J.         Long-Term Resource Adequacy

1.         To operate the transmission system reliably, the transmission operator must be able to balance generation and load at all times.  This requires adequate electric generating, transmission, and demand response infrastructure.  Some lead time is needed to develop adequate infrastructure for the future through self supply or bilateral contracting.

2.         Resource adequacy today must be assessed at the regional level.  Because all customers in an interconnected region are interdependent, a shortage of resources for some customers in the region can lead to a shortage for the entire region, which threatens reliable grid operations and risks sustained shortages with attendant high prices for the region. 

3.         We propose a resource adequacy requirement to provide for sufficient supply and demand resources to avert such shortages.  Under these procedures, we believe that involuntary curtailment will rarely if ever be employed.  However, consistent with current policies, the proposal must include procedures for such emergency conditions.

                        1.         The Reason for the Requirement

4.         The Commission proposes to adopt a resource adequacy requirement to help ensure development of the infrastructure needed for reliable transmission system operation.  Because electricity cannot be generated and easily stored for future delivery, extra generating and demand response resources are needed to serve a function similar to storage in the natural gas industry; other commodity markets would call these a supply inventory.  The cost of necessary reserves is analogous to the necessary cost of storage or inventory.

5.         A requirement to assure adequate long-term resources is currently needed because spot market prices do not consistently signal the need for new infrastructure in the electric power industry.  Most resources take years to develop and spot market prices alone may not signal the need to begin development of new resources in time to avert a shortage.  Moreover, spot market prices that are subject to mitigation measures may not produce an adequate level of infrastructure investment even after a shortage occurs.  Further, as long as regional resources are made available to all regional load-serving entities and their customers during a shortage, such entities have the incentive to lower their supply costs by depending on the resource development investments of others, a strategy that leads to systematic under-investment in infrastructure by all load-serving entities in the region.217

a.         Spot Market Prices Alone Will Not Signal the Need to Begin Development of New Resources in Time to Avert a Shortage.

6.         The spot market price does not yet work well to produce long-term reliability investment, even without price mitigation, for several reasons.  Extra resources need to be planned in advance for electricity because, when prices rise, demand is not reduced quickly and new generation cannot be added quickly.  Both the demand for electricity and the supply of new generating capacity generally respond very slowly to price. 

7.         Regarding demand response, most retail customers buy power at a regulated fixed price.  Even in states that have approved retail competition, customers are often shielded for years from price changes by a rate freeze.  They are unaware of hourly changes in the cost of producing electricity.  Electric meters are read monthly, and customers see only the imperfect price signal of a monthly bill rendered after electricity is used.  Although larger commercial and industrial customers can be more price responsive, for many of them electricity is a small fraction of their cost of doing business and may receive little managerial attention.   It takes time to develop the administrative rules and the technical capability to reduce consumption.  As a result, most demand today is unable to respond to real-time prices because of insufficient price information, inflexible rate designs, and metering limitations.

8.         The response of new generating capacity to price is slow because it takes time to plan, site and construct new electric power generating facilities.   Development of a new power plant takes two to five years or more, depending on the type of plant and its location.  It can take even longer to site the transmission lines needed to transmit the power to customers. 

9.         These factors together can lead to sustained periods of inadequate supplies, threatening the reliable operation of the bulk power system.  Insufficient demand response to price and the slow supply response to price can combine to produce electricity shortages that not only threaten reliability but also can raise day-ahead and real-time market prices significantly. 

10.       Further, rushing to relieve inadequate regional supplies and reduce high regional spot prices may bias construction choices toward supply resources that can be constructed quickly, perhaps sacrificing long-term cost minimization, environmental concerns and fuel diversity goals.  Most customers prefer spreading out resource capital costs over time to concentrating them into a peak period.  A resource adequacy requirement accomplishes this.

b.         Spot Market Prices That are Subject to Mitigation Measures May Not Produce an Adequate Level of Investment When a Shortage Occurs. 

11.       Customers object strongly to inadequate supplies—and high prices when supplies are inadequate—because electricity is essential for many uses and customers cannot turn to substitutes to reduce electricity demand.  Electric power drives modern life, and there is significant societal disruption from even short supply interruptions. 

12.       For these reasons, customers want protection from the exercise of market power that may occur when supplies are short, and some form of market power mitigation is needed under these circumstances, as discussed in the market power mitigation section.  However, market power mitigation may tend to suppress the scarcity price that would otherwise stimulate new resource development.  As a result, investors may not develop adequate infrastructure—making the problem worse—unless there is a provision for resource adequacy.  Such a provision helps customers by assuring adequate supplies and helps generation developers by creating a demand for resources in advance of electricity prices doing so alone.

c.         Load-serving Entities Will Underinvest in Resources Needed for Reliability if They Can Depend on the Resource Development Investments of Others. 

13.       In an interconnected region, the failure of some market participants to secure sufficient long-term electricity resources can contribute to a shortage that affects reliability and spot market prices for all participants in the wholesale power market.

14.       Under retail competition, load-serving entities competing for customers may compete on the basis of cutting the cost of forward contracting for resources unless they all are held to the same resource adequacy requirement.  Without such a uniform requirement, those suppliers that contract for reserves may lose market share, and those who do not may gain a market share – at least for a short period of time.  For this reason, a load-serving entity has an incentive to minimize its own costs by procuring few or no reserves and relying on others to develop reserves.  If the rules allow it, some load-serving entities will try to have the reliability benefit of adequate regional resources that other load-serving entities pay for or that uncontracted-for generation must offer pursuant to market power mitigation.

15.       Severe power shortages lead to public insistence on government intervention.  Both historical practice and recent events indicate that during a shortage those load-serving entities that have reserves are required by government to share them with those that do not have reserves.  There are at times state regulatory and gubernatorial requirements to protect customers from blackouts or high prices, a U. S. Department of Energy requirement for utilities to share power reserves in an emergency, or a Commission requirement to bid all available power into an organized spot market. 

