SPP Integrated Marketplace –Frequently Asked Questions
Last Updated: 06/01/2011 1-4
SPP Integrated Marketplace – Frequently Asked Questions
TABLE OF CONTENTS
1. Acronyms 1-4
2. Basic 2-5
2.1 What are the Integrated Marketplace Benefits? 2-5
2.2 What are the major market components that SPP is adding with the Integrated Marketplace? 2-5
2.2.1 Day-Ahead Market 2-6
2.2.2 Reliability Assessment 2-6
2.2.3 Real-Time Balancing Market 2-7
2.2.4 Transmission Congestion Rights Market 2-7
2.2.5 Multi-Settlement 2-7
2.2.6 Consolidated Balancing Authority 2-7
2.3 What is the difference between the Day-Ahead Market and the Ancillary Services Market? 2-