So we need to look at other angles of key issues with “both/and” thinking while predicting the present.

One very likely scenario is that electricity seems to be poised toward a large market share of the world energy pie in the XXI century. Under EWPC I see emerging retailers and generators competing on a global scale, as it is already happening. Energy and environment global governance is very likely to emerge.

Dale Bryk wrote an interesting and forward looking article - Toward a New Regulatory Framework - on the Jan-Feb issue of EnergyBiz Magazine, which poses the need for insights which are available in the generative dialogue we are developing, with for example a non-artificial decoupling of sales and profits. Also he writes of the utility of the future, which under EWPC would be the integrated transportation company. Retailers and generators would no be utilities in that sense or is it the other way around?

Mr. Lord's basic premise is that Renewable Portfolio Standards are blunt policy that lead to economically inefficient results. While I agree with that assessment, he makes no mention why many states are enacting RPS regulations.

States are choosing to regulate with a RPS because of a market failure to put a price on CO2 emissions. As long as CO2 emissions remain an externality, with little or no cost to the private sector, government will have to rely on suboptimal regulations to slow the growth of these greenhouse gases. Doing nothing is not a responsible option when the consequences of global warming may severely impact the natural ecosystems upon which our civilization depends. Doing nothing is even more economically inefficient than the RPS.

Despite the rhetoric that US markets are free and competitive, it is chock full of inefficient tax policies, subsidies, and regulations intended to protect certain industries at the expense of economic efficiency. I would love to see a carbon tax, a carbon cap and trade, and other market based responses to help curb CO2 emissions. But I don’t believe that the American body politic would support new taxes of any kind at this time.

So, if Renewable Portfolio Standards are the best option available to reduce CO2 emissions, what should regulators do to cope with the increased “peakiness” Mr. Lord points to?

I believe that most efficient solution is to implement realtime pricing to end users. In fact, how can we even dream of achieving a true, efficient deregulated market as long as most of the demand side sees only fixed rates, and therefore has no incentive to respond to price spikes?

Implementation would need to start with the largest customers first, but the rapid growth in homes with broadband and a national standard on communications could enable even residential customers to log prices at which they want appliances to start cycling or shut down.

This is not to suggest that renewable subsidies are not equally subject to volatility, but rather that any regulation which distorts the free flow of capital must ultimately be considered as a distortion. A valid case can be made that since the renewable subsidies pale in comparison to those paid to alternative sources, this isn't really a subsidy so much as a playing-field leveller. However, even this characterization is flawed, because virtually all existing renewable regs are structured to pick winners rather than allow the efficient allocation of capital. ($1000/kW to a solar panel is an example of winner picking, but paying someone based on the volume of carbon they reduce would be an example of letting capital flow to the most effective use. Needless to say, the former is vastly more prevalent.)

So yes, the subsidies are inherently volatile, and yes, our existing renewable policy has mis-framed the real issues. But these caveats aside, the focus only on renewables fails to characterize the breadth of these issues.

The focus here was not on subsidies per se, but on structures that create exclusive markets. The decision to create depletion allowances or wind tax credits or special depreciation structures create an unlevel playing field but they do not shift volatility of the market from one segment to the other. In traditional subsidy structures, the subsidy reduces the investment risk but does not impact the overall market supply allocation dynamics (for example,under such things as LMP - a tax subsidy may impact a company's bid pricing policy but they still bid into the same pool; under RPS, these are separate supply pools with, potentially, completely separate bidding structures).

Fossil fuels tried this with the ill-fated PURPA plans. I am not debating the need for subsidies to encourage technologies (though I agree that results oriented subsidies - x dollars per MMBtu of fossil fuel reduction may create greater technological diversity than $x per solar panel) or the fact that existing technologies have huge subsidy structures that many industry members ignore. I am discussing the concept that certain subsidy structures (and that is what market set asides are) can create great potential for economic back lash against exactly the group they hope to support.

Fred C. Schweppe led in the 80s the development of theory and practice of spot pricing of electricity to replace a mistaken avoided cost signal used under PURPA. Schweppe thought to apply his development to a regulated marketplace that kept the T&D utility offering retail services to active customers, as he was very conservative about the pressures of deregulation. What is emerging is a wires only T&D "utiity" where independent competitive retail services operate under under prudential regulation. That is what I have term as EWPC and is open to be enhanced to cover all effective designs as well to respond to Len.

