F. Day-Ahead and Real-Time Market Services

1. This section sets forth the bidding, scheduling, price determination, and settlement provisions necessary to implement LMP in the day-ahead and real-time markets for energy, regulation and both operating reserves. In this section, we lay out the basic elements that would be used for congestion management and operation of the spot markets.¹³8

1. Design of the Day-Ahead Markets

2. We propose that the Independent Transmission Provider operate day-ahead and real-time markets for energy and certain ancillary services in conjunction with its scheduling of transmission service day ahead and in real time. These markets would allocate transmission and generation capacity among competing uses in different markets through LMP pricing. For example, the markets would determine how much transmission capacity would be allocated for transmission service to market participants completing bilateral energy transactions, for use by the Independent Transmission Provider in completing energy sales and purchases through its bid-based energy markets, and for providing ancillary services. The markets should be operated jointly to ensure that transmission and generation capacity is allocated where it is most valuable, and to ensure that the prices for the products and services are internally consistent.

a. Scheduling Transmission Service Day Ahead

(1) General Features

3. Each day the Independent Transmission Provider would accept requests to schedule transmission service to support bilateral energy transactions or customer-owned generation for each hour of the following day. A customer desiring transmission service would be required to submit a scheduling request in a standardized form specified by the Independent Transmission Provider. For each requested transmission service, the scheduling request would indicate the receipt point and the delivery point of the bilateral energy transaction or customer-owned generation, the amount of power (MW) to be transmitted and the time period. To facilitate the ability of demand to respond to price signals, transmission customers will be given several ways of indicating their willingness to change their consumption based on congestion costs and marginal losses: (1) customers (whether or not they hold Congestion Revenue Rights) would be allowed to specify in their scheduling requests the maximum transmission usage charge (reflecting the costs of congestion and marginal losses) at which the customer desires service;¹³9 (2) customers would be allowed to specify the maximum congestion charge component of the transmission usage charge at which they desire transmission service, or above which they are unwilling to pay any congestion costs; or (3) customers (whether or not they hold Congestion Revenue Rights) could submit a bid that states a desire for transmission service to be scheduled regardless of the transmission usage charge. This option may be useful for a holder of a Congestion Revenue Right that desires to schedule transmission service that uses the receipt point-to-delivery point combination covered by that Congestion Revenue Right.

4. Another way that transmission customers will be able to respond to price signals is by submitting multi-hour block bids, requesting transmission service for a block of consecutive hours and indicating the maximum price for the entire multi-hour period. For example, a multi-hour block bid might specify that the customer desires 10 MW of transmission service from receipt point A to delivery point B in each hour from 1:00 pm to 6:00 pm as long as the price per MW for the entire 5-hour period does not exceed $10. Such a bid would be accepted if the sum of the hourly transmission usage prices for each of the 5 hours did not exceed $10. Otherwise, the entire bid would be rejected. This option allows a customer, for example an industrial customer in a state with retail access, to indicate that it is willing to reduce its transmission usage if the prices for a multi-hour period are above a specified level. This feature has not been put in practice in any of the bid-based markets operated by ISOs. We seek comments on its merit and any implementation difficulties.

5. The Independent Transmission Provider would consider these transmission scheduling requests in conjunction with bids submitted in its day-ahead energy and ancillary service markets. Based on all of these, the Independent Transmission Provider would accept the set of energy bids and scheduling requests and develop a day-ahead schedule that maximizes the economic value for all market participants. The Independent Transmission Provider would also establish transmission usage prices for each hour of the next day that are the same as the implicit transmission usage price included in the set of locational energy prices (i.e., the difference in the price of energy at the receipt point and at the delivery point, which reflects both congestion and losses).

6. The Independent Transmission Provider would schedule all requests for transmission service since these users have agreed to pay any applicable congestion charges. The Independent Transmission Provider would also schedule all requested transactions where the transmission usage charge was below the amount the customer indicated it was willing to pay.

7. Customers with Congestion Revenue Rights would receive congestion revenues that help offset any congestion charges paid as part of the transmission usage charge. The amount of the congestion revenues received (and the associated protection against congestion charges) would depend on the specific Congestion Revenue Rights held. A customer holding receipt point-to-delivery point Congestion Revenue Rights for a certain amount of power between a delivery and receipt point that matches its day-ahead transmission schedule would receive congestion revenues that exactly offset its congestion charges, so that its net bill would reflect no congestion charges (although it would be charged for losses).

8. The above process would be used for scheduling transmission service on a daily basis. Some customers, particularly those with Congestion Revenue Rights, may desire to schedule the same exact service over a longer period to save on administrative costs. The Commission seeks comments on whether a customer should be allowed to provide a schedule for multiple days or have a standing scheduling request that would remain in effect until changed by the customer. Any schedule request, once scheduled by the Independent Transmission Provider would become financially binding on the customer at the close of each day's day-ahead market.

(2) Transmission Service Across Borders

9. Transmission service across the border of adjoining Independent Transmission Providers’ service areas – from a point of receipt in one service area to a point of delivery in another – requires coordination between the affected Independent Transmission Providers. When transmission congestion exists between a point of receipt and a point of delivery in different service areas, managing the congestion becomes more difficult because more than one Independent Transmission Provider is involved.