16.       Some market participants depend on government intervention during severe shortages as an alternative to paying their share of the cost of developing adequate regional resources.  As long as regional reserves are made available to all, a load-serving entity can reduce its own reserve resource costs and rely on the resources of others.  The result is that all load-serving entities will tend to follow this strategy, leading to a systematic underinvestment in resources needed for reliability.218  The current physical configuration of the transmission grid often exacerbates this problem because it is often difficult to impose the results of one party's resource shortfall solely on that party.  For example, if several competing load-serving entities serve customers in the same electrical neighborhood, it may not be technically feasible to curtail some of these customers and not others during a shortage.

17.       These arguments persuade us to propose a long-term resource adequacy requirement in the Standard Market Design rule.  A resource adequacy requirement provides for timely development of supply and demand response resources to assure regional resource adequacy.  It helps smooths out the price swings of the electricity business cycle.  A well-designed resource adequacy requirement supports competitive markets if it allows suppliers to compete to provide infrastructure and buyers to choose the infrastructure with the best combination of features such as cost, reliability, environmental effects, and service life.

                        2.  Basic Features of the Requirement

18.       We propose to require, as set out in the proposed regulations, that an Independent Transmission Provider must forecast the future demand for its area, facilitate determination of an adequate level of future regional resources by a Regional State Advisory Committee, and assign each load-serving entity in its area a share of the needed future resources based on the ratio of its load to the regional load.  

19.       The Independent Transmission Provider must assure that each load-serving entity in its area acts to meet its share of the future regional needs—through self-supply, contracts to purchase generation, biddable demand or other demand response program.   The Independent Transmission Provider must apply standards, discussed below, to audit the adequacy of the plans of load-serving entities to meet the future resource needs of its area.  Moreover, the Independent Transmission Provider must check that resources are not double-counted by different load-serving entities.  In a region with more than one Independent Transmission Provider, each Independent Transmission Provider must coordinate this checking responsibility with all the Independent Transmission Providers in the region.

20.       If a power shortage occurs during which the Independent Transmission Provider is unable to satisfy demand in the spot market and also meet its reliability requirement for a minimum level of operating reserves, the Independent Transmission Provider must add a per-megawatt-hour penalty during the shortage to the price of energy taken from the spot market by a load-serving entity that did not meet its share of the regional needs for that year.

21.       Further, if the operating reserve level decreases to the point that the Independent Transmission Provider must curtail load, the Independent Transmission Provider must, to the extent possible, curtail the spot energy purchases of the load-serving entity that did not meet its resource adequacy requirement before curtailing the spot energy purchases of load-serving entities that did.  The load-serving entity is subject to such first curtailment during a shortage only in the amount by which it falls short of meeting its share of the resource adequacy requirement for the year in which the shortage occurs.219

22.       If a shortage remains after all such first curtailments are completed and additional curtailment is necessary, the remaining loads of the first-curtailed load-serving entities and the loads of other load-serving entities that have satisfied their resource adequacy requirement would be curtailed under the same protocol.  In this case the shortage may be attributable to certain load-serving entities of either type that, whether or not they may have met their resource adequacy requirement.  We expect that those load-serving entities that are short of their own reserves would lose service ahead of those that are not short. 

23.       The approach to resource adequacy proposed here is intended to assure the development of both new supply and demand response resources.  This approach focuses on encouraging payment to fund construction of future resources instead of avoiding payment of a penalty for inadequate current resources as in some current programs.  The forward-looking planning horizon provides time for market entry by new suppliers, which will help to check any market power among existing suppliers.220

24.       This proposal is designed to complement, not replace, existing state resource adequacy programs.  A vertically integrated utility satisfying a current state resource requirement that equals or exceeds its share of the resource adequacy requirement would not have to do anything more.  For those states that have retail choice programs in which retail customers or their suppliers buy power from a multistate region, we intend this approach to provide for regional adequacy in a way that no one state alone may be able to accomplish.

25.       The proposed approach is like the traditional reserve margin requirement imposed by states on monopoly utilities.  It worked well during most of the last century to ensure adequate supplies, and is still in use in most states, especially states that have no retail choice program.  However, because the traditional approach relies on individual utility plans and resources, it might not continue to work well in a region where utilities now rely on independent power producers in several states for new resources instead of their own new generation.  The traditional reserve margin requirement may also not work well in a region where some states have traditional monopoly utilities and others have retail choice because a shortages in one state can affect all states in the region.

26.       To continue to rely on the traditional reserve margin requirement, it has to be adapted to have a regional focus and to fit with competitive procurement.  We propose a resource adequacy requirement of this type.

27.       The resource adequacy requirement proposed here is unlike that of the three Northeast ISOs.  ISO-New England, the New York ISO and PJM each impose an obligation on load-serving entities known as an Installed Capacity (ICAP) requirement.  The three requirements differ, but share some basic characteristics.  We are reluctant to impose a national ICAP requirement, in part because of our concern about the effectiveness of the existing ICAP programs and in part because they were based on former voluntary tight power pools.  The three ISOs play a strong role in administering the program, a role that may not suit regions without a history of tightly coordinated reserve sharing. 

28.       The basic features of the proposed requirement are set out next, including discussion of the demand forecast, the level of resource adequacy, the role of the load-serving entity, the load-serving entity's share of the regional resource adequacy requirement, the types of resources that can satisfy the resource requirement, the standards that each type of resource must meet, the planning horizon, enforcement of the requirement, and regional flexibility.

            a.         Demand Forecast

29.       A Independent Transmission Provider would be required to do an annual demand forecast for its area.  The forecast would look ahead for the time period needed to add new supply and demand response resources.  We will refer to this time period as the planning horizon, a topic discussed further below.

