It is difficult to discuss or propose a core/noncore market structure without
discussing Californias previous retail market restructuring effort. Many academics
and others have written papers pointing out the flaws in Californias previous
actions. One aspect of those earlier restructuring debates deserves prominent
treatment: customer choice.
In the aftermath of the electricity crisis, we have given comparatively short
shrift to customers served by Californias electric system. What do customers
want? The short, anecdotal answer is that they want three things: lower prices,
high-quality service and options (about where they buy their power and what
type of power they buy). In numerous surveys, customers especially residential
customers report that they would actually pay more for green power. Knowing
this, it is fair to conclude that, in many instances, the current market structure
is not serving the needs and wants of customers.
To that end, a different core/noncore structure should be considered under
which a 200-kW size threshold is set for customers being automatically defined
as noncore, as long as aggregation is allowed and preconditions are in effect.
Those include, primarily, mechanisms to guard against cost-shifting both of
past costs and of future utility generation investments between so-called
captive customers and those who opt for choice.
Companies are risk-averse and long-term investment requires a stable environment
that is dependent upon a considerable degree of certainty in the regulatory
arena. For generation investment, merchant generators cannot get financing for
investments without the guarantee of a multiyear power purchase agreement from
a regulated utility, which in turn requires certainty of cost recovery from
rate payers that can come only from the California Public Utilities Commission.
Despite these uncertainties, we have greater certainty about other aspects
of the system. Certain physical realities remain. There are chiefly two: first,
load levels and load growth are fairly predictable, at least over the short
and medium term. Regardless of who serves that load, it can be counted on to
exist and grow, at a modest 2 percent or so at least, over the next several
years. Second, the amount of electric generation available in the state today
is measurable. Again, this is regardless of who actually owns the capacity or
what entities are proposing to build new generation. So, it is possible to calculate,
within reasonable bounds, what the electric supply and demand balance is likely
to be over the next few years.
Thus, what we are actually addressing with a core/noncore market structure
is purely economic policy. We are struggling with how to allocate costs (and
therefore risk) among a series of actors in the market: customers, utilities,
generators, energy service providers and, for the last three, shareholders.
Each of these actors would like to minimize their risk, and it is the job of
regulators and legislators to balance that risk and ensure that it is shared.
The key element, therefore, becomes the application of uniform resource adequacy
requirements on all load-serving entities (LSEs) in the system. If all LSEs
are required to have under contract sufficient capacity and energy to serve
their customers, plus a reserve margin, there should be ample opportunity for
investment and profit, while spreading the risk of reliability failure among
a number of actors. One option for addressing this problem is the development
of a capacity market. In meeting the resource adequacy requirements, LSEs should
manage a diverse portfolio of types of resources as well as contract terms.
There should be business risk for all LSEs, investor-owned utilities (IOUs)
and energy service providers (ESPs) for prudent portfolio management.
Utilities know the costs of their retained generation in the past and on an
ongoing basis. The costs of the power contracts the state has with the Department
of Water Resources are finite and the time period is fixed. Recent and future
investment, either in the form of a physical asset or a contractual commitment,
is also knowable. Legal and regulatory requirements exist, to one degree or
another, that constrain our flexibility in allocating all of these costs. However,
there could be other creative ways of assessing charges to cover these costs,
without creating cost shifts or potential cost shifts among customers. The benefit
of this new assessment structure would be greater customer choice at an earlier
Current and future investments in generation have the same potential to become
future stranded costs. Thus, under any core/noncore model, we will need an ongoing
mechanism to guard against cost shifting.
Utilities argue that until their customer base is reasonably certain, they
are unable to make long-term investments in generation. The same is likely true
for ESPs. So, without certain entry and exit rules, no LSE is going to be willing
to make long-term investments. The scenario that most observers are worried
about is when an IOU invests in a long-term generation resource for a certain
forecasted future load, and then loses that load to a direct access (or noncore)
provider. In this situation, the concern is about remaining customers of the
IOU being required to pick up the cost of the generation investment.
In reality, if an IOU makes an investment that turns out not to be needed to
serve its future retail load, the IOU will sell its excess generation on the
wholesale market. If an ESP needs generation resources, it may buy the excess
IOU generation. This gives rise to the worry that there could be a socalled
death spiral, whereby IOUs invest in generation for a decreasing customer
base; that customer base migrates to direct access or noncore status, forcing
IOUs to sell their excess power at a loss on the wholesale market, finally leading
to cost shifts to remaining IOU customers, and further incentive for noncore
In this situation, it is also important to keep in mind that the size of the
potential cost shift, however, is not the full cost of the investment in generation
by the IOU, but the difference between the wholesale market price and retail
rates received by the IOU. This amount should be coverable by instituting reasonable
market rules for switching and cost responsibility principles. Structuring a
capacity market is another way to address this issue.