10. There are at least two methods for arranging for transmission service across borders – physical reservations (i.e., continuing firm point-to-point reservations of transfer capability), and scheduling of service consistent with internal transactions under Network Access Service (scheduling of transmission and financial bidding). We propose to treat transmission service across borders in the same way as internal transactions. Thus, like internal transactions, an importing or exporting customer could either schedule transmission service and agree to pay the transmission usage charge regardless of the level or submit a bid that limits its congestion exposure. Under the first method, the transmission customer would submit to each Independent Transmission Provider a request to be scheduled for transmission service to and from the border, regardless of the applicable transmission usage charges that it will be assessed. The customer would be scheduled unless congestion arose that could not be relieved through redispatch or some other means. Under the second method, financial bidding, the customer would submit a price bid to each Independent Transmission Provider indicating the maximum transmission usage charge that it is willing to pay for transmission service on each side of the border. The customer would be scheduled if its price bid on each side of the border was at or above the applicable transmission usage charge. Under either method, if the customer's transaction is scheduled, the customer would pay the applicable transmission usage charges to and from the border. We propose to make both options available to transmission customers, because each option may provide benefits to customers. We would prefer "one-stop shopping" with Independent Transmission Provider coordination; we seek comment on whether this can be done?

11. Recently we accepted a prescheduling option for service across borders that was proposed by the New York ISO.¹⁴0 A prescheduling option would give a customer certainty prior to the day-ahead market that it could transmit power across a border. Under the New York ISO's prescheduling option a customer may schedule such a transaction up to eighteen months in advance of the dispatch day. A customer that requests a prescheduled transaction agrees to pay the applicable market clearing transmission usage charge. Once submitted, the transaction would be financially binding unless the New York ISO permits the customer to withdraw the prescheduled transaction. We seek comment on whether a similar prescheduling option should be included in Standard Market Design.

b. Transmission Losses

12. When energy is transmitted from a point of receipt to a point of delivery, some of the energy is lost due to resistance on the wires. These transmission losses are a cost of transmission and commonly are recovered on an average cost basis from all transmission customers. As noted earlier, we are proposing that energy prices and the associated transmission usage charges be based on marginal costs, in order to promote economic efficiency. We seek comment on whether transmission losses should be recovered on the basis of the marginal cost of losses or if they should be recovered on the average cost of losses. There are advantages and disadvantages to each approach. Using marginal losses would promote a more efficient use of the transmission system. However, as discussed below, charging marginal losses will collect surplus revenues that must then be returned to transmission customers. On the other hand, the advantage of charging average losses is simplicity. If average losses are charged, the losses collected from customers would equal actual losses. There would be no need to create a mechanism to return surplus losses.

13. For customers purchasing transmission service to complete bilateral transactions, we see value in allowing transmission customers to pay for their assigned losses either in cash or in kind. To pay in cash, the customer would pay the market price for its assigned MWhs of losses, which would be included in the applicable transmission usage charge. Thus, the MWh of energy injected at the point of receipt would equal the MWh withdrawn at the point of delivery. The transmission provider would procure the energy used for losses from its energy market. To pay in kind, the customer would supply energy at the point of receipt in the amount of its assigned losses. Thus, the MWhs injected at the point of receipt would exceed the MWhs at the point of delivery by the amount of the assigned losses, and the customer would pay in cash only the congestion component of the transmission usage charge.¹⁴1 We note, however, that some commenters in our outreach process expressed concern that allowing customers to provide losses in kind may unduly complicate the scheduling process, especially for transactions that involve multiple Independent Transmission Providers. We seek comment on whether transmission customers should have the choice of paying for losses in cash or in kind, or alternatively, whether all transmission customers should be required to pay for losses in cash.

c. Day-Ahead Energy Market

(1) General Features

14. We propose that the Independent Transmission Provider be required to run a voluntary, bid-based, security-constrained day-ahead energy market. "Voluntary" means that market participants do not have to buy or sell in the day-ahead energy market. The day-ahead market we are proposing provides customers with additional supply choices. It is not intended to substitute for other longer-term arrangements that customers may use to purchase supplies such as bilateral transactions or use of a customer's own generation. Thus, market participants would be able to schedule bilateral transactions and/or their own generation rather than bid into the day-ahead energy market. "Bid-based" means that participants may submit offers to buy or sell quantities of energy into the market and may specify the prices at which they are willing to transact. This provides an organized and transparent system for the Independent Transmission Provider to determine the marginal cost of relieving transmission congestion. "Security-constrained" means that the Independent Transmission Provider, in the energy auction process, takes account of all system constraints, such as contingency limits, needed for reliable system operations and develops a schedule that does not violate such constraints. This is necessary to ensure that the day-ahead schedule is physically feasible. Otherwise, the Independent Transmission Provider might be required to make additional payments in real time to relieve congestion, which could provide an incentive for market participants to create congestion in the day-ahead market to receive these payments in the real-time market.¹⁴2 The market should allow full participation by both the supply side and the demand side of the market.

(2) Bidding and Scheduling Rules

15. Each day, the Independent Transmission Provider would accept bids to sell and buy energy for each hour of the following day. Participants desiring to sell or buy energy would submit a bid in a standardized form.

16. Each seller's bid would indicate the amount of power (MW) offered to be sold, the receipt point, and the time period. In addition, each seller would be allowed to submit multi-part bids that separately specify bid prices for start-up, no-load, and energy, as well as technical characteristics such as ramp rates, minimum run times and minimum down times. Allowing suppliers' bids to include these items yields more detailed information that can improve the ability of the grid operator to dispatch suppliers with the lowest total cost. For example, if the supplier were required to submit a one-part bid it would need to include start-up costs in its energy bid, resulting in a higher energy price bid. However, a supplier submitting a bid that separately specified the energy bid and the start-up costs would not have to make these estimates and the grid operator would use the bids to dispatch the supplier with the lowest total cost. Suppliers would also be allowed to submit bids that are self-schedules, that is, that would indicate an amount to be supplied at a location regardless of the applicable energy price. The supplier would receive the applicable market clearing price for its energy. This option may be useful for suppliers with very high start-up costs such as nuclear facilities. Intermittent resources would be able to participate in the day-ahead market on the same basis as other resources.