30.       Demand forecasts have long been used in the utility industry to determine the need for future resources and to plan new infrastructure investments.  The Independent Transmission Provider may undertake a “bottom up” method of demand forecasting by adding up the demand forecasts of its component areas where they can be relied on.221  This may be accomplished through a collaborative process with all stakeholders.

                        b.         Level of Resource Adequacy 

31.       After the area's demand is forecast, the Independent Transmission Provider must assess whether the collective resource plans of load-serving entities in this area are adequate to meet the projected future peak need with allowance for adequate reserves.  In today's more competitive environment, the effectiveness of single-utility supply forecasts may be reduced.  Under open wholesale transmission access, regional patterns of energy flow can change quickly, making single-utility transmission planning difficult.  Generators sited in a utility's service territory, if not under contract, may export power to another area or region.  Single-utility forecasting is also more difficult today because power market information is considered very sensitive.  Competitive suppliers are reluctant to share this information with a utility that is a potential competitor.  A regional assessment of regional supply adequacy by one or more independent entities in the region would help overcome these difficulties.

32.       Further, close coordination is needed between those planning generation and transmission because the location of planned generation affects the location of planned transmission and vice versa, and an Independent Transmission Provider (or a group of Independent Transmission Providers acting collectively in a region with more than one Independent Transmission Provider) is in the best position to coordinate these planning functions.                           

33.       Once the future level of supply and demand resources is determined, the region must assess whether this level is adequate.  This requires a regional determination of the appropriate level of resource reserves, for example, whether the reserve margin (if reserve margin is the region's measure of resource adequacy) should be 12, 15, 18 percent, or another level.  We seek comment on and encourage regional discussion of appropriate planning targets in energy-limited areas, specifically on how to incorporate volatility of annual hydropower supply.

34.       Each region should take its own characteristics into account when determining the appropriate level, subject to a minimum level of resource adequacy for all regions discussed below.  This determination has been made by load-serving entities under the oversight of the states, and we want this state oversight to continue.  We propose that the level should be set by a Regional State Advisory Committee.222  States in the region should have this strong role in determining the level of resource adequacy because a higher level provides greater reliability and also incurs higher costs that affect most retail customers.  State representatives are in the best position to determine on behalf of retail customers the trade-off between the cost to the customers of extra generation and demand response reserves and the difficult-to-quantify benefits to the customers of increased reliability and reduced exposure of the region to the effects of a power shortage.

35.       We will require the Independent Transmission Provider (or the several Independent Transmission Providers in a region with more than one such Provider) to provide a forum and assistance to the Regional State Advisory Committee to establish the appropriate level of resource adequacy for the region.  Because many Independent Transmission Providers encompass more than one state (or province), the Independent Transmission Provider's role as a facilitator will be helpful in establishing the regional reserve level.

36.       However, we ask for comment on what fallback provision should be employed if the Regional State Advisory Committee does not reach agreement on the appropriate level of resource adequacy.  We believe that having different reserve levels in different states in the same region maintains the problem of some customers relying on the reserves of others.

37.       We are concerned that the requirement be set so that the Independent Transmission Provider can operate the interstate transmission system reliably with real-time operational resource adequacy.  We are also concerned that inadequate resources could lead to poor market liquidity and even shortages with sustained high wholesale power prices.  For these reasons, we propose to adopt a 12 percent reserve margin223 as a minimum regional reserve margin for all regions with the understanding that this is low by traditional generation adequacy standards and that the Regional State Advisory Committee in each region may set this number higher for the region to achieve greater reliability.  We selected a 12 percent reserve margin as a minimum in that it is two-thirds of the typical historical reserve margin target of 18 percent for large utilities.224  We emphasize that most utilities historically used a reserve margin well above 12 percent.  This 12 percent reserve margin is intended to be a safety-net level in planning for reliable future transmission and market operations and not to be the target reserve level for the region that should be established by the Regional State Advisory Committee.

c.         Load-serving Entities

38.       Each load-serving entity must satisfy a portion of the regional resource adequacy requirement.  Load-serving entity here means any entity that uses transmission in interstate commerce to provide power to load, whether a traditional distribution utility or an energy service supplier that aggregates retail loads under a retail access program.

39.       A large retail industrial or commercial customer that has retail access rights and buys power directly from suppliers is also considered a load-serving entity.  If it does not buy power from another load-serving entity but uses the interstate grid to buy power directly from a supplier, it too would be required to meet its share of the resource adequacy requirement.  As for other load-serving entities, their reserves may include the ability to reduce their own demand on the grid.

40.       A load-serving entity may choose a higher level of reliability by developing more supply or demand response resources than required.  Further, a load-serving entity may choose greater reliability and price assurance by procuring additional reserves for its own use.  In particular, customers in a load pocket that is served by a few large generating units may need a higher reserve margin to have the same level of reliability as customers outside a load pocket.

d.         Load-Serving Entity's Share of the Regional Resource Requirement

41.       Once the future regional requirement is determined, each load-serving entity’s share of the regional requirement must be determined.  Meeting a regional resource adequacy level does not assure that every part of the region has adequate resources if there are internal transmission constraints or if resources are counted that may be sold outside the region, retired before needed, or otherwise made unavailable.  For these reasons, it is important that resources not be considered merely regional but be associated with and committed to particular load-serving entities.

42.       We request comment on two methods for determining each load-serving entity’s share of the regional requirement.  One is to allocate the future resource adequacy needs to loads based on each load’s forecasted future demand.  For example, if the load forecast is for three years ahead and a particular load is growing faster than the regional average, its share of the adequacy requirement could be based on its forecast load ratio share for three years ahead, not on the present load ratio share.  This method assigns more adequacy responsibility – and cost – to faster growing loads.  However, if the Independent Transmission Provider’s forecast is made through a “bottom up” method that adds up individual load forecasts, it must rely on each load to report its growth rate accurately.  This approach creates an incentive for loads to understate their growth to lower their resource costs.