The result should be the opportunity to avoid the backlash problem that Tom identifies through efficient pricing. If subsidies to fossil fuels are dismantled, there will be no need to subsidize any clean technology as the market rules will be stable for the long run. Vulnerable customers groups should be aided with transparent external subsidies.

I would refer you to the white paper I wrote for the Center for Advancement of Energy Markets (CAEM) titled "Electricity Regulation As An Exercise in Real Option Management: Comparison of Risks for Infrastructure Investment Under Traditional Cost-of Service Regulation as Compared To an Open Market Pricing - At-Risk Capital Model" in 2003. LMP works VERY well for allocating the real option to PRODUCE power but it fails terribly in pricing the real option to INVEST in the ABILITY to produce power. If you would, it allocates the system extremely well but it can not price capacity effectively. The underlying connection to this discussion is the more you shrink the open price market, the less effective open market become in pricing that second option.

The problem described by Mr. Lord is one of many that are inherent in the use of RPS.

Mr. Hiaasen is pointing in the right direction for industry structure. Let the big energy customers that already have interval meters face real time prices. If they want to buy insurance for future price swings let them do so through short or long-term contracts available in the market place. The lessons learned from the experience of large electric customers can be moved down through the range of customer sizes. That can even be achieved by merely allowing smaller customers to leave the shelter of regulated prices. Eventually, only the high cost to serve, highly risk adverse customers will be served under regulated prices. That is OK.

The energy industry needs to become more efficient. It has become to big, to expensive, and too polluting to leave as is. Governments and institutes will only delay and distort the process. Once externalities are priced through cap and trade mechanisms we can allow markets to do the hard work of finding the best solutions. The best solutions may vary from place to place and time to time.

As pointed out by Mr. Lord, single part real time prices are so volatile that they may not be adequate for motivating investment. One of the advantages of letting large customers go first into a truly open market is that they can work this out. They are big enough that we actually can afford the mechanisms that would force them off the grid if there is inadequate capacity because they did not contract for it. Their experience in dealing with that reality will be instructive.

The issue of large versus small then gets subsumed. The greater issue is how does reliability get defined as "availability at a know value". Until price becomes a factor in reliability the whole mechanism is unstable - LMP doesn't handle that question. Similarly, if the horizon forward for the cost and commitment structure for reliability is adequate, then the entity investing in ECM or DSM or renewables knows the economic advantage they are getting compared to the rest of the markets. I led a team effort for World Bank/UNDP in Colombia in the late 90's designing just such a market - the documents are public.

All the hedging strategies etc. discussed are simply ways to hide the needed signals from the people who need to be responding to them. These are steps backward. They also add to the "free rider" problems, and add an unnecessary insurance premium penalty to the costs.

Charging all customers real time prices should send consumers on a hunt for alternatives to avoid peak prices. But politics rears its head. The California Energy Commission recently calculated the levelized cost of merchant simple cycle power plants operating in the state at $586 per MWH. The high cost is driven primarily by their survey that showed utilization at only 5%. One can quibble over the last $100 per MWH at this utilization rate. One can also argue the super peak will always be met with old units that would be retired but for the existence of the super peak, making their capacity cost is much lower than that of new CTs. Regardless of any such adjustments, it becomes clear that at somewhere between 1% and 2.5% utilization total costs cross $1000 per MWH. But the California ISO plans to raise its ceiling price to $1000 in the future. The real cost of the top 100+ hours per year can never show up in LMP here. Other ISOs also have ceilings. If the true cost of the super peak were allowed to reach residential bills there would be hell to pay politically. And brief periods over $1000 are not good motivators for new capacity. How to get the peak down to more stable levels?

Achieving a stable market requires getting out price signals about the cost of super peaks, without an unacceptable political back lash. Size does matter in the ability to absorb the shock of wildly volatile prices. Large customers can deal with seasonal and daily volatility because they are sufficiently sophisticated and have the resources to deal with large seasonal variations. They can live with volatility, use on site generation to peak clip, use ice making to shift air conditioning compressors to off-peak periods, shut down selected operations on-peak, etc. Private contract negotiations will bring out the importance to these customers of clipping their highest peaks even while ISOs have price ceilings.