17. Similarly, each buyer's bid would indicate the desired amount of power (MW) to be bought, the delivery point, and the time period. In addition, each buyer would be allowed to specify bid prices that indicate the quantities it is willing to purchase at alternative prices. Buyers would also be allowed to submit multi-part bids that indicate the time and price constraints under which they are willing to purchase energy. These options would facilitate demand response programs because they allow the buyer to indicate the price at which it will voluntarily reduce its consumption. Buyers would also be allowed to schedule an amount to be purchased regardless of the applicable energy price.¹⁴3 Bids would not need to be tied to a physical generator or load resource. However, for reliability purposes, bids would need to indicate whether they were purely financial bids or whether they were tied to a physical resource. This would permit market participants to bring day-ahead and real-time prices closer together, increasing the stability of both markets. This option should reduce price differences between these two markets.

18. Buyers and sellers would be able to submit different price bids for different hours of the day, and bids could vary from day to day. However, if market participants can exercise market power, limits may be imposed on bidding to mitigate market power, as discussed below in the section addressing market power monitoring and mitigation.

19. We propose a scheduling option to address the special conditions facing energy-limited resources such as hydroelectric and environmentally constrained thermal resources. These resources are limited in the amount of energy or the number of hours that they can produce energy over a period of time. As a result, production in one hour may reduce the amount of energy that the resource can produce (and the associated revenue) in other hours. Energy-limited suppliers could submit bids in the day-ahead market that specify the amount of energy, or the number of hours, available for production over the next day. The supplier could then request the Independent Transmission Provider to schedule its energy in those hours of the next day when the energy price is highest. Such a scheduling feature would promote efficient scheduling because it would allow the energy-limited resource to be scheduled where its energy would have the greatest value, with maximum profit to the resource owner.¹⁴4 We recognize that the resource mix varies significantly from region to region and that some regions, such as the Northwest, have a greater amount of energy limited resources. We seek comment on whether other scheduling options or regional variations should be included for energy-limited resources in the tariff.

20. We recognize that intermittent resources such as wind power may also benefit from scheduling rules that recognize their inability to precisely control output. We recently approved a special mechanism for intermittent resources selling into the energy market run by the California ISO.¹⁴5 Under that mechanism, the intermittent resource and the California ISO work together to develop a schedule and procedures for accurately forecasting the output of the resources. However, California ISO currently runs only a real-time market for energy and not both a day-ahead market and real-time market as proposed here. Also, the amount of power produced by intermittent resources within California is much larger than in many parts of the country. We propose to include the California ISO's scheduling option for intermittent resources as part of Standard Market Design. However, we seek comment on whether there is a better way to schedule intermittent resources.

21. Finally, in drafting the bidding and scheduling rules we have included several ways for demand to respond to prices. We recognize that several ISOs currently have demand response programs that operate differently. Under these demand response programs, the ISO pays end-users to reduce their demand if market clearing prices reach a certain level. We believe the direct approach of letting demand bid in the market will be less costly than a program where an end-user receives payments greater than the market clearing price to reduce its demand. We have not proposed to include these types of programs in the pro forma tariff although they could be included if the Independent Transmission Provider, in consultation with the state advisory committee and stakeholders, determined that they were necessary. Since the participation of demand in the market is critical for an effective wholesale market, we seek comment on whether the measures proposed are sufficient or if other measures should be included.

(3) Price Determination and Settlement

22. Based on the accepted bids included in the day-ahead schedule, the Independent Transmission Provider would establish day-ahead locational energy prices for each hour. The hourly energy price at each location would reflect the marginal cost (as reflected in bids) of producing and delivering energy to that location in that hour. Energy prices would be consistent with the transmission usage charges, so the difference in energy prices between two locations in an hour would reflect the cost of transmitting energy from one location to the other.

23. The Independent Transmission Provider would establish a single market-clearing energy price for each hour for each node on its transmission system. We believe it is important that energy prices be calculated for each node to avoid socialization of congestion costs and to reduce the possibility of manipulating the congestion management system.¹⁴6 The Independent Transmission Provider could also establish nodal prices for time intervals shorter than an hour. Nodal pricing would be used for both buyers and sellers in the day-ahead market.

24. Upon request of market participants, the Independent Transmission Provider would establish trading hubs. A trading hub is a virtual location where financial transactions may be arranged, whose hub price is the weighted average of energy prices at a specified set of nodes on the transmission system. A trading hub facilitates financial trading and aggregation of supplies from multiple sources. Creation of trading hubs should not lead to socialization of congestion costs, because the price for service at the trading hub is the weighted average of prices at the various nodes that are included in the trading hub. Energy may not be injected or withdrawn from the grid at a trading hub, since a hub does not exist at a physical location. But a hub may be named as an intermediate point between physical points of injection and withdrawal where financial energy trades may occur.¹⁴7 Also, at the request of market participants, the Independent Transmission Provider would establish zones that are the weighted average of energy prices at selected delivery nodes on the transmission system. This option would permit a load-serving entity to aggregate prices for deliveries to its various delivery nodes.

25. Each buyer and seller would transact at the applicable clearing price for the hour and time period. A seller that submits separate bids for start-up and no-load costs and is dispatched by the Independent Transmission Provider for any period during the day, will be assured that it will recover the start-up and no-load costs that it bid. If a seller’s total bid costs (including start-up and no-load costs, as well as energy running costs) over the entire day are not fully covered by its revenues from selling at the hourly clearing prices, it would receive an additional payment (i.e., an "uplift" payment) for the net revenue shortfall for the day. Hourly energy prices would be based only on energy bids; start-up cost bids and no-load bids would not be used in calculating hourly energy prices. Thus, a generator may have legitimate start-up costs that are not fully covered by selling at the hourly energy price over the day; paying uplift may be necessary to ensure that generators selected in the auction will receive revenues that fully cover their bid-costs.¹⁴8 Since the additional payments are a cost of providing supplies of energy and ancillary services in the Independent Transmission Provider's day-ahead market, we propose to recover the additional payments from entities that purchase energy and/or ancillary services in the Independent Transmission's Provider's day-ahead market. Any entity that does not buy any energy from the Independent Transmission Provider's day-ahead market on a given day, and that self-supplies all of its ancillary service obligations on that day, would not be assigned a share of the additional payment for that day.