43.       The other method is to allocate the future adequacy requirement to loads based on each load’s most recently documented load ratio share.  This method is less subject to manipulation.  However, an area with a slow load growth located within a region of generally high load growth may subsidize the high reserve needs of its neighbors.

44.       We ask for comment on which of these two methods the Commission should choose in the Final Rule.  Alternatively, we ask whether this issue should be left to regional determination.

45.        Once each load-serving entity’s share of the regional adequacy requirement is determined, the Independent Transmission Provider must inform each load-serving entity of its share.  It must require each load-serving entity to report and document how it plans to meet its adequacy requirement.

46.       The time available to the load-serving entity from being informed of its resource share to having to report to the Independent Transmission Provider must be adequate to allow it to develop arrangements for meeting future resource needs.  We ask for comment on how much time is needed for these purposes.

e.         Resources That Can Satisfy the Resource Needs

47.       Each region’s resource adequacy requirement could be satisfied by a combination of generation, transmission, and demand response infrastructure.

                                                (1)       Generation and Transmission

48.       The supply requirement could be satisfied by self-owned generation, local distributed generation, or firm bilateral contracts for power that are backed by specific generating units (or a portfolio of designated generation units).   The firm bilateral contract could be either a forward contract for the purchase of power or an option to purchase energy under specified shortage or price conditions, as long as the firm contract is backed by specified generating units.

49.       In any of these cases, the generator must be committed to supply power to the load-serving entity, at least under certain conditions.  Self-owned generation that is committed to another load-serving entity, unless it can be recalled during a shortage, would contribute to the other load-serving entity's requirement, not the requirement of the load-serving entity that owns it.  Generation under contract must specify that the generator will be available to the load-serving entity – or at least to the market that the load-serving entity participates in – under  conditions set out in the contract.  These conditions, discussed further below under generation standards, must be adequate to meet the region's need for reserve resources.

50.       The firm contract would be for a forward-looking period that would at least cover the planning horizon, which (as discussed further below) would be selected regionally and should be based on the time needed to develop new resources in the region.  The load-serving entities must also demonstrate that future use of the designated resources is physically feasible and, in particular, that transmission is or will be available to deliver energy from a generator to the load-serving entity that claims it in its resource plan.

                                                (2)       Demand Response

51.       Allowing demand response infrastructure to satisfy the requirement removes bias toward exclusive reliance on new generation to meet regional needs.  Better demand response to high prices when a shortage condition approaches will lower demand and reduce the use of high-cost power resources.  Demand response will help ensure reliability, prevent a shortage that could produce a curtailment, act as a check against market power, and provide a yardstick for the value that buyers place on supply. 

52.       Biddable and interruptible load can satisfy the resource adequacy requirement as well as generation.225  A load-serving entity that does not want to pay for generating reserves can substitute a demand response alternative to meet its resource adequacy requirement.  Under some state programs, the larger retail customer may be rewarded for reducing its electric use in addition to enjoying a reduced bill for reduced consumption.  Several states have this type of biddable load reduction; it is one way to allow the customer to determine how much it is willing to pay for power.  Further, competitive energy service suppliers can compete for load by offering lower rates to customers who agree to participate in demand response programs such as remote air conditioner cycling, aggregate building load management, and other proven demand response and load management options.

                        3.         Resource Standards

53.       The Independent Transmission Provider must determine if each load-serving entity’s planned resources meet certain standards.  The resources must meet the standards to count toward satisfying the entity's share of the regional resource requirement.  Both generation and interruptible or biddable load must meet standards to satisfy the requirement.

54.       We propose here certain minimum standards for comment.  We also are considering in the Final Rule to ask the North American Energy Standards Board (NAESB) to develop more detailed standards for determining whether resources satisfy the resource adequacy requirement, and we seek comments on this approach.

            a.         Generation Standards

55.       Generation must be owned by or under contract to the load-serving entity and committed to meet the resource needs of the load-serving entity at least during certain conditions such as an operating reserve shortage.  The Independent Transmission Provider must be satisfied that the generation is physically feasible; that is, the generating units are capable of generating the power planned, and enough transmission is available to deliver the power from the generating station to the particular load.  The generating units under contract must be real and specific generators.  This is so that only real generation that can avert a supply shortage is counted and so that its transmission over the grid can be assured.  For example, it does no good for a load on Long Island to claim a generator in western New York as a resource if the power cannot be delivered to Long Island during a Long Island shortage.

56.       Because the purpose of this requirement is to encourage the development of new resources including new generation, generation under contract for development within the planning horizon should satisfy the requirement.  Should the Commission specify the contract content needed to rely on generation under development?  If so, should we refer this matter to NAESB to determine the content?

57.       For these reasons also, a contract with a marketer to deliver power at a future time from unspecified sources cannot satisfy the requirement.  The purpose here is not to transfer financial risk for nonperformance to a marketer but to ensure performance, that is, to ensure that enough actual, deliverable generating capacity is available or developed at satisfactory locations to avert a future shortage.  However, a forward contract with a marketer that is linked to specific generation and demonstrates transmission adequacy would satisfy the requirement.  We ask for comment on whether we should allow a liquidated damages contract for power from unspecified sources to be included in the resource adequacy plan, and also on whether we should allow a load-serving entity that initially fails to satisfy the resource adequacy contract, but later brings in new resources under a liquidated damages contract for the amount of its resource deficiency, to avoid the penalty price and first curtailment in the spot market during a shortage.

            b.         Transmission Standards

58.       Generation must be deliverable to satisfy the requirement.  A Congestion Revenue Right for the appropriate year is one way to satisfy this requirement.  We propose to adopt a practice (used in PJM) that allows a resource owner to pay for the development of adequate transmission to deliver its energy to a load and then to sell its Congestion Revenue Rights while still satisfying the requirement that its generation be deliverable.  Should a commitment by any load-serving entity to pay congestion costs no matter how high also satisfy the requirement?  If so, how should the Independent Transmission Provider respond if the sum total of all such commitments exceeds the available capacity of a bottleneck interface?