In discussing this alternative proposal for core/noncore structure, the following
principles are important to consider:
- Certainty of structure and rules is paramount;
- Cost causation;
- Rational rate design;
- Preserving reliability;
- Five-year planning horizons (supply and demand);
- Importance of aggregation as option; and
- Customer size threshold for noncore.
It is a fairly obvious and often-made point that certainty of market rules
promotes investment. Certainty, in this case, means not only a clear market
structure, but also clear implementation rules and time frames. We need to establish
a definition of which customers are core and are eligible for noncore; rules
for switching from core to noncore status and back again need to be clear and
stable; cost responsibility needs to be clear and calculable for customers making
In general, customers should pay for generation costs incurred on their behalf.
If an IOU makes a power plant investment while serving a particular noncore
eligible customer, for example, that customer should be responsible for paying
its fair share of the cost of that investment, even if it later elects service
from an energy service provider. This, in effect, covers the revenue requirement
of a generation investment.
Rational Rate Design
In addition to covering the revenue requirement, a wholesale effort is needed
to rationalize the rate structures for many customer classes to reflect the
true cost of serving those customers. Generally speaking, fixed costs should
be assessed with a fixed charge, while variable costs should vary by usage levels.
Moving toward real-time pricing and other tariff designs that allow rates to
fluctuate with costs is not only a principle necessary for a functional core/noncore
market structure, it is also likely to be a reasonable precondition.
As discussed, any market structure change should occur only in the context
of a stable resource adequacy requirement for all LSEs. If all entities serving
customers in the market are required to prove resource adequacy, then the system
in general should be resource adequate, regardless of which entity is serving
a particular customer.
This leads to a discussion of the provider of last resort issue. IOUs worry
that no matter how the market rules are structured, if some unanticipated situation
occurs and there is a system emergency, all customers will expect that they
will be able to switch back to their IOU provider and be served. The IOUs should
be the provider of last resort, but should be appropriately compensated for
fulfilling that role.
Most customers in the market have a one- to two-year planning horizon, while
most power plants cannot be built without at least a 10-year revenue stream.
The need to bridge this gap exists both for IOUs and ESPs, since both want to
be able to serve their customers at the lowest cost, which involves some long-term
commitments. To balance the risk and allow for reasonable planning horizons,
require a five-year commitment from customers to their core or noncore status.
This would mean that customers wishing to become noncore would pay a cost responsibility
surcharge for generation built or contracted for on their behalf while the IOU
served them. Likewise, a noncore customer who made an initial five-year commitment
to noncore status but wishes to switch back to the IOU, would have to pay the
market rate for the remainder of the five-year commitment to noncore. Switching
among non-IOU providers would not create additional cost responsibility, beyond
the five-year commitment, but if there was any IOU service in the interim, the
customer would pay the market rate.
Aggregation of customers under the noncore size threshold whatever it is
finally resolved to be is of critical importance to satisfying customer needs.
For a number of noncore customers, the advantages of noncore service will not
be limited to price, but will include such important customer service options
as innovative billing and metering services, more responsive customer service
representatives or the ability to serve statewide chain stores through one provider.
For example, a fast food chain with locations in all service territories could
have one noncore ESP that provides aggregated billing to the corporate headquarters
for all locations. No IOU can offer that service, by definition. Most fast food
chains would not come close to meeting a 200 kW-per-month size threshold at
each location/meter, but through aggregation, these types of customers needs
can be served.
Aggregation is also an important option for smaller customers wishing to choose
green power options. Without allowance for small customer aggregation, retail
ESPs with green portfolios would not be able to serve residential customers.
Customer Size Threshold
If aggregation is allowed, the size threshold required to achieve noncore status
becomes less important. A 500-kW threshold for monthly peak demand would create
an automatic noncore status only for the very largest big box retail stores
and office buildings, plus most industrial customers. A 200-kW monthly peak
demand threshold would capture a much larger portion of the commercial market.
The CPUCs preference would be for a 200-kW threshold, although 500 kW would
be satisfactory if aggregation of smaller customer loads is allowed.
Meeting the needs of utilities, independent power producers and Wall Street
is important, but should not be the primary function of the CPUC. We exist to
ensure that customers are served. In implementing a core/noncore in the structure
as outlined, we can give customers the choices they want and also meet the needs
of California and its power providers and generators.