26. The results of the day-ahead market would be financially binding on buyers and sellers. That is, sellers would be paid the applicable locational day-ahead price for energy scheduled to be sold in the day-ahead market, and buyers would pay the applicable locational day-ahead price for energy scheduled to be bought in the day-ahead market. In addition, to the extent sellers and buyers fail to actually produce or take energy according to their respective schedules in real time, such imbalances would be settled at the applicable real-time energy price. Thus, a seller would pay the real-time LMP nodal price for any scheduled energy that it fails to deliver in real time to its bid delivery point. Similarly, a buyer would be paid the applicable LMP nodal real-time price for any scheduled energy that it does not take at its bid receipt point in real time.

27. The Independent Transmission Provider would post prices and other market information and settle the markets promptly to provide market participants with reliable information regarding their market transactions.

28. In certain instances, a generator may alleviate a voltage or stability constraint by producing real power and/or reactive power at its location. By alleviating the constraint, the transfer capability of the grid may be increased, thereby allowing a greater amount of lower-cost energy to be transmitted to an area with higher energy prices. For example, the transmission capability to import power into a load pocket may initially be limited to 1000 MW due to a voltage or stability constraint, even though the thermal limit is 1500 MW. However, production of an additional 100 MW of real power and/or an additional amount of reactive power within the load pocket could increase import capability into the load pocket by 50 MW, to 1050 MW. We seek comment on whether generators who provide such real or reactive power should receive additional compensation (in addition to the locational market price for energy and the applicable compensation for reactive power) for the additional transfer capability that they create, to provide incentives to produce energy that increases transfer capability. For example, should such generators be given the Congestion Revenue Rights with the additional transfer capability that they create? In certain circumstances, a generator must reduce its production of real power in order to increase its production of reactive power. In these circumstances, should the generator be compensated for the opportunity cost of its reduced profits from selling real power? Should the generator be paid the higher of its opportunity costs or the market congestion value of the additional transfer capability created? How should locational market power concerns be addressed in these circumstances?

d. Day-Ahead Ancillary Service Markets

(1) General Features

29. Order No. 888 identifies six ancillary services, two of which may only be provided by the Independent Transmission Provider and four of which must be offered by, but need not be obtained from the Independent Transmission Provider. The four ancillary services that must be offered by, but need not be obtained from the Independent Transmission Provider, include:¹⁴9

(1) Regulation and frequency response

(2) Energy imbalance

(3) Operating reserve - spinning

(4) Operating reserve - supplemental

Pursuant to the requirements of Order No. 888, transmission customers are assigned the responsibility for these ancillary services. Customers may meet their responsibility through self-supply, by procuring these ancillary services from a third party, or by acquiring them from the Independent Transmission Provider.

30. As discussed earlier, imbalance energy would be provided through the day-ahead and real-time energy markets. For the remaining three ancillary services (regulation and both operating reserves), we propose to require that the Independent Transmission Providers operate bid-based markets open to all potential suppliers so that Independent Transmission Providers can procure these ancillary services from the lowest cost suppliers. Different regional reliability authorities may establish different requirements for operating reserve - supplemental. For example, the four jurisdictional operating ISOs procure resources for the ancillary service operating reserve - supplemental (which are usually generation resources that are not synchronized with the grid or demand-side resources that can curtail use), with varying response times. Each ISO procures a portion of their necessary operating reserve - supplemental requirement with reserves that can respond within 10 minutes of a dispatch request, as well as slower-responding reserves at 30 minutes (New York ISO and ISO-New England) and 60 minutes (California). Since different regional reliability authorities have established different response times for operating reserve - supplemental, we do not propose a standard set of markets for operating reserve - supplemental. However, we propose to require that each Independent Transmission Provider operate separate markets for each type of operating reserve - supplemental that it procures.

31. Location-specific reserve targets may be required in some areas due to persistent and significant congestion. The Independent Transmission Provider would identify and establish these targets consistent with any reliability rules.

(2) Bidding and Scheduling Rules

32. Each day, the Independent Transmission Provider would determine the total amount of each of the ancillary services that will be required for each hour of the following day. Customers that wish to meet their ancillary service requirement through self-supply or procurement through a third party would be required to provide the Independent Transmission Provider with the necessary information about the generation capacity or demand-side resource that would be providing the ancillary services (as is currently required under the existing pro forma tariff).

33. To procure the remaining amount of ancillary services, the Independent Transmission Provider would accept bids for regulation and the types of operating reserves for each hour of the following day. A participant desiring to sell regulation or operating reserves would submit a bid in a standardized form specified by the Independent Transmission Provider. Bids could be offered to provide ancillary services from generation capacity or any demand-side resource that meets the technical requirements of the ancillary service. Participants could offer the same capacity in more than one ancillary service market, as well as in the energy market.

