BackDate: 16 February 1999
To: Wally Gibson
Adequacy Study Committee
From: Carol Opatrny, for the Public Power Council
Re: Response to the Proposed Policy Issues (Phase 2) Work Plan
At the last meeting of the Adequacy Study committee, you asked committee members to review your Phase 2 Work Plan and provide comment. These comments are in response to your request but also in response to the work effort in general.
While I find the Work Plan’s questions interesting in terms of an academic discussion, I do not think that additional effort by this committee is necessary to address what I believe is the essential, underlying question: Who has responsibility to secure adequate resources (both supply-side and demand-side) to meet forecast load on an expected basis, i.e., who is the Supplier of Last Resort, or SOLR? Please be aware that the following discussion focuses on retail level since BPA has responsibility to serve the region’s net requirements.
Below, I will address each of the outstanding questions that you have raised, that is, those questions that are not already being addressed by the technical analysis underway in the development of GENESIS and in the review of other analytical tools already available to the region. As you have, I will set aside questions surrounding how to define "adequate" resources and operating reserves. Although I find these most interesting and relevant, there appears to be a significant amount of effort already dedicated to answering these exact questions, e.g., NERC’s pending legislation regarding Reliability Standards. Although I have not been directly involved in such discussions, I am under the impression that many owners/operators of generating projects will want to continue to supply operating reserves, and that others, e.g., generating utilities, merchant plants, interruptible loads, etc. will also. Finally, I do not believe that the profitability (or lack thereof) of providing reserves is really an issue or is made significantly uncertain due to hydroelectric conditions.
Background
As we have discussed, the issue that has caused renewed interest in the SOLR is the potential for retail access. While the state of Montana has legislated such, other states in the Pacific Northwest region -- and in most of the country, for that matter -- have not taken final formal action to date. Nonetheless, by assuming that the momentum behind deregulation in this industry will eventually result in open access at the retail level, we have a responsibility to discuss who remains responsible to meet load, both on a firm and incidental (i.e., incremental load due to non-performance of alternative suppliers) basis.
After consulting Shelly Richardson, PPC’s Attorney, I have concluded that in the traditional regulated utility environment, an electric utility providing the public service within its defined service territory (e.g., the "public utility", the "electrical company", etc.) is the party with an obligation to serve the retail consumer. (See, for example, ORS 757.020 ("Duty of utilities to furnish adequate and safe service at reasonable rates." and RCW 80.28.010 "Duties as to rates, services and facilities.")). From this conclusion, I infer that the utility having an obligation to serve may be considered to have an obligation to provide service as a last resort. In fact, it is my understanding that this situation is typical across the country. When the Distribution Utility and its Control Area are one and the same, this responsibility, both operational and financial, is relatively straight-forward: The utility secures adequate generating resources to meet forecast loads and operating reserve requirements that are mandated by the NERC and the appropriate sub-regions, e.g., for this region, the WSCC and NWPP. If loads are not met, due to lack of supply, it seems clear under traditional regulatory standards that the utility remains responsible and will only be off-the-hook, if it has interruption or curtailment rights for unmet load. Further, the utility has the responsibility to ensure that the interruption or curtailment of so-contracted for loads will not affect service to other loads. In other words, the utility must have the physical ability to interrupt or curtail the so-contracted for load without affecting other loads, for which it has no right to interrupt.
This situation can of course be complicated by the fact that many distribution loads are located in another utility’s Control Area. In these cases, although the Distribution Utility remains the SOLR, load excursions are actually signaled to the Control Area Operator. In effect, the Distribution Utility becomes responsible to pay penalty charges imposed by the Control Area Operator since the Control Area Operator actually supplies the power. By way of example, in our region, many public agencies are responsible for distribution loads but are located in BPA’s Control Area. As a result, load excursions are covered by BPA, however, such behavior is discouraged and economic penalties (in the form of Unauthorized Increase charges) are levied.
In the event retail customers choose to seek power from alternative suppliers, e.g., any power supplier other than its Distribution Utility, the Distribution Utility may no longer be responsible to plan to meet that load on a firm basis, however, it remains operationally responsible, as the SOLR. This means that customers choosing alternative power suppliers may be served by their SOLR on an incidental basis, but the SOLR may no longer be responsible to secure long-term firm power supplies for such load. This new relationship will motivate the Distribution Utility to separately determine its financial responsibility as the SOLR, since (1) it is no longer the supplier of choice for certain customers and as such, its overall revenue requirements will change; and, (2) in the event the customer’s alternative power supplier does not perform, it will face incremental power supply costs or be on the hook for penalty charges. A change in financial responsibility will require the need for a different rate schedule or even a different contractual arrangement between the customer and its Distribution Utility (the SOLR).