A major concern when California was developing its industry restructuring was what happens when a supplier fails to provide the power consumed by its customers on peak? The inability to turn off its customers selectively socializes the cost in a manner like the tragedy of the commons. Now California is requiring each load serving entity to contract for a 15% reserve to avoid the problem. At 15% reserves there will never be an adequate shortage premium in an LMP to motivate meaningful peak reductions. If we could privatize reserve shortages then we would feel more comfortable about getting reserve levels down to where price could be effective. Equipment that insures customers will stop taking power from the grid when they have not purchased any is affordable for large customers, but not at the residential level.

Eventually we should reach a point where size will not matter. But during the transition it seems that size can be used to good effect.

Under EWPC such volatility does not exist because of ultraquality transportation, enhanced by the development of the resources of the demand side with real time and non-real time efficient price transactions (i.e. under outage coordination – see my posts of 7.4.07 above) under retail competition. From the end of last year to the beginning of this year, James Carson, Len and I had a very lengthy dialogue on EnergyPulse, under the articles Playing with Fire - The 10 Tcf/year Supply Gap -- Part I and Playing with Fire - Part II. Len had many reservations about LMP, which ended when I made the following post:

Locational “marginal” prices come in many flavors. This is what the paper mentioned by Len says “LMP is still a new model and only time will definitively demonstrate its successes or failures. LMP will probably never be a perfect solution for all wholesale market concerns. It has its limitations. At this time, LMP is largely a supply-side focused approach to organized markets. Integration of demand-side factors to such issues as transmission congestion or generation shortages remains to be considered.["]

There is another flavor in the article Demand Response and the FERC Standard Market Design NOPR:

Demand Response, Locational Marginal Pricing, and Centralized Markets

In the proposed Standard Market Design (SMD), the key elements that would encourage demand response are locational marginal pricing (LMP) and the establishment of centralized day-ahead and real-time markets for energy, ancillary services, and transmission services. LMP and centralized markets provide efficient wholesale price signals to which LSEs and customers might respond if retail market designs allow such response. Over the longer term, LMP and centralized markets will lead to more efficient investment in generation, transmission and demand response technology, resulting in lower costs and ultimately lower prices to consumers.

LMP will allow demand response to play a role in relieving transmission constraints, both in the short and the long term, by communicating the cost of electricity service to customers. Locational marginal prices are the only prices that are consistent with efficient system dispatch, and they are the only prices that induce self-interested loads to consume efficient quantities of power and profit-maximizing generators to produce efficient quantities of power.

LMP does a great job at allocating the marginal cost of PRODUCTION but where is the price signal saying "we need more resources or less consumption two years from now"? The LMP/real time model assumes the most efficient system is to restrict demand - face it, that is the reality. When we get to LMP, the supply resource base is FIXED, you ain't getting any more. In a 100 degree heat wave you may find consumers are pissed that they don't have a choice to pay higher prices. It may have been more efficient for consumers to say, two years earlier, "I'm willing to pay x to be assured I can get power at no more than $300/MW (and you can sure do that with renewables) any time I flip the switch on". That is the discussion that LMP based systems ignore.

I don't see the difficulty, or what other system might work better. Surely you don't propose a return to regulation rather than free markets (ultraquality by regulation). Customers should be free to select which electrons they purchase based on the only two qualities (I have found so far, though more creative companies may identify more, and if the market manager agrees, more power to them), which can distinguish them in the market from other suppliers, "reliability" and "generator fuel". It's not complex. I can choose to purchase my peak-time power from eg. a 75% reliable source at $0.20 / kwh and curtail usage if asked, or from a 100% reliable source at $3.00 / kwh and ignore curtailment requests. My choice, and my programmable smart meter will take care of it all automatically.

Dick: I speculate that you haven't read my two articles in this site, links posted about 8th coment in this series.

