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There is much discussion about the failure of the restructuring process and the inability of regulators to see the forest for the trees. The alternative has been to turn the process back to "the industry experts" who know better. The industry experts didn't know better, they just had an advantage of different economic drivers.
Under "cost of service" regulation, the electricity rate case structure is designed to reduce investment risk to the point where utilities have an incentive to provide all the capital investment they can. In this manner, the regulatory structure becomes a "supply push" incentive structure. It doesn't matter what the customer wants to buy, the regulator has set what the customer will pay for. Once that basis is set, the regulator and the planning process can become one of picking and choosing the most pleasing engineering solution. The utility is not incentivized for economic efficiency; the regulatory process incentivizes for maximum regulatory efficiency. Since the utility earns on employed capital, the question becomes how to get the most capital employed. The regulators job is to act as a brake on utility investment. In essence, the regulator gets to be the monopoly buyer for the market; interveners in the rate case are merely back seat drivers in this process.
Under open market structures, there is not risk mitigation from the regulatory process. Instead, as we can observe, the risk mitigation process is handled by tax incentives. However, unless tax incentives reduce the risk to the point where everyone wants to invest – leading to overbuilding and uneconomic investment – the system still requires a "demand pull" cost structure. However, "demand pull" markets have greater risk of under investment and resulting systemic, rather than episodic, periods of price spikes and hyper volatility. This creates unacceptable political risk for regulators and the political process – consumers want low, stable rates.
We are seeing the similar problems occurring in natural gas. As long as natural gas was also a significant by-product of oil production the supply push caused by oil exploration managed the issue. The NGPA of 1978 created another massive "supply push" from the rapid escalation of the market price of natural gas. Now that we have worked off the last hangover from that era we are observing the first true "demand pull" cycle in the natural gas market. The results have not been pretty.
What can be done to correct the problem? Volatility Managers has been frequently speaking to the difference between the "build" options in energy – the addition of additional production capacity – and the "run" options in energy – the use of that capacity to supply energy at any given time. The infrastructure issue – both supply and transport – is the creation of market structures to ensure a stable and adequate amount of build options are exercised in any given period to assure delivery of energy at a cost consumers are willing to pay. But how can the risk tolerance of the consumers and the price they are willing to pay for reliability be determined?
In the past, this risk tolerance has been the risk tolerance of the regulatory commission. Most governmental entities are more risk adverse than many consumers and are likely to be significantly more risk adverse than commercial and industrial customers. Therefore, it is likely that the regulators will pay more for reliability than many consumers would. But we do not do that for certain. What we do know is that regulators will pay a lot for reliability (look at the PPA contracts of the early 80s at avoided, rather than operating, cost). Similarly, if ISOs and RTOs are responsible for replacing the regulator as the arbiter of reliability risk for the market there is a great likelihood that their risk tolerance will not be that of the marketplace.
For example, DSM, in the form of voluntary load reduction or shedding, is nothing more than the customer’s statement of the value at which it is more valuable for them to have reduced reliability than to continue receiving service. Mechanisms need to be put in place where the willingness of consumers to shed load is compared with the cost of new generation and/or transmission resources. Only then is the most economically efficient allocation of capital achieved. The existing capacity markets and most proposed reliability markets are based on eliciting offers from the generation and transmission side of the market – in essence, attempting to create a weaker open market version of "supply push".
The current state of restructuring has removed strength of the "supply push" which assured the luxury of selecting the most physically efficient system. Yet, it has not achieved the point of creating a "demand pull" process that allows the most economically efficient allocation of capital between new supply and load control. Until this happens, the system will be prone to "boom – bust" cycles and all the economic, political and engineering issues that they entail.
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The California legislature is now struggling with the relationship between industry structure and incentives for the development of new generation capacity, having seen first-hand the wreckage caused by getting it wrong. The most promising approach, and one to watch is a "core/non-core" approach envisioned in AB 428 (Richman).
As background, basically, "core" customers are served from a portfolio of resources regulated by the PUC, and "non-core" customers can elect to contract directly with competitive suppliers. This approach avoids the fatal problems for both utlities and competitive suppliers that arise from administratively-set, usually artificially-low "prices to beat."
Relative to this article, the utility commission can re-create traditional "supply-push" by mandating resource adequacy requirements for the "core" portfolio. These customers are presumably the least price-sensitive and generate the most political backlash when markets fail.
At the same time, non-core customers benefit from "demand-pull" or the "supply-push" that comes from wholesale capacity markets if these turn out to be more efficient (as I belive they will).
Given California's experience, it might take a while for a core/noncore retail industry structure to have all these features along with the ability of any customer to choose between core and noncore service, but it is a start. The adoption of "core" service in other states, with the "supply push" it can create, may be a way to prod reliabity investment and dampen the boom-bust cycle until markets mature and provide the needed "demand pull."
Peter Evans New Power Technologies
Thomas Lord 5.31.03
The problem with the core process is you are resetting the PUC as the monopoly buyer of generation development for the core customers. This creates three potential breakdowns in the system: the PUCs ability to buy generation resources in an economically efficient manner; the PUC's risk tolerance and the free rider issue for "non-core" customers.
Historically, PUCs have not been exceptionally skilled traders as monopoly buyers. The major argument for restructuring was the inefficiency of the utility business. Since the PUC buying practices, in essence, allowed this inefficiency what leads us to believe they will do better the second time around?
The risk tolerance issues is even more troubling. The PUC, as a political entity, has an extremely skewed risk tolerance - failure of reliability has an enormously greater negative impact than the positive impact of slightly lower rates for a perfectly tuned system. Therefore, it is highly likely the PUC will over pay for reliability to avoid any potential for negative impacts.
The "non-core" issue arises because -as a political matter - the state will be unwilling to shut of economic consumers if the power resources fail to materialize. Therefore, the core customers will become more and more central to the demand pull and will share the benefits with non-core customers in times of slight shortages yet the non-cores will get much of the benefit of those expenditures without the burden in times of over supply. In essence, they get a "free ride" on the obligation the core customer have to create a "demand pull".
A perfect case in point is the pricing structures for renewable power. The PUC should allow the utilities to purchase lowest cost power on the open market. The core customers are likely to be obligated to buy renewable power under the PUC actions. It is unlikely the non-cores will buy above market power from renewables. It would be better if the state wishes - as a public policy - to encourage renewable power as a resource to provide a direct subsidy to reduce renewable power to the same price as open market power. In that manner, the rate payers do not underwrite a political decision. Just my opinion.
TERRY MEYER 7.2.03
Good analysis, new to me.
When it comes time to pull the plug on non-core customers, just how do we keep them from switching to "core" status?
Thomas Lord 7.3.03
The "free rider"problem is one I had to address designing an open market structure for wholesale power fro the World Bank in Colombia. The reality is that the movement of customers and, even more complicating, the potential for customers to move out of the service territory or go out of businees. That is one reason I prefer the PJM "interchange" model for energy delivery. It would - if anyone ever took the intellectual leap - allow the PUC to completely separate the process of devliering energy from the process of pricing energy. This would allow the separation of the engineering of the system from the risk management of the system. At that point, "core" versus" non-core" is irrelevant, the distinction would be "system managed" or "self managed" for pricing.