The cost of providing SOLR "services" may change due to retail access for at least a couple of reasons. First, the cost of maintaining a firm power supply should go down (assuming the customer can displace or resell power supplies made excess), however, the utility may face incremental costs associated with securing back-up resources or replacement power supplies. This means that the SOLR will need to identify any net cost and allocate such to the customer seeking an alternative power supply either through a Distribution Service Charge or through a penalty fee at the time when the customer’s chosen power supplier doesn’t perform. In addition, the Distribution Utility’s rate schedule may need to be modified. And, finally, the contractual arrangement between the SOLR and the customer (and presumably between the customer and the alternative supplier) will have change and spell out terms and conditions such as: (1) obligation to supply replacement power (in the event the alternative supplier doesn’t perform); (2) cost of providing replacement power supply; and, (3) rights to interrupt or curtail (including frequency, duration, compensation, if any, etc.). In short, both the rate schedule and the requisite contractual terms and conditions should attempt to ensure that no costs resulting from a customer’s decision to purchase power from an alternative supplier are borne by the SOLR’s remaining customers.
In the event the Distribution Utility no longer provides a generation function, under the traditional regulatory framework it still remains responsible to secure adequate power supply to serve its distribution load, whether via contracts or hiring resource managers to do so. Here again, it appears that the contractual arrangement between the Distribution Utility and its generation function will require terms and conditions that specify the obligation to serve, the cost of emergency supply or non-performance, and rights to interrupt or curtail load.
Question 3: What are the current institutional constraints on the generation supply market, if any? Are they significant enough to be concerned about?
I do not see any significant impediments or institutional constraints on the generation supply market. In effect, the supply responsibility resides at the local level, the Distribution Utility or SOLR. This means that it becomes the Distribution Utility’s responsibility to know its load and directly or indirectly secure adequate supply (which may include demand-side management options). In short, Distribution Utilities that lose load to open access will need to become more contract-savvy in order to contain the risks and costs they might incur (directly, as a Control Area Operator and indirectly if located in another Control Area) if some of their distribution customers’ power suppliers don’t perform.
Therefore, I do not believe that deregulation (re-regulation) or the spinning-off of the generation supply function has created new impediments. I do, however, believe that it has discarded some efficiencies (both operational and financial) from which the region used to benefit due to regional planning efforts. This is because the deregulated, competitive environment does not foster sharing information but instead, falsely (in my opinion), fosters the notion that information is most valuable when deemed proprietary. In short, if there is one, I believe that the institutional barrier that will cost rate payers money will be the abandonment of sharing and coordination of information, such as generating units maintenance schedules, streamflow data, hydro operation forecasts, etc.
Question 4: What are the current institutional constraints on demand response to market conditions?
Along similar lines, I do not think that there are impediments to the demand-side market. Here again, the decision to rely on such for the purpose of avoiding outages will be made at the customer/Distribution Utility level. In fact, I have had the opportunity to research a number of load curtailment/interruption tariff provisions contained in various contracts (both for U. S. and Canadian utilities). This concept is not new or novel. Traditionally, the value for such was reflected in a contract which according to some, may not "send an efficient, real-time price signal" in today’s "more competitive" marketplace. Therefore, we may see changes in the price paid for interruption or curtailment, e.g., indexed prices. Otherwise, a contract will still be necessary in order to specify eligibility, contract term, duration and frequency of interruptions, notification, energy returns (if appropriate), non-compliance penalties, etc.
As an aside, I find interesting the expectation or rule-of-thumb, that 26% of this region’s peak load is available for interruption (Mr. Morlan’s assumption). I suggest that this region may have significantly less interruptible supply simply based on a quick review of BPA’s Whitebook (December 1997). The Whitebook indicates that the total DSI loads make up 28% of BPA’s average energy load; 17% of peak; and, assuming a 3000 aMW total DSI load, only 13% of the region’s average energy load; and, 12% of peak. Therefore, assuming that the DSIs would offer up all of their load (which I believe is about 75% too much), the rest of the region’s industries and large commercial loads would have to secure the remaining 14% or 3990 aMW
Question 5: What actions could be taken to make the market more efficient, both for supply entrants and demand-side entrants?
I believe that the market could be more efficient if it could turn back the hands of time to before functional separation was mandated. Without a "way-back machine", I assume that this model will not be repeated for sometime and suggest that we haven’t accumulated enough experience (and therefore don’t have adequate information) to conclude that the supply market in a deregulated industry is not efficient. Therefore, we should not attempt to fix what has not been demonstrated to be "broken".
Question 6: What actions are likely to lead to a dead end and should be avoided?
I suggest that we avoid doing more analysis. While I believe that the modeling effort is fun and interesting, our last meeting demonstrated that the modeling tools currently available were adequate to tell us (the region) that inaction will result in supply deficits and increase probability of loss of load. In short, I don’t believe that GENESIS will tell us anything new (even though it may be spiffier). If the effort continues, I strongly recommend that it stop short of attempting to identify: (1) the value of interruption (which I believe is a contract issue between a customer and the entity that wants interruption rights -- not an issue for regional analysis and regulation); and, (2) which loads should or should not be interrupted. I for one will hold my utility responsible for interrupting my load if it doesn’t secure adequate resources (or demand-side resources) and doesn’t have the contractual right to interrupt my service. And, presumably a Distribution Utility or SOLR will seek the least cost option for ensuring reliable supply for its load. This means that a market for such will be created upon need, e.g., when the utility faces load/resource balance. In short, the value of reliability or "unreliability" as you call it will by necessity be determined by the market. Furthermore, as the Council and other organs of government have discovered (unhappily from time to time), the public tends to regard as arrogant a protected, distant elite’s deciding which individual’s employment, comfort and convenience are more valuable to society than the next person’s.