"Unfortunately, Pennsylvania's old electricity industry waged an all-out war against the energy conservation and some other provisions of Energy Independence Strategy," continued Hanger. "They engaged in hardball politics to stop the conservation and smart meter policies of the strategy. We intend to let the voters know about their opposition to programs that save energy and help customers lower their bills and we will urge the vast majority who support these programs - Republicans, Democrats and Independents -to make their voices heard."

The Energy Independence Strategy will empower Pennsylvania consumers to take control of their electric bills; expand Pennsylvania's renewable energy market; provide incentives to cut electricity usage; increase the state's investments in clean energy; and replace our state's dependence on foreign oil with Pennsylvania-made fuels. "

"I would love to see a carbon tax, a carbon cap and trade, and other market based responses to help curb CO2 emissions. But I don’t believe that the American body politic would support new taxes of any kind at this time....... So, if Renewable Portfolio Standards are the best option available to reduce CO2 emissions...."

If one tries to look at things from my point of view, i.e., a proponent of a major non-emitting source that is specifically excluded from RPSs (nuclear), I think one will understand why I don't share Eric's patience/tolerance of RPSs, particularly if they are invoked in the name of solving the GW problem. If CO2 reductions are the stated purpose, then any policy that distinguishes in any way between non-emitting sources is indefensible. The alternative suggestion recently raised by Senator Domenici, i.e., a non-emitting portfolio standard that includes nuclear and sequestered carbon along with renewables, is somewhat better and more defensible as a GW policy (and is still not a "tax"), but is still far from ideal. Portfolio standards in general are bad policy, for a variety of reasons.

Declaring, by fiat, that a certain amount of generation will be produced by a specific, hand-picked set of sources, regardless of cost or the degree of practicality, is a bad idea in general.

First of all, the selection of the "blessed" energy sources that will be covered by the mandate is always going to be political and arbitrary. For instance, biofuels (e.g., ethanol) and even trash burning plants classified as "renewable", and nuclear is not, even though nuclear is far more environmentally sound than either of them. Not only is the RPS black and white (i.e., a source is on the list or its not), but this fundamental difference in treatment is based on something as silly as whether or not a source can be called a certain name (i.e., "renewable"). As one should have expected, the result is that now we are engaged in silly arguments about whether a given source is "renewable" or not. Some (Bush) have even tried to call nuclear a "renewable" source. Do I agree with this? No. But the real answer to the question "is nuclear a "renewable" source is, "who cares - it's a dumb, irrelevant question". In terms of sustainability, a 1000-year fuel source is as good as infinite.

Secondly, it is wiser to encourage (subsidize) a given source than to try and figure out what level of contribution is practical/economic, and then mandate that. It requires govt. to figure out things that it doesn't need to figure out (i.e., it requires them to pick winners).

Thirdly, and perhaps most importantly, RPSs only encourage one specific means for reducing CO2 emissions (or air pollution, or energy imports, or whatever the goal is). RPSs do nothing to encourage conservation; nothing to encourage fuel switching (e.g., coal to gas); nothing to encourage upgrading or replacing power plants to increase their thermal efficiency; nothing to encourage installation of pollution controls (in the air pollution case); and finally, nothing to encourage nuclear, CCS, or any other non/low-emitting option that does not make it on to the "blessed" list for whatever arbitrary reason. As all these things are left out, they will certainly result in a higher cost for a given amount of emissions reduction. In contrast to this, policies like carbon taxes or cap-and-trade automatically encourage all means of emissions reduction, with rewards that scale directly with the level of reduction.

I would also prefer taxes or limits, but barring that subsidies are a much better approach than any RPS. Govt. should determine the real negative impacts related to energy (i.e., CO2 emissions, air pollution, and foreign oil/gas imports) and they should subsidize all sources that reduce or eliminate those things. And it should be based on tangible performance with respect to those real problems, not on a silly name.

DM: "Government’s reasonable role today is dealing with externalities."

Absolutely. IMO, there are three significant external costs that are not included in the cost of (fossil) power. Three great market failures. These are CO2 emissions, air pollution (~25,000 annual deaths and ~$100 billion in indirect costs), and the geopolitical/economic effects of oil/gas imports from places like the Middle East and Russia. Correcting these market failures (i.e., inaccurate price signals) is the most important, if not the only, role for govt.