34. Each bid would indicate the type of ancillary service, the amount of generating capacity (MW) offered for sale, the receipt point of the resource and the time period. The bid would also include an availability bid indicating the minimum price per MW (which could be either a positive amount or zero) required to provide the ancillary service. The availability bid would allow the bidder to ensure that it would not be selected to provide the ancillary service unless the ancillary service price is high enough to cover out-of-pocket costs, such as the costs of keeping a crew at its facility for the following day. The bid would also include the various components that would be submitted to provide energy into the energy market. These components include an energy bid, indicating the minimum price per MWh required to produce energy. Other bid components would include price-bids for start-up and no-load, as well as technical constraints, such as minimum load, ramp rates, minimum run time and minimum down time. By providing one ancillary service, a bidder may forgo profits from sales in other markets, and these forgone profits are an opportunity cost of providing ancillary services. As explained in the following section, the Independent Transmission Provider will consider the opportunity cost associated with forgone sales in other markets operated by the Independent Transmission Provider. Opportunity costs from forgone sales in markets not operated by the Independent Transmission Provider could be included in the bidder's availability bid.

35. The Independent Transmission Provider would consider all bids to sell ancillary services, in conjunction with bids submitted in its day-ahead markets for energy and transmission service. As noted earlier, based on all submitted bids, the Independent Transmission Provider would maximize the economic value (as reflected in the bids) of the accepted bids, i.e., accept the bids with the overall lowest cost. Thus, for generation capacity and demand-side resource that bid into more than one market, the Independent Transmission Provider would schedule the generation capacity or demand-side resource into the market where it is most efficient (unless it is not efficient to schedule the generation capacity or demand-side resource in any market).¹⁵0 This should yield the overall lowest cost for procuring energy, regulation and operating reserves.

(3) Price Determination and Settlement

36. Based on the accepted bids included in the day-ahead schedule, the Independent Transmission Provider would establish day-ahead prices for each of the ancillary services procured in the bid-based markets for each hour. In regions with separate locational ancillary service requirements, the Independent Transmission Provider would establish separate hourly locational ancillary services prices.

37. To promote an efficient market, the price for regulation and operating reserves services would equal the marginal cost of each service, which would equal the highest accepted total bid cost expressed in dollars per MW. The total bid cost of each generator is the sum of: (1) the generator's availability bid per MW and (2) the opportunity cost of forgoing sales in other markets operated by the Independent Transmission Provider, expressed on a per-MW basis.¹⁵1

38. A generator or demand-side resource could be eligible to bid into more than one market operated by the Independent Transmission Provider. The opportunity costs paid to the supplier would be the forgone profit from the most profitable other market. For example, a generator that is capable of providing ancillary services could also sell into the transmission provider's day-ahead energy market, although it would incur additional variable energy costs to do so. Thus, the forgone profit from selling into the energy market (as reflected in the generator's bid) would be the difference between the energy price and the generator's energy bid. The opportunity cost of selling ancillary services would include this forgone energy profit.

39. The hourly price for one of these ancillary services in a given location would thus equal the sum of the opportunity cost and the availability bid in dollars per MW of the most expensive unit accepted to provide that type of ancillary service in that hour to that location. As noted above, a generator providing any ancillary service is also technically capable of providing a slower response ancillary service. For example, a generator providing operating reserve - spinning could also provide operating reserve - supplemental. Thus the opportunity cost of providing operating reserves - spinning would be at least as high as the price of operating reserve - supplemental. As a result, the marginal cost (and thus, the price) of operating reserve - spinning would not be less than the price of operating reserve - supplemental in the same hour.

40. Although suppliers bid to provide these ancillary services in the day-ahead market, customers pay for them based on real-time load. Transmission customers would be assessed a pro rata share of the total ancillary service requirements for each of these three ancillary services in each hour, based on their real-time, load-ratio share. Ancillary service requirements generally depend more on real-time transactions than on day-ahead schedules. Assessing ancillary service requirements based on day-ahead schedules would provide an incentive for customers to understate their day-ahead schedules.

41. In Order No. 888, exports are not charged for these ancillary services. We ask for comments on whether they should be charged here.

42. Customers that want to self-provide or procure their own ancillary services would be required to notify the Independent Transmission Provider in the day-ahead scheduling process and identify the resources that would be used to provide these services. Customers would be given credit for the amount of ancillary services that they self-provide or procure from third parties. Customers that self-provide or procure from third parties more capacity than their requirements would be paid the applicable hourly ancillary service price for the excess if needed by the market.¹⁵2

2. Scheduling After the Close of the Day-Ahead Market

a. Replacement Reserves

43. The Independent Transmission Provider will use the day-ahead market to develop prices and a schedule for suppliers. The prices and schedules will be based on the bids submitted by buyers and sellers. However, the day-ahead schedule may be less than the forecasted load in real time and, if so, the Independent Transmission Provider would commit additional units to ensure that load can be met reliably in real time.

44. After the Independent Transmission Provider has established a day-ahead schedule and associated prices for energy, transmission service and ancillary services, it would make its own forecast of load within its market area for each hour of the following day. To the extent that its forecasted load exceeds the amount of energy scheduled to be delivered to load in the day-ahead schedule, the Independent Transmission Provider may need to procure additional reserves (called "replacement" reserves) from generators to make up the difference, but only to the extent necessary to ensure that sufficient generation will be available to meet load.

45. To procure replacement reserves, the Independent Transmission Provider would accept bids from generators submitted for the day-ahead market. The Independent Transmission Provider would select generators to provide replacement reserves so as to minimize the costs of availability, start-up costs and no-load costs regardless of energy costs. This approach to procuring replacement reserves would provide an incentive for load to accurately bid its load in the day-ahead market since energy prices may be higher in the real-time market.

46. As discussed further in the next section, generators selected to provide replacement reserves would be included in the real-time energy bid stack along with other generators that submit bids into the real-time market to provide energy. Generators selected to provide replacement reserves would be paid the applicable real-time energy price for energy that they produce. If a generator's revenues received from selling real-time energy are less than its bids for availability, start-up, no-load and energy, the Independent Transmission Provider would pay the generator an additional payment (i.e., an "uplift" payment) for the shortfall. The revenue shortfall would be recovered pro rata from all loads that buy energy in real time that have not been scheduled in the day-ahead market. Thus, the costs would be allocated to the customers that benefitted from the replacement reserves – customers that took power in real time. This provides an incentive for load to accurately predict its requirements in the day-ahead market.