59.       A robust transmission system with few constraints may allow a load to rely on generation and demand response reserves that are farther away than if the transmission system is weak.  Supply reserves that are not deliverable to the load claiming them when needed cannot be counted as satisfying that load's reserve requirement.

60.       For transmission as well as for generation and demand response, the purpose of this requirement is to encourage the development of least-cost resources, which may include new transmission needed to access existing or new generation.  We believe therefore that planned transmission with full siting approval and completion expected within the planning horizon should satisfy the adequacy requirement.

            c.         Demand Response Standards

61.       Demand response must also be verifiable to satisfy the adequacy requirement.  The Independent Transmission Provider must have confidence that the demand response resource will be able to contribute when called on during a shortage.  Demand response may be obtained through biddable demand reduction, interruptible load, or other dependable load management program.  Distributed generation that is interconnected with a customer, a load-serving entity, or an energy services company, although it is technically generation and not demand response, can also be used by a local distributor to reduce the demand that the distribution system places on the grid. With biddable demand reduction, certain loads will be assured of dropping off the system at known price levels; the amount of load dropped should increase with the price. 

62.       With interruptible load, a customer pays a lower power price year round but will be interrupted under defined shortage conditions; the load is subject to a simple on-off criterion.  An important feature of this proposal is that the load-serving entity plan that depends on interruptible load to meet its resource adequacy requirement must be capable of being implemented.  The Independent Transmission Provider may require, for example, that the load-serving entity install equipment that gives it direct control over the loads of the customers that are subject to the interruption.  We recognize, however, that installation of such equipment may be too costly or otherwise impractical in some situations.  In that case, the load-serving entity must have a satisfactory arrangement for implementing its interruptible load program under the instructions of the Independent Transmission Provider. 

63.       If load in an area "buys" demand reduction from another area (in effect buying some of that other area's freed-up generation), the transmission needed to deliver the freed-up generation to the load that relies on it must be available.

                        4.         Planning Horizon

64.       The purpose of a forward-looking resource adequacy requirement is to create a demand for new resource entry in advance of a shortage so that enough supply construction and demand response infrastructure installation are begun in time to avert the shortage.  The planning horizon for each region is the number of years ahead for which the Independent Transmission Provider must forecast annually its area's load, as well as the number of years ahead for which load-serving entities must show that they have adequate resources.  For example, the Independent Transmission Provider could forecast its area's peak load three years from the present and require that each load-serving entity in its area have acceptable plans today to have enough resources three years from now to meet the forecast peak with a reserve margin of 12 percent.  In this example, the planning horizon is three years and the reserve level is the minimum 12 percent.

65.       The choice of the planning horizon affects the lead time for construction and the duration of forward contracts that can satisfy a resource adequacy requirement.226  The traditional state-required electric company planning horizon was 10 to 20 years.  The horizons were established when the industry relied on new large hydroelectric, coal, or nuclear facilities to meet growing load, and these facilities could take 10 or more years to site and construct.  Today, most new resources are planned and developed over a much shorter time frame, in part because of the reliance on low cost natural gas.  However, this planning horizon could change again if natural gas were no longer the main fuel of choice.

66.       Because the planning horizon should be no less than the time frame for developing new resources and development times vary from region to region, the planning horizon can depend on that region's reliance on coal, gas, wind, hydropower or new demand-response technology for new supply.   This argues for allowing each region to determine its own appropriate planning horizon. 

67.       We propose to make the planning horizon a matter for regional choice.  Regions should consider several factors in selecting the planning horizon.  Most important, the planning horizon chosen should not be so short that it fails to motivate and achieve construction of generation and demand response resources in time to avert a shortage.  Greater fuel diversity may be achieved with a longer planning horizon.  If the horizon is short, two years for example, load-serving entities may have an incentive to select resources that can be developed in two years or less, such as peaking units and some other gas-fired generators.  A longer planning horizon allows time for development of other resources such as coal-fired generation, hydroelectric resources, and some advanced demand response programs.  Load-serving entities in retail choice states would benefit from a shorter planning horizon because it would reduce their business risk associated with demand forecast error.  Also, they may not want to enter into bilateral contracts for supplies for a time period that is longer than the duration of their contracts with their customers.

68.       We propose to have the Regional State Advisory Committee determine the planning horizon for the region.  The Independent Transmission Provider (including each Independent Transmission Provider in a region with more than one Independent Transmission Provider) must provide information and support to the Committee, as requested, to help it to determine the region's planning horizon.  We request comment on how to resolve any lack of consensus within the Committee regarding the appropriate planning horizon.  We also ask for comment on whether the Commission should establish limits on the region's choice of planning horizon, such as at least three years and no more than five years.

69.       We also ask for comment on whether to have a resource adequacy requirement before the end of the first planning horizon period.  For example, if the horizon is three years, should there be a requirement for resource adequacy in the first two years?

                        5.         Enforcement

70.       Here we explain in more detail our proposal to enforce the resource adequacy requirement, along with some alternative enforcement procedures, and ask for comment on the most effective enforcement method.