Finally, I understand your interest in an efficient transmission network so that an efficient generation market is supported. However, I suggest that this issue is best handled by a group of individuals with some transmission planning and operating backgrounds, rather than the group that has been assembled to discuss generation supply adequacy and reliability. Also, I suggest that this issue not be discussed in isolation since its resolution depends upon the context in which it resides. In the meantime, I believe that significant information regarding transmission constraints is readily available in planning documents, seasonal constraint studies, OASIS postings, etc. Further, given the FERC’s "or pricing" policy, it seems that any entity interested in developing new generation will undoubtedly take transmission constraints (and potential incremental transmission costs) into consideration so that generation supply will not be islanded.
Conclusion
I hope these comments are helpful. I truly believe that the issue the group is struggling with is Supplier of Last Resort. Fortunately or not, the obligation to serve, and by extension the obligation (if any) regarding SOLR is a function of state law. State laws are, and will remain, unique, different one from another. And so, regional reconciliation of the same doesn’t make sense. I’m not at all convinced that the region, much less the Council (at the behest of BPA), can or should attempt to insert itself in a matter that is essentially within the domain of states. Most unfortunately, I am double booked on Thursday and so will not be present at our next meeting. Please call if you have any questions or comments and if you wish, please share this memo with the other committee members.
Back
Due to other engagements, I will not be able to attend on Thursday. However, I did want to get some thoughts to you on Wally Gibson's paper and Carol Opatrny's reply. Please feel free to distribute this note at your meeting.
In general, and most importantly, I agree with Carol's analysis and conclusions on the SOLR issue. This is a decision for state governments, state regulatory agencies, and the boards of locally regulated utilities, both in general policies and in negotiations with their end-use customers; this is not an area where the Council, the T-Board, BPA, or other regional entities should be acting.
A few clarifications, in my mind, are nonetheless in order.
1. BPA's obligation to serve is defined both in contract and in statute, and customers have in some cases specified BPA's responsibility to serve so that it is not a blanket or open-ended obligation. In other words, BPA has the responsibility to serve only those net requirements that are contractually placed on BPA, not just any net requirement. Many utilities have effectively waived the right to place their net requirements on BPA for specific periods of time.
2. Utilities may or may not be "on the hook" for interruptions or curtailments, depending on state and local policies. I seem to recall that damage to consumer equipment in PGE's territory last year was not reimbursed by PGE.
3. Some retail customers may eventually decide to change control areas. In this case, the load would be telemetered out of the local control area, and the Distribution Utility's responsibility might be limited to the physical maintenance of the wires, poles, transformers, and related equipment, plus some metering and information flow.
4. In a deregulated environment, information will become a commodity like any other, and we may end up with more or less information than we have had traditionally. Competitive markets tend to have more price discovery than regulated markets, so to the extent that we now have spot markets with posted prices, we have more information than we had previously.
Also, in the recent past, some federal agencies have reduced the amount of information traditionally available about future system conditions, claiming "proprietary" rights. Given that these actions are taking place without a complete transition to deregulated and competitive markets, I am not sure whether we should blame "the market" for this reduction in information.
5. The jury is still out on whether functional separation will make markets more or less efficient. There are valid arguments that transmission is likely to become more expensive, rather than less. It is also the case that Northwest prices are likely to rise during some periods and under some conditions, because barriers on trade between the Northwest and California are falling. However, the Supply System, arguably, has reduced its costs dramatically because of competitive pressures, and these pressures would arguably have been lower had the functional separation not occurred. Markets will tend also to "wring out" cross-subsidies, which should make individual decisions more rational.
6. The DREW effort is teaching us that transmission planning tools cannot provide the kind of information needed for good and complete generation planning studies and market price forecasting models. If any further analysis is performed, or new computer models built, I would recommend that transmission system forecasting is where the work is needed. With a better common understanding of the trade-offs among generation, transmission, distribution, conservation, and DSM, we might have a much better comfort level in letting market forces loose in the region and, equally importantly, knowing where we are not comfortable letting the market rule. I would note that NRTA has underway a "transmission adequacy" effort, which is, in my mind, where the work should take place.
On a related issue, we worry a lot about sending price signals that warn about additional transmission capacity needs, but we don't worry about the opposite. That is, FERC's open-access transmission tariff provides an opportunity for a transmission provider to surcharge a transmission customer when a request for service triggers a need for additional transmission capacity, but does not provide, as far as I can tell, for a similar credit when a new generation plant helps avoid transmission investments. This is a serious deficiency, in my mind, and it is not clear that FTR auctions will solve it.
LLP
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Lon L. Peters
Northwest Economic Research, Inc.
6765 S.W. Preslynn Drive
Portland, Oregon 97225-2668
503-203-1539 (voice)
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