47. We propose to add a new Section G.2 to the pro forma tariff that would implement the foregoing procedures for scheduling and paying for reserves after the close of the day-ahead market.

b. Changes to Transmission Schedules

48. A market participant that has not scheduled transmission service in the day-ahead market but desires transmission service in real time must inform the Independent Transmission Provider within specific time deadlines before real time. Market participants may change their day-ahead transmission service schedule by informing the Independent Transmission Provider consistent with the time deadlines.

49. Participants that have informed the Independent Transmission Provider of their desired changes within the Independent Transmission Provider's lead times, and adhere to the requested changes in real time, would settle the changes in transmission service at the applicable real-time transmission usage prices, described more fully below. Participants with new or increased transmission service would be charged the applicable real-time transmission usage price between the applicable receipt and delivery points for the new or increased transmission service in the applicable hour. Conversely, participants that reduce transmission service in real time (compared to the day-ahead schedule) would be paid the applicable hourly real-time transmission usage price for the applicable receipt and delivery points, to compensate them for the additional transmission capacity they have made available in real time.

3. Design of the Real-Time Markets

50. Under Standard Market Design, the Independent Transmission Provider would be required to operate bid-based, security-constrained real-time markets for transmission service, energy, and certain ancillary services (i.e., regulation, operating reserve - spinning and operating reserve - supplemental).

a. Real-time Energy Markets

(1) General Features

51. Under the Standard Market Design, the Independent Transmission Provider would accept bids to buy and sell energy in each hour in the real-time energy market. The bids would be in the standardized form specified by the Independent Transmission Provider. Real time energy markets would be used to provide the imbalance energy service of Order No. 888 pro forma tariff and self provision would be allowed. However, loads could voluntarily enter into bilateral contracts with suppliers in advance to lock in a fixed price for energy.

(2) Bidding and Scheduling Rules

52. In general, bids would indicate an offer to depart in real time from the bidder's day-ahead schedule to purchase or sell energy (including a day-ahead schedule to purchase or sell 0 MWhs of energy). Real-time bids would be accepted from any market participant, including generators, load-serving entities, eligible retail buyers, marketers and other agents. Bids would indicate the increase or decrease (in MWhs) from the day-ahead schedule in the amount of energy to be sold or purchased in real time, and the location and the hour of the changed purchase or sale. Each participant bidding into the real-time energy market would be allowed to include multi-part price bids similar to those allowed in the day-ahead energy market (this is a departure from the Working Paper).

53. The transactions in real time vary from those reflected in the day-ahead schedule due to a variety of factors, including changes in weather conditions and unexpected equipment outages. The Independent Transmission Provider may be informed in advance of some of the scheduling departures under the procedures described above; other departures may occur without warning.

54. As occurs today, an Independent Transmission Provider will have to adjust energy production and/or load at various locations in order to balance generation with load and manage congestion. Under Standard Market Design, the Independent Transmission Provider would make these adjustments by calling upon participants that have submitted bids into the real-time energy market, as well as participants that have been selected to provide spinning, supplemental, and replacement reserves. The Independent Transmission Provider would issue dispatch instructions to bidders so as to balance generation and load, and efficiently manage congestion of demand and supply.

(3) Price Determination and Settlement

55. The Independent Transmission Provider would determine energy prices in the real-time energy market for each node for each 5-minute period or other subhourly period where a 5-minute determination is not technically achievable. Each price would reflect the marginal cost (as reflected in the real-time supply and demand bids) of producing energy and delivering it to the node in that period. The Independent Transmission Provider would post prices and other market information and settle the markets promptly to give market participants reliable information regarding their market transactions.

56. To promote efficient participant decisions regarding real-time transactions, we propose that all departures in real time from the day-ahead schedule be settled through the real-time market at the applicable price (as is done today in many markets). Nodal pricing would be used for both buyers and sellers in the real-time market.

57. There are several aspects of the design of the real-time energy market where we seek additional comments.

Ex Post versus Ex Ante Prices

58. This Section discusses how to determine real-time energy prices. The options are to set the prices using near real-time estimates (ex ante), or base the price on the price of the actual marginal resource clearing the market in real time (ex post). Immediately in advance of each upcoming 5-minute period, the Independent Transmission Provider would announce the real-time energy prices that it estimates will clear the market and match generation with load during that upcoming period (based on the real-time bids submitted by market participants). The Independent Transmission Provider could settle all departures in real-time from the day-ahead schedule using these prices announced in advance. Such an ex ante pricing policy would provide price certainty and thereby encourage buyers and sellers that have not submitted bids to adjust their transactions in response to the announced price.

59. Alternatively, an ex post pricing policy could be used as an incentive for suppliers to follow dispatch instructions. Some bidders may not respond to the announced prices in the way suggested in their bids. For example, a supplier stating in its bid that it would increase its output by 50 MWh for each price increase of $5/MWh may in fact increase its output by less than 50 MWh in response to such a price increase. By settling at the ex ante price, the generator would be paid the higher price despite the fact that it did not increase its output as it had promised in its bid. An ex post pricing rule might help to encourage bidders to respond in real time in a way consistent with their bids. Specifically, the price used to settle real-time deviations from day-ahead schedules could be the price-bid associated with the energy observed ex post to be produced by the marginal supplier in the 5-minute period (but not higher than the advisory price announced ex ante). Such an ex post price rule would encourage suppliers to supply the full amount of energy promised in their bids.

60. We propose to adopt the ex post rule because it creates incentives for bidders to act consistent with their bids. We seek comment on the choice between ex post and ex ante pricing.