71.       Unlike some ICAP requirements, the approach adopted here does not require a load-serving entity to pay a penalty in the near term for failure to have adequate future resources.  Our proposed approach relies primarily on two enforcement mechanisms: (1) a Commission-set tariff penalty imposed on a load-serving entity that threatens reliable transmission operation by taking energy from the spot market during a shortage in a year for which it fails to meet its resource adequacy requirement, and (2) a Commission requirement that the spot market electric service of such a load-serving entity must be curtailed first when the shortage that is severe enough to require that some customers be curtailed.  Each of these mechanisms, the penalty rate and the load curtailment, would occur at the end of the planning horizon, not the beginning.227

1.         The first mechanism applies during a power shortage in which the Independent Transmission Provider is unable to satisfy demand in the spot market and also meet its reliability requirement for a minimum level of operating reserves.228  As a shortage develops, price is expected to increase in the spot energy market.  A load-serving entity that is short on self-generation, bilateral contracts (including affiliate generation and call contracts), and demand response resources will be dependent on the spot markets to meet its resource needs.  The rising price in the spot market is, of course, a principal incentive for the load-serving entity to develop adequate supply and demand resources.  If shortage conditions develop to the point where the Independent Transmission Provider cannot serve all load and maintain the minimum level of operating reserves, it must take some action to maintain reliable operation.  Some load must be given either an economic incentive to exit the spot market or an order to stop taking power from the spot market.  We propose that these measures be applied first to the load of the load-serving entities that did not meet their share of the resource adequacy requirement.  However, the load-serving entity is subject to a penalty and first curtailment during a shortage only for spot energy purchases 229 and only in the amount by which it falls short of meeting its resource adequacy requirement.

1.         Specifically, we propose that during such a shortage the Independent Transmission Provider must add a per-megawatt-hour penalty price to the price of energy taken from the spot market by a load-serving entity that did not meet its share of the regional needs for that year.  This rate would apply only to spot energy purchases, not to power received from the load-serving entity's self-generation or bilaterally contracted energy.  However, it would apply to spot market energy sales needed to correct for imbalances associated with energy from these sources.  We would set the penalty price high enough that we do not suggest that failing to meet a resource adequacy requirement and paying a penalty rate is an acceptable alternative to developing new resources, which would be the case if the paying the penalty appears to be less costly over time. 

2.         The penalty price would increase in stages as the shortage becomes more severe.  For example, the penalty price could be $500 (in addition to the spot market energy price) when operating reserves are just below the minimum level, $600 when operating reserves are more than below 1 percent below the minimum level, $700 when operating reserves are more than 2 percent below the minimum level, and so on.  We ask for comment on having such a graduated penalty and the appropriate penalty rates.

3.         This first enforcement mechanism provides a price-based mechanism to enforce a resource adequacy requirement and to restore the transmission system to a reliable condition.   Most system operators – and their regulators – treat load curtailment (voltage reductions and blackouts) as a last resort measure, and operators may violate the reliability rule for minimum operating reserves rather than implement a load curtailment to satisfy the minimum operating reserve criterion.230  We believe that the penalty price should be set high enough to bring about voluntary load reduction by a load-serving entity and thus restore the system to a reliable condition.

4.         The second enforcement mechanism is applied when the operating reserve level decreases to the point that some load must be curtailed.231  The spot energy purchases of that load-serving entity load would be reduced by the amount of its resource deficiency and consequently some of its customers would be curtailed before the loads of other load-serving entities.232

1.         In support of this second mechanism, we will require the Independent Transmission Provider to inform the load-serving entity's state regulatory authority233 if the load-serving entity fails to submit a satisfactory plan for adequate future resources, thereby exposing its customers to possible penalties and future first curtailment during a shortage.  Our intent is to rely on the traditional state role of enforcing a load-serving entity's reserve obligation.  We believe that in most cases the state regulatory authority would prefer to have the load-serving entity meet the adequacy requirement as a condition of doing business in the state, rather than expose its retail customers to first curtailment.  The state regulatory authority may wish to consider any decision of a load-serving entity not meet its resource adequacy requirement.  It may want to ask the load-serving entity to identify which of its customers will be subject to first curtailment if the region is short of power.234   

1.         If the Independent Transmission Provider does not have direct control of the circuit equipment needed to implement a curtailment and relies on the load-serving entity to follow its instructions to implement a curtailment, the load-serving entity would be subject to a severe penalty for the unauthorized taking of power from the spot energy market because this jeopardizes grid reliability.  We propose to charge the applicable Locational Marginal Price plus $1000/MWh for all unauthorized energy taken following an instruction to implement curtailment.235  We also seek comment on whether the $1000/MWh penalty would be sufficient to deter unauthorized taking of energy and, if these penalties are paid, who should receive these revenues. 

2.         We believe that load-serving entities, under these enforcement provisions and under the oversight of state regulatory authorities, will meet their resource adequacy requirement and not be subject to these curtailment penalty and first curtailment provisions at all.  If most meet the requirement as we expect, shortages and first curtailment of any that do not should occur infrequently.

3.         Having presented our enforcement proposal, we suggest variations of this proposal and ask for comments on these alternatives.  As mentioned, under our proposal the penalty rate or load curtailment would occur at the end of the planning horizon, not the beginning.  However, we ask for comment on this approach compared to an alternative approach that may provide a more immediate and effective incentive to a load-serving entity to take action to provide for future resources well in advance of facing a penalty or first curtailment.  This is to impose a penalty on the load-serving entity immediately (that is, in year 2004 to continue the example in an earlier footnote) if it fails to submit a satisfactory plan to meet its 2007 resource adequacy requirement.  We did not propose this option as our first choice because it has some of the unfavorable features of some ICAP programs that focus more on avoiding immediate penalties than on motivating long term resource development.  However, we ask for comments on the merits of this alternative approach. 

4.         As presented, the Independent Transmission Provider audits the plan of each load-serving entity only at the beginning of the planning period (in 2004 in the example above).  We are concerned that a load-serving entity may submit a satisfactory plan but fail to fully implement the plan.  The proposal permits but does not require the Independent Transmission Provider to audit each year the progress of the load-serving entity in implementing its plan, and we ask whether we should explicitly require this.  If the load-serving entity's progress is unsatisfactory, should the Independent Transmission Provider find that it fails to satisfy its resource adequacy requirement?  If the load-serving entity implements its plan but some of its resources fail to perform when needed during a shortage, should that load-serving entity, in addition to having a greater need for spot market energy at a presumably higher spot market price, also be subject to either of the enforcement mechanisms set out above?