DM: "It may be challenging for the public to balance emissions with the cost of power, but at least it is the proper subject for the public to wrestle with."

Indeed. Quantifying external costs and placing an economic value on them is a very difficult scientific and economic challenge, but this challenge must be faced. These questions must be analyzed and answered. When you think about it, no intelligent, non-arbitrary energy/environmental policy (of any kind) can be set unless you know the answers to these questions. Furthermore, these are (frankly) the only real questions. All other questions/policies are distractions. How much are we willing to pay to reduce CO2 emissions, pollution, and/or energy imports, period.

DM: " I think the real strength of cap and trade systems is that they divide the roles of government and the private sector in a constructive way......Once externalities are priced through cap and trade mechanisms we can allow markets to do the hard work of finding the best solutions. The best solutions may vary from place to place and time to time"

Absolutely. Govt. should not pick energy sources (or winners). They should not develop any kind of plans or initiatives for how we will achieve a certain degree of emissions reductions, etc... Govt. should only set requirements or economic penalties, and then let the market decide how to proceed. This will clearly minimize costs.

Here's hoping (or dreaming?).

Well, if the credits are all auctioned off, as opposed to being given away to the current incumbents, then the cap-and-trade system will essentially act like a CO2 tax, the only difference being that the effective tax level rises or falls, depending on how the whole nation is achieving the overall goal. Any carbon tax on fossil fuels would raise their price, and make your non-fossil home energy system more competitive with the fossil energy/electricity that you would have otherwise bought from your utility. That is, your gas and power bill would go up, making the option you're considering more viable and competitive.

If most of the initial credits are given to incumbents, the benefit may be smaller, but probably not much, especially as time goes on. As time goes on, not only do the number of credits fall, but as demand is going up, even the incumbents will have to build more generation, and will have to buy credits for any new fossil units. Thus, the cost will go up for at least some of their generation. Thus, the price charged for their power will go up at least as much as their average power cost (averaged over the new and existing sources). In fact, the increase might be closer to the full cost of the credits, as the cost of their least efficient fossil generators, plus the full market price of a CO2 credit will be the marginal, market price setting cost. Thus, the net effect (especially in time) will be similar to what would occur in the fair public auction case I discussed in the first paragraph.

You will benefit (relative to others) if fossil prices go up, even if you never get paid a credit under the new system. Even this, however, could possibly be arranged. In any event, anything that raises fossil fuel prices would increase the market value of any surplus power you sent back to the utility. If the utility won't buy surplus power from you (i.e., beyond you zeroing out your bill for the month) at any price, this is a more fundamental problem that goes well beyond the issue of whether or not any bought back power also includes the value of a CO2 credit.

One more thing, I don't believe that you would fare any better under any of the RPS systems that I've heard about. My understanding is that with our RPS policy in CA, the utilities are required to get a certain fraction of THEIR annual generation from renewables, by certain dates. Non-utility users, or producers, are not involved at all. I think that the demand reduction (meter running backwards) from all those solar PV users out there merely registers as reduced demand (as opposed to renewable generation), and is not counted towards the utility's RPS goal. I could be wrong on some of these details....

While a national RPS can generate added costs since renewable energy capacity is often more capital-intensive than conventional capacity and has a higher upfront capital cost, it would bring significant benefits, the report noted. The cost savings from more renewable energy not only offsets the additional capital costs, but far exceeds them, providing net benefits to the consumer. The Wood Mackenzie report, The Impact of a Federal Renewable Portfolio Standard, states that a 15% RPS could cost an additional $134 billion in capital cost, but could save nearly $240 billion in wholesale power costs.

Renewable energy such as wind power avoids the costs of fuel all together, all the while displacing fossil fuel use and mitigating the price volatility associated with such fuels. Any reduced demand for natural gas resulting from more renewable energy usage can put downward pressure on natural gas prices, lowering the cost to consumers for both direct use of natural gas for heating and in terms of electricity prices. In the case of a 15% RPS, total natural gas consumption could be reduced by 10%, according to the Wood Mackenzie report.