Other Charges for Uninstructed Deviations from Schedules

61. We seek comment on whether market participants should face additional charges for “uninstructed” deviations in real time from their schedules, i.e., for producing or taking a different amount of energy in real time than was scheduled without permission or direction from the Independent Transmission Provider. Uninstructed deviations from schedules may increase the amount of regulation service or other ancillary services that the Independent Transmission Provider must procure, in order to reliably balance load and generation. If so, it would be appropriate to recover the costs of these services through a charge. We seek comment on whether the increased costs of regulation service or ancillary services should be allocated to the entities (buyers and sellers) that had uninstructed deviations from their schedules since the costs were incurred to serve these entities. Uninstructed deviations may also require the use of scarce ramping capability within the Independent Transmission Provider’s market area. If ramping capability were used, it may be appropriate to charge for that use. We seek comment on whether and how to establish market prices for ramping capability. Finally, in extreme cases large uninstructed deviations can threaten reliability of service. To discourage this type of conduct a penalty provision may be appropriate.¹⁵3 We seek comment on whether the SMD Tariff should include penalty provisions for uninstructed deviations that threaten system reliability and how such penalty provisions should be structured.

What Bids Should be Eligible to Set the Energy Price

62. Strictly speaking, the marginal cost of meeting a small increment of load would be based on the bids of suppliers whose output can be increased, or buyers whose load can be decreased, from their scheduled level in the hour by as little as 1 MW. Thus, for example, the marginal cost of supplying load in an hour would not be based on the bid of any generator that is operating in the hour solely because of a minimum run constraint, because changes in load would not change the output of the generator.¹⁵4

63. However, we are concerned that by excluding generators whose output is adjustable in increments greater than 1 MW, on an hourly basis, from setting the energy price may not promote efficient results.¹⁵5 These potential inefficient results are more likely to occur in the real-time market than in the day-ahead market.¹⁵6 Therefore, we propose to allow generators whose output is adjustable on an hourly basis, but only in increments greater that 1 MW, to be eligible to set the energy price in the Real-Time Market if two conditions are met. First, the generator’s output must be needed to meet load in the hour. That is, in the absence of the generator’s output, either load could not be fully met or a more expensive generator would be needed to fully meet load. Second, the reason that the generator is operating must not be a minimum run time constraint. We also propose that any cheaper generators that are directed to reduce their output would be paid their opportunity costs (i.e., the difference between the applicable energy price and their energy bids) for the amount of the output reduction. With this payment, the generator is compensated for the legitimate opportunity cost of following the Independent Transmission Provider's instructions.¹⁵7

64. We seek comment on whether such lumpy generators should also be eligible to set the energy price in the day-ahead market. Although allowing these lumpy generators to set the energy price may have more direct benefit in the real-time market, we are concerned about potential negative ramifications from establishing different pricing rules for the day-ahead and real-time markets.

b. Real-Time Ancillary Services Markets

65. As discussed earlier, Order No. 888 requires transmission providers to offer to provide to transmission customers energy imbalance service, regulation and frequency response, operating reserve - spinning and operating reserve - supplemental. Under Standard Market Design, energy imbalance service would be provided through the transmission provider's real-time energy market. The Independent Transmission Provider would procure its expected requirements for the remaining three ancillary services through day-ahead ancillary service markets discussed above.

66. We propose that the Independent Transmission Provider operate a real-time ancillary services market to accommodate adjustments in the supply of ancillary services from the day-ahead schedule. In real time, there may be entities that can provide ancillary services more efficiently than those that were scheduled in the day-ahead market. The real-time market would permit such efficient substitutions. Higher-cost suppliers scheduled in the day-ahead market would buy back their offer to provide ancillary services at the applicable real-time price, and other, lower-cost entities would be paid the real-time price to take over the supply of ancillary services. In addition, the Independent Transmission Provider may need an amount of ancillary services that differs from the amounts procured in the day-ahead market, for several reasons. For example, the requirements expected in the day-ahead market may differ from actual, real-time requirements, or participants scheduled to provide ancillary services may experience outages in real time. Under Standard Market Design, the Independent Transmission Provider would procure any additional ancillary services needed in real time through the real-time ancillary service markets that it operates.

67. In the real-time market, the Independent Transmission Provider would accept bids for each ancillary service. As in the day-ahead market, a participant could offer the same capacity in more than one ancillary service market. The real-time bids would contain the same types of information as those submitted into the day-ahead ancillary service markets, with one exception – we propose to exclude availability bids for spinning reserves and supplemental reserves in real time. The types of costs reflected in the availability bid to ensure that the supplier will be available to provide these reserves are incurred in the day-ahead time frame, not in real time.¹⁵8 There do not appear to be any incremental costs associated with providing these ancillary services in real time, other than the opportunity costs of forgoing sales in another market operated by the Independent Transmission Provider, and these opportunity costs would be reflected in the way that ancillary service prices are determined.¹⁵9

68. The Independent Transmission Provider would consider all bids to sell ancillary services in real time and select those bids that minimize the overall cost of procuring additional ancillary services required in real time.

69. Based on the bids accepted in the real-time market, the Independent Transmission Provider would establish real-time ancillary service prices for each hour that reflect the marginal cost of each service. All participants supplying a given type of ancillary service in a given hour in real time (and to a given location, if there are locational ancillary service requirements) would be paid the applicable market clearing price.

70. Transmission customers that have not self-supplied or procured through third parties their full assigned ancillary service requirement would be assessed a pro rata share of the costs incurred by the Independent Transmission Provider for procuring ancillary services in real time.