5.         Another feature of our proposal is that it would not affect electric service from the self-generation and bilateral contracts of a load-serving entity that fails to meet its resource adequacy requirement (except that it would be subject to a penalty price during a shortage for balancing energy in the spot energy market).  We ask for comment on whether this proposal unduly weakens the incentive to develop regional resources and whether, in the alternative, the Independent Transmission Provider should first curtail service to the load serving entities that failed to meet their share of the resource adequacy requirement, including transmission service from resources acquired outside the spot market, freeing up those resources for the use of those that planned adequately.

6.         Finally, our proposed enforcement mechanisms are designed to create an incentive to avoid a future penalty or first curtailment.  During the public outreach process for developing this proposed rule, some commenters recommended a stronger Independent Transmission Provider role in compliance with a mandatory resource adequacy requirement.   One proposal is for the Commission to require the Independent Transmission Provider to procure resources on behalf of load-serving entities that fail to meet fully their requirement and charge them for the cost of the resources.236  Another is for us to require the Independent Transmission Provider to either (1) calculate an expected capacity deficiency and purchase the call options necessary to meet the adequacy requirement on behalf of the load-serving entities, allocating costs pro rata, or (2) require load-serving entities to purchase reserves at the price produced by an Independent Transmission Provider-run auction.237

7.         These approaches have advantages as well as disadvantages.  Among the advantages are that they provide a greater assurance of achieving adequate resources and avoid the possible pitfalls of applying penalty rates or first curtailment.  Among the disadvantages are that they take away one demand response option, namely curtailment, from the range of policy choices.  Also, the latter approaches appear to require the Independent Transmission Provider to take a position in the capacity market, which places the Independent Transmission Provider in a role that may be incompatible with its independence.238

8.         What is the effect of these alternate enforcement mechanisms on the incentives and business risks of the load serving entities in the region?  Is there another enforcement mechanism that is both appropriate and effective?

                        6.         Regional Flexibility

9.         We propose to apply the requirement set out above to all regions, including regions that already have an ICAP requirement that has been previously approved by the Commission.  This requirement would replace the current ICAP program. 

10.       Some regulators, customers, and market participants have expressed dissatisfaction with the ICAP models presently in place.  Some customers view ICAP as an added cost with no tangible benefits; they assert that the commodity being traded has little value because customers are paying for installed capacity but not receiving any greater assurance that generation adequacy is maintained.  Some commenters say that, in some ICAP programs, a generator can receive an ICAP payment and later be released from the ICAP obligation for a relatively small penalty to sell its capacity in another market with a high wholesale price.

11.       Existing local generators are said to have preferential ability to participate in the ICAP market.  The ICAP payment goes to the existing generators and does not necessarily lead others to enter the market to increase capacity.  Depending on how the ICAP rules are designed, existing generators may be able to exercise market power, forcing up ICAP prices.  In some markets, trading has been so thin at times that there is a question about whether there is a competitive market price. 

12.       In some such cases, the ISO has intervened to set the price administratively, and market participants are concerned that the price does not reflect the forward value of generating capacity.  Some contend that prices in the spot markets and bilateral markets, including long-term forward contract markets, appear to be not well correlated with ICAP market prices. 

13.       The generators object to ICAP price controls.  Some power generators see short-term ICAP payments as providing inadequate assurance of capital cost recovery to motivate new investment.  They prefer longer-term contracts to ensure that their investment costs will be recovered.

14.       Finally, many parties object that ICAP focuses on power generation, ignoring the potential of demand response.

15.       Although we propose that every region must adopt our approach, this approach offers significant regional flexibility.  Our approach allows each region to set its own level of resource adequacy, set its own planning horizon, and select from a combination of supply and demand response resources for meeting its needs.

16.       Our proposal permits but does not require a region to have its Independent Transmission Provider establish a market for acquiring and trading adequate resources.  We believe that the bilateral market and other means can be adequate for acquiring and trading resources.  Nevertheless, we ask for comment on whether, under the approach to resource adequacy proposed here, we should require an Independent Transmission Provider to create a market to facilitate load-serving entities meeting their resource adequacy requirement efficiently.

Despite the flexibility of our proposed approach, regions with a historical reliance on a tight pool for sharing reserve may argue for a continuation of some form of ICAP program.  We ask for comment on how existing Commission-approved ICAP mechanisms can be transitioned and modified so as to be made consistent with our resource adequacy proposal here without disrupting financial commitments made under existing rules.  What are the disadvantages of particular elements of the ICAP approach that should be avoided in the approach proposed here?  Do any of the enforcement proposals or alternatives discussed above re-introduce any such disadvantageous elements?  


217For further discussion of these topics, see e.g., Steven Stoft, Power System Economics (IEEE Press, Wiley-Interscience, 2002) especially "Fallacy: The 'Market' Will Provide Adequate Reliability."

218This is the well-known "free rider" problem for public goods, those for which consumption cannot be limited to those who paid for them (such as parks and national defense) and that are available to all users even if only some users pay for them.  See, e.g., Lee S. Friedman, The Microeconomic of Public Policy Analysis, Princeton University Press (Princeton, NJ 2002), which states at pages 597-598:

 

If their provision were left to the marketplace, public goods would be underallocated.  The reason is that individuals would have incentives to understate their own preferences in order to avoid paying and free-ride on the demands of others.  Thus, public goods provide one of the strongest arguments for government intervention in the marketplace: not only does the market fail, but it can fail miserably.

219 A load-serving entity that continues to take spot market energy despite the curtailment order of the Independent Transmission Provider would be subject to a very high penalty under the tariff.

220A regional resource adequacy requirement should also provide substantial evidence of need for infrastructure to investors as well as to siting authorities.  This should aid suppliers in acquiring financing and should facilitate siting decisions.  An added benefit may be the ability to better predict, plan, and finance new transmission system facilities associated with these resource requirements.

221A load-serving entity has an incentive to underestimate its future load if doing so would reduce its share of the resource adequacy requirement.  For an analysis of bias in demand forecasts, see Mark Bock, "Analysts hunt for bias in NERC forecasts," Electric Light & Power, July 2002.

222See the following section, State Participation in RTO Operations, for a discussion of the composition of the advisory committee.

223The reserve for a period is the amount of resources expected to be available during the period less the forecast peak load during the period.  The reserve margin is the ratio of the reserves to the forecast peak load during the period, expressed as a percentage.  A region may use another measure of adequacy as long as the minimum level is the arithmetic equivalent of a 12 percent reserve margin.  For example, many use capacity margin, which is the ratio of the reserves to the amount of resources expected to be available during the period, expressed as a percentage.  A capacity margin of 10.7 percent is the same as a reserve margin of 12 percent.  Some may measure adequacy with a loss-of-load probability, called LOLP, which is a statistical measure of the expected total time during a period that generation will be unable to meet load.  The common U.S. standard is one day in ten years, which means that the sum of the hours (or fractions of hours) during a ten-year period when generation is expected to be short is 24 hours.  Reserve margin cannot be translated directly into LOLP without studying a particular system.  For example, an area served by a few large generators is more vulnerable to a shortage caused by an outage of one or two large generators than a similar area served by many smaller generators.  The area with a few large generators may need a larger reserve margin to achieve the same LOLP.  A general rule-of-thumb for a large U.S. utility system is that an LOLP of one-day-in-ten-years is achieved with a reserve margin of about 18 percent.

224The target level of these reserves, often called planning reserves, is not the same as the operating reserve level, a subject treated further below. 

225The traditional reliability reserve margin allows interruptible load to be counted equally with generation resources, with some exceptions.

226For example, forward-contracting for supply with one-year contracts that begin today and end after one year would not satisfy an adequacy requirement with a three-year planning horizon.  A one-year contract for the third year forward would satisfy the goal for that year.

227For example, if the planning horizon is three years, a demand forecast would be made in 2004 for the year 2007.  The Independent Transmission Provider would assess the adequacy of resources for 2007 and allocate the resource adequacy requirement for 2007 among the load serving entities.  The entities would submit to the Independent Transmission Provider in 2004 their plans to meet their share of the 2007 resource adequacy requirement.  An entity fails to submit in 2004 a satisfactory resource plan for 2007 would not be subject to the penalty rate or be among the first curtailed during a shortage in 2004 but would be subject to the penalty rate and be among the first curtailed during a shortage in 2007.  Next year, in 2005, the same process repeats: the Independent Transmission Provider would forecast demand in 2008, and so on.

228Operating reserves are generation and demand response resources needed to keep the system in balance, follow changes in load, and make up for a "contingency" such as the loss of the largest generating unit or of a major transmission line that delivers more power than any one generating unit.  The North American Electric Reliability Council and the regional reliability councils set rules regarding the minimum operating reserves that must be maintained by the system operator for reliable operation.  The rules are expressed in a formula so that the value of the minimum operating reserves changes during the day with load conditions and with the sources of supply.  Typically, for a large utility, the minimum operating reserves are in the range of 5 to 8 percent of load, but this can vary significant with changing conditions.  An operator that operates with less than minimum operating reserves threatens not only its own reliable operation but the reliability of its electrical neighbors.

 

229These actions apply to spot energy purchases only.  In the event that the load-serving entity that failed to meet its share of the resource adequacy requirement has adequate supply and demand resources outside the spot market available to it at the time of the shortage, the Independent Transmission Provider would continue to provide transmission to support delivery of these resources.  This proposal gives deference to the ownership and contractual right to use self-generation, bilateral contracts, and demand response resources, and it encourages the development of such resources during the planning horizon period by those entities that failed to plan adequately at the beginning.  It also discourages contracting with unreliable resources to meet the resource adequacy requirement because each load-serving entity must actually rely on its resources to meet its resource needs.

230We will not overturn this practice by requiring curtailment of load immediately to restore the minimum operating reserve level.  Some regions have a regional policy of taking action to reduce voltage or shed load only when operating reserves fall to some fraction, such as three-fourths or three-fifths, of the minimum operating reserve requirements of the reliability organizations.

231Regional practice will determine when load must be curtailed to maintain reliable operation.  Operators may continue to follow their existing reliability practices: those that do not curtail service immediately when the operating reserve level goes below the minimum must impose the penalty price on resource-deficient load-serving entities.  However, it is not our intent to require an operator to violate a reliability rule by providing service with a penalty price instead of enforcing its reliability rule through load curtailment.  We believe that a high penalty price may result in the needed load reduction.  Whenever the operator must curtail load to maintain reliability, it should do so.  Our requirement goes to which load must be curtailed first when curtailment of load is necessary, not to when curtailment becomes necessary.

232An individual load-serving entity may run short of planned-for resources when its region is not experiencing a regionwide shortage, for example, because of a combination of high demand on its own system and unplanned outages of its own resources.  In this case it is not required to be curtailed because that load-serving entity may procure additional supplies from the short-term or long-term bilateral market or from the spot market.  Since the region is not short, others are likely to sell power, including perhaps a portion of their reserves on the basis that the reserves can be recalled if a regionwide shortage occurs.

233In this section, the term "state regulatory authority" includes the retail rate regulating authority for load-serving entities not regulated by a state utility commission.

234Any necessary curtailment action, whether a first curtailment or any subsequent curtailment action may have to satisfy applicable state or local rules for ensuring that essential retail services (such as police, hospitals, fire stations) are maintained.