In a recent interview, William Durbin, head of global gas and power research for Wood Mackenzie, said the firm decided to examine a 15% RPS given the large number of state RPSs already on the books and that “it was pretty clear the federal government was moving in that direction.” Durbin explained that “on the long run, you're saving on gas because there's no cost to the wind. So we ended up saving roughly $90 to $100 billion in fuel costs.”

The cost savings from reduced fuel and electricity prices associated with a national RPS have been echoed in other reports. The Department of Energy’s Energy Information Administration analyzed a 10% RPS by 2020, and estimated $22 billion in reduced expenditures on natural gas and electricity. The Union of Concerned Scientists analyzed a 20% RPS by 2020 and estimated natural gas and electricity savings of $49 billion.

Thank you again for engaging the generative dialogue. This is what I understand is emerging under EWPC.

To answer your three questions on the first paragraph, the system planner, controller and operator - which has a monopoly of the controlled market wires only "utility" and has the responsibility of managing long run and short run systemic risk - makes the decision under regulation. That is how integrated transportation (transmission and distribution) should be financed through tolls as it is done today for transmission at some designations. The result is a system that will be operated on the normal state - designed and operated with ultraquality.

Consumers make their input through competitive retailers, by entering long term, middle term, short term contracts to express the reliability and other services they are willing to pay for.

Many other industries have suppliers that invest and risk in lead time of decades (not only for transmission), why should electric generators be the exception?

Once you have the above, a EWPC grade designed LMP does its job on the wholesale market with the interaction of generators and retailers. Inter-temporal relationships of LMP market rules to the other 4 main non-real time activities are reflected through modeling and simulation done by the system planner, controller and operator, the generators and the retailers. That is how the short run and long run are linked.

Your last paragraph completely removed my interest in EWPC. the concept of open markets is that the risk tolerance of each individual is different. Therefore, the market mechanism is a manner in which the risk tolerance of the market as a whole is determined.

Regulatory structures, by their very definition, have a single risk tolerance reference - the regulator. Regulators have an asymmetric risk tolerance - they are much more willing to spend money to avoid a small risk of harm than they are to spend money for a potential reward. The certainty equivalent of the regulator choices will almost always have a lower value than the market's choice (the out lier is when the regulator makes a very risky decision based on bad inputs).

Regulators have a decision cycle time that, with current market volatility, leads to a huge market VaR - one greater than most of the market participants would accept.

So you have created a lower value, higher VaR structure - not one I can shift towards. I would prefer to create a structure that creates a regulatory framework on how the market participants interact to create adequate signals of how all segments of the market value supply and reliability and apportion the risks and rewards accordingly. That is very different than EWPC.

I will state, however, that it is reasonable to have transmission and distribution managed in a central system. This is due to the fact that the lead times on most transmission projects make them untenable in an open market at-risk structure and distribution is currently a "natural monopoly" - at least at the retail level.

I think a non-utility producer of energy from renewable sources gets rewarded with a REC or Renewable Energy Credit. This REC can then be sold to a utility as a way to meet their quota for a RPS. I don't think it is too hard to get registered to receive a REC, though they are in a larger unit (a MW-hr?) than most individual would produce. The are also bought on an open market, so you might not get as much $$$ for your REC as you would like.

I think Green Energy programs offered by some utilities use those funds to purchase RECs, so they (the utility) can claim the credit for producing that renewable power.

I don't see the grounds for your objection. I am glad the generative dialogue is going towards “native load” arguments to justify retail as part of the distribution monopoly.

The EWPC is an emerging paradigm shift (a work in progress that is different from what has been done so far) away from deregulation, where actual congestion and price spikes were used to justify investments, while increasing the physical risk of system failure. That is the flaw of deregulation which produced highly excessive profits for some agents.

Under EWPC there is a controlled market and an open market. The interface between both markets has the following characteristics:

The system planner, controller and operator works to operate the system in real time under normal state with LMPs. As can be seen on slide 23 of my CMU presentation, "congestion and excessive price spikes are associated with value destruction and the risk of value destruction." That is the reason of NERC (patch) mandatory standards. However, as can be seen from slide 17 of said presentation, “mandatory standards might produce large value destruction...”

Generators and retailers transact in a non-real time open market having their own individual risk tolerance. Both generation and demand are random variables in time and space. Retailers and generators perform simulations with model to make their investments decisions, forecasting with models their investments and operating decisions up to unit and demand commitments.