4. Market Rules for Shortages or Emergencies

71. We believe the market rules discussed above in combination with the market mitigation measures and the resource adequacy requirement will result in an efficient system for matching supply and demand under most operating conditions. However, we recognize that when emergency situations do occur, changes may be needed to the market rules to comply with reliability requirements. In the event of a capacity shortage or emergency, local reliability rules and procedures (which typically combine NERC, regional reliability council and system operator guidelines) prescribe a series of actions that the system operator takes to maintain reliability. For example, procurement of reserves is reduced, typically in order of reserve quality (that is, supplemental reserve quantities are reduced before spinning reserve quantities). The system may be re-dispatched to adjust the location and responsiveness of remaining reserves. System operators have also traditionally called on emergency supplies from neighboring systems (in the past, these emergency purchases have taken place at pre-defined prices; increasingly, they are being made at market prices). Finally, steps are taken for voluntary and involuntary load-shedding. States typically approve in advance the retail curtailment plans of utilities.

72. In the markets proposed in the SMD Tariff, we envision that with more extensive demand-side participation, the potential for these types of capacity shortage or emergency situations will substantially diminish. However, system emergencies may occur. The existing pro forma tariff gives transmission providers the authority to curtail transmission service and take any other preventive action necessary to preserve system reliability. The SMD Tariff would continue to grant the Independent Transmission Provider this same authority. However, the actions taken to ensure system reliability can affect prices in the energy and ancillary service markets. Market participants should be aware of how these actions will affect pricing in the markets operated by the Independent Transmission Provider. To that end, the SMD Tariff requires Independent Transmission Providers to file proposals with the Commission regarding the implications for market pricing of each reliability procedure. These proposals would need to be consistent with the resource adequacy mechanisms discussed below, but could vary to reflect regional differences in reliability requirements. We seek comments on what, if any, more specific requirements should be included in the Final Rule.

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1³⁸Part I of the SMD Tariff includes a definition of the terms related to market services. In addition, as we use the term "supplier" or "seller" in this Section, the definition we are using includes both generators and demand-side resources that satisfy the Independent Transmission Provider's applicable requirements.

1³⁹For example, when transmission usage prices become sufficiently high, customers holding receipt point-to-delivery point Congestion Revenue Rights may prefer not to schedule transmission service between their designated receipt and delivery points. Instead, the customers may prefer to receive the applicable congestion revenues. Customers could communicate these preferences through price-bids.

1⁴⁰New York Independent System Operator, Inc., 99 FERC ¶ 61,292 (2002).

1⁴¹The amount of energy needed for losses would not be known until the close of the market. For transactions in the day-ahead market, the Transmission Provider would inform each customer that wishes to supply losses in kind (after the close of the day-ahead market) of the amount of its assigned losses (in MWh), and that amount would be included in the customer's day-ahead schedule. For transactions in the real-time market, the Transmission Provider could provide an estimate in advance of the amount of each customer's assigned losses. However, since actual marginal losses would not be known until after the fact, the customer would be charged or credited at the applicable LMP for any under- or over-provision of losses.

1⁴²See the discussion of this issue in Appendix E.

1⁴³Since energy prices have the potential to rise to very high levels, it may be necessary to require buyers that request energy without submitting a price bid to demonstrate to the Independent Transmission Provider in advance that they are financially capable of paying very high prices for such quantities. Alternatively, the Independent Transmission Provider could limit the amounts based on a buyer's creditworthiness.

1⁴⁴While this scheduling feature is intended mainly for energy-limited resources, it would be available to all generators and would not be restricted to energy-limited resources, unless such restrictions are necessary to mitigate market power.

1⁴⁵See California Independent Operator Corp., 98 FERC ¶ 61,327, order accepting compliance filing, 99 FERC ¶ 61,309 (2002).

1⁴⁶ See discussion in Appendix E of manipulation strategies involving congestion management.

1⁴⁷ A good example of a trading hub is PJM's Western hub, where there are active spot energy and transmission rights markets, as well as bilateral markets.

1⁴⁸ For example, suppose that the Independent Transmission Provider needs to supply an additional 100 MW load in each of 20 hours over the next day. Two generators, A and B, are available. Generator A has energy costs of $35/MWh, but must incur $15,000 in start-up costs before beginning production. Generator B has energy costs of $40/MWh, and has no start-up costs. Generator A’s total cost of meeting the load would be $85,000 (i.e., total energy costs of $70,000 [$35/MWh x 100 MWh x 20 hrs] PLUS start-up costs of $15,000). Generator B’s total cost would be $80,000, comprised exclusively of energy costs (i.e., $40/MWh x 100 MWh x 20 hrs). Generator B should be chosen because its total costs ($80,000) would be less than Generator A’s total costs ($85,000). Suppose that the hourly clearing price in each hour is $42/MWh. By selling 100 MWh in each of 20 hours, Generator B would receive total revenues of $64,000 (i.e., $32/MWh x 100 MWh x 20 hrs), which is $6,000 less than its total bid-in costs of $70,000. Generator A would thus need to receive a $6,000 uplift payment in addition to its energy revenues. Paying $6,000 in uplift is still cheaper for customers than the alternative of dispatching Generator B.

1⁴⁹These four ancillary services are in addition to two other ancillary services, (1) Scheduling, System Control and Dispatch Services and (2) Reactive Supply and Voltage Control. We seek comment on treating Scheduling, System Control and Dispatch Services as a basic cost of providing transmission service instead of as an ancillary service.

1⁵⁰Because of the way that prices would be established in each market, the market into which each bidder of generation capacity or demand-side resource is scheduled would also be the market that is the most profitable for the bidder. That is because, as discussed in the following section, the prices in each market would reflect marginal opportunity costs of the bidders in that market. Thus, the price in each market would be high enough to allow each accepted bidder in that market to receive at least as much profit as it could have received in any other market operated by the Independent Transmission Provider that it is technically capable of participating in.

1