What questions are we addressing in the overall study?
The first two points are addressed in the analytical (Phase 1) part of the study and the remaining ones will be addressed in the policy/institutional issues (Phase 2) part of the study.
There are various forms the power market can take, which will have effects on the levels and volatility of prices that the market will display and on the incentives for entry into the market by resource developers. Some of the general features that can exist, singly or jointly, are bilateral contracts (short to long term), a spot market (formal or informal) and a market for futures and other derivatives (formal or over the counter). Because of the instantaneous supply and demand balance required in electric power systems, some mechanism for ensuring adequate operating reserves is necessary as well.
Today there is a market already in place in the Northwest.: It has, among other features, an informal bilateral market, two informal spot markets with survey price data reported daily (COB and Mid-Columbia), a formal futures market based on one of the spot markets (the NYMEX COB futures), a nascent formal spot/short term market based at the Mid-Columbia (APX/Chelan), and a mandatory mechanism for requiring that control areas have adequate operating reserves (the WSCC’s Reliability Management System, soon to be filed at FERC). Control areas will have to rely on the other markets for provision of the operating reserves.
This market will likely continue to evolve in response to the requirements of
the participants, subject to external limitations, both direct and indirect. The
most important questions are whether it has or will have the most desirable
characteristics sufficient to ensure adequate reliability or not, and, if it
does not have enough of the desirable characteristics, what factors are
constraining it from developing. Prominent among current external
constraints is likely to be, for instance, uncertainty about future load
responsibility on the part of distribution utilities.
There are two ways of thinking about this question. First, assuming “adequacy” means levels of reliability that have historically been maintained in the Northwest, (or any other administratively established reliability standard), will market suppliers find it profitable to provide for that level of reliability, especially given the cash flow implications of the uncertain hydro supply on that profitability?
This approach derives from a circumstance in which prices are not allowed to rise sufficiently to balance supply and demand, but the balancing is achieved by other means. In this circumstance, characteristic of the franchised and regulated industry, the generation reliability criteria were set administratively and resources were planned to meet the criteria. Involuntary curtailment was the mechanism for balancing supply and demand when events occurred that they were not planned to be covered under the reliability criteria because with of their low enough frequency of occurrence. that they were not planned to be covered under the reliability criteria occurred. The decision about meeting the events within the limits of the criteria was then one of finding the least cost means (with some very general feedback between the cost of meeting these infrequent events and the reliability standard itself). There was almost always no direct, and often no indirect, testing of the cost of the unreliability against the cost of reducing it.
With a competitive power market, but an administratively set reliability standard, either the resources to meet the criterion have to be contracted for in advance or prices sufficient to allow profitable market entry have to be expected and, on average, achieved. Contracting in advance, i.e., giving the developer some commercial expectation that his investment will be profitable, would be the analog of the regulated utility mechanism. This requires some load-serving entity to take the capital cost responsibility and risk of providing these reserves to its customers. Alternatively, leaving the capital cost risk on the suppliers (or some financial intermediary providing fixed-for-variable swap services) means that spot prices will necessarily be quite high during periods of shortage., and This would probably be more so the case in the Northwest than elsewhere, because of the effect the normal variation in hydro has on the frequency of severe load and resource imbalances.
There is also a second way of thinking about the question, in which the
reliability level is not set administratively. In this case the question
can be posed as the following: will there be a sufficient market mechanism
developed, both on the supply and the demand sides, that the level of
reliability can be determined by the market rather than being chosen
administratively? If it can, one would expect that the reliability
standard would be different for different customers or groups of customers,
rather than being set the same for all customers.
The market will be most efficient if it has significant participation by end-use customers. Price spikes may be mitigated if end users who value the service less than the price are technically and institutionally capable of bidding load reductions into the spot market or the longer-term markets.
There are both institutional and technical impediments to widespread demand-side participation. and The latter are unlikely to be resolved until the incentive is created by the resolution of the former. Industrial customers have had experience with interruptible rates and are most easily capable of participating in a demand bidding market. Smaller customers, who may have the ability at the least to shift loads with the proper incentives, typically do not have access to the technology that would allow them to participate significantly in such a market. This segment of the market is most likely to participate through the mediating actions of the aggregator, whether a new marketer or the existing distribution utility.
A potentially significant impediment to suppliers’ entrance into the market is uncertainty about responsibility for load service in the future. Most distribution utilities in the Northwest remain responsible for meeting all loads placed on them by the customers they serve. But with the advent of retail access, these utilities do not know who they will be responsible for serving in the future, nor do they know when that transition will take place. A reasonable response in these circumstances is to limit capital commitments for loads that might quickly depart.
This response, in turn, changes the kinds of markets that are available to future generators, because it shifts the risk of capital expenditure from the utility and its customers to the supplier. This circumstance raises the importance of the market structure into which generators will sell, because it means either that they will have to rely more on spot market transactions or that they will need some other mechanism to off-load the spot market risk to those more able and willing to bear it. Either case requires a transparent and liquid spot market and the latter requires, in addition, other financial mechanisms, like a well developed derivatives market.
The important thing is not that either traditional utilities and their customers or generation suppliers should bear the capital risk of fluctuating market prices, but that some efficient mechanism is available for market participants to choose the level of this risk that they are willing to bear. Uncertainty is the enemy of developing this efficient mechanism.
At the wholesale level, Bonneville retains a statutory responsibility to meet the loads of the public agency and IOU residential and small farm customers that are placed on it (with some flexibility in the manner and price of service). Similar concerns apply to Bonneville’s response to the uncertainty about future wholesale loads it faces.
Transmission constraints affect the ability of generation to serve loads in specific locations. The market prices need to reflect this so that generation is not inadvertently sited with the expectation of being able to serve a market that it will actually not be able to serve. This means that some form of transmission pricing that accurately conveys scarcity of transmission capacity is needed. Examples are congestion pricing, auctions of transmission path capacity and so forth.