Two issues and one comment:

1) What is the justification for imposing a "retailer" intermediary between every customer and every generator? If a customer is savey enough and willing to deal directly in the open market, why should they not be allowed equal status in the market with the retailers? Modern computer systems can easily make per-unit transaction costs effectively zero, eg. covered by a small easily affordable monthly flat-rate charge (see gas card example above).

2) Anyone participating in the grid of the future is either responding directly to real-time prices, or a free-rider. Anyone hedged to/by a flat rate price retailer is gaining benefits of load levelling by their neighbors who are responding to real-time prices, which benefits presumeably will be collected by the retailers at no cost. Why allow that? If not allowed, how to enforce? IMHO, intelligent real-time-price metering should not be an option (aside from the problem of how to get meter production volumes high enough to get their cost within the "10x present analog meters" range required.)

Comment: With real-time-price metering and automated load response equipment installed at every customer representing a significant percentage of grid capacity, the headaches of the "system .. controller and operator works to operate the system " just go away. Skip spinning reserve, short-term load forcasting, etc. etc. Those simply go away, and without any value destruction or mandatory standards. Only required are some simply and obvious rules which avoid excess rent collection of monopoly suppliers at the bedinning, ideally by a) encouraging existing generating entities to swap physical generation capacity across market boundaries b) depending on open market transmission to enable regional competition and c) perhaps mandating eg. FERC or etc. to use threat of legal recourse to dissuade monopoly exploitation. It's all logical, quite simple, and requires no opaque syntax to explain.

I like it.

Given that every customer will still need a meter anyway, AMR is going to happen regardless of market design, and bills still need to be transmitted and collected in any system; THEN I fail to see how IMEUC might pose any impediment to your retailers business design innovations. I proposed the market manager making longterm contracts for eg. baseload etc. only because I don't think many private "retailers" will, but see no reason to bar them from doing so and using the metering system to verify their transactions.

If I understand correctly, Len opinion used to be: let’s centralized part (or all) of the retail function in an electronic switchboard exchange. The remaining retail activities will be done by the customer themselves and by the generators, with the latter doing especially retail marketing activities. However, in said post he changed his opinion (which is an essential element of a generative dialogue) to the possibility of retailers, which will give generators the opportunity to negotiate long term contracts with retailers in addition to the Market Manager - WOW!

But just to make sure that I got it right, I need readers to respond the next 6 questions and make their own decisions?

Shouldn't customers (maybe they are not “savey enough” or don’t like to deal directly with the market) have the choice to reject the exchange and enter into a contract with an intermediary, when electricity retail management is a chore with low benefit to cost ratio?

Shouldn't generators prefer to deal with a middleman (retailers) to perform the retail activities, when electricity retail management is a chore with low benefit to cost ratio?

Will the Market Manager do all (long run and short run) retail activities that correspond to the 4 above mentioned non-real time activities from system planning to load commitment?

Are free riders to be found easily under monopoly or under competition?

When all customers are forced to go through the switchboard, the exchange is nothing more than a monopoly electronic retailer. How will the switchboard do the development of the resources of the demand side (regulated retailers are trying to do this now under monopoly) now that we need those most to integrate demand?

Is my opinion to impose a retailer or is Len’s opinion to impose a switchboard?

Shouldn't generators prefer to deal with a middleman (retailers) to perform the retail activities, when electricity retail management is a chore with low benefit to cost ratio? -- not likely if the transaction costs are zero and the returns are higher in the market.

Will the Market Manager do all (long run and short run) retail activities that correspond to the 4 above mentioned non-real time activities from system planning to load commitment? -- in every pseudo-deregulated market now existing, those duties are already handled by an independent ISO/TSO body. IMEUC simply makes their job easier.

Are free riders to be found easily under monopoly or under competition? -- no, they're difficult to identify and surcharge, but widely existing, eg. every flat-rate meter.

When all customers are forced to go through the switchboard, the exchange is nothing more than a monopoly electronic retailer. -- IMEUC is the only system which provides market incentives, and fair financial rewards, to every customer to "develop the resources of the demand side" by any means available including the dozens of ways not yet thought of. The rewards are inherint, the calculation of their size is automatic, not subject to economists' errors in calculation nor lobby group's influence for preferrence, nor the opinions of any government group.

My position is, to gain the most part of the benefits it is not necessary to impose the switchboard model on every customer, only the majority, eg. a sufficient number to flatten the demand curve and send reliable price signals to builders of new capacity. However, how would you fairly select what subset to impose it on? Choise of retailers sounds very random.

Yes some of those customers might pay a surcharge, but under real competition the retailer that is not competitive has its days counted. That explains the need for business model innovations under EWPC.

Wholesale ISO/TSO bodies are using intermediaries to perform retail activities. Those intermediaries compete to perform retail services. They are candidates to be retailers or merge with retailers under EWPC.

Transaction costs for generators to do all four main retail activities with end-customers are not insignificant.

I agree that good businessmen would like to get a large market without competing, like "a sufficient number to flatten the demand curve." However, I suggest that it should be the market that selects the winning business models for every market segment.

By the way, I don’t have a position. Under the generative dialogue I am open to adjust my opinion on EWPC as new insights emerge.

Sorry for the delayed response.

You may be right about a small and/or non-utility producer being able to get RECs. However, I still believe that it would be possible to arrange the same benefit w/o an RPS policy. For starters, if we had an "emission-free energy" portfolio standard that included nuclear and sequestered fossil (CCS) along with renewables, there would be no reason why such a non-utility producer couldn't get CECs (i.e., "clean energy credits") exactly the same way they get RECs under an RPS.

Even under a cap-and-trade system, I see no reason why a small producer couldn't get paid for credits the same way a less-emitting utility would. The administration would be harder than most cap-and-trade planners currently envision, due to the much larger number of entities, but it seems that the REC/RPS system is no different with respect to that. In summary, it seems to me that the ability to include small/non-utility producers (in terms of getting paid for non-emitting generation) is not really dependent on the type of system that is used, i.e., renewable portfolio standard, non-emitting portfolio standard, or cap-and-trade system.

I can think of one possible reason why small (distributed, non-utility) energy advocates might prefer an RPS to a carbon tax, or any of the other approaches I discuss above. It has to do with the fact that the major non-renewable, non-emitting sources (e.g., nuclear or CCS) are things that will not be done on small, non-utility scale. Thus, with a more inclusive approach (as opposed to RPS), the set of sources that could be produced by individuals (non-utilities) constitute only part of the pie, as opposed to the whole pie. If these large-scale non-renewable means outcompete renewables, for whatever reason, then small non-utility generators will not see much action. RPSs eliminate some (most?) of the competition. Under RPS, private renewable generators have to compete against only utility renewables, as opposed to having to compete with utility renewables, utility nuclear, and utility CCS.

I'm hoping this isn't true. At this point I will lay some of my (personal) cards on the table. I am deeply concerned about air pollution (25,000 annual deaths), global warming, and foreign gas/oil dependence. I don't have anything at all against distributed or non-utility generation. I just don't care. I don't care one wit about whether people continue to get their power from utilities (and from large centralized stations) or whether a significant fraction of the users get their power from private, distributed generation. This issue does not motivate me. I personally am very happy with the utility power, and the convenience it allows. What I do care about are the three issues I listed above. Given this, I really don't want to hear (or think) that people would be willing to have us fight global warming and foreign energy dependence with one hand tied behind our back (by not encouraging nuclear or CCS) just because they think that it might (indirectly) advance the cause of distributed generation a little bit better.

I am not saying that anyone here is conciously promoting RPS over other policies for this reason. I also fully agree that any regulations or market features that are actually slanting the market against distributed sources should be eliminated. I also agree that the tangible benefits of distributed generation (e.g., reduction of transmission losses and increased efficiencies in the case of CHP) should be fully accounted for. That said, I don't think we should let a desire for distributed/private generation be a significant factor in setting our major energy policies (such as how best to fight GW). Whether a source is centralized or distributed should not be given significant weight in determining how much any given source should be encouraged. The issue simply isn't important enough, IMPO.

(PS: I won't be responding, as I'm out of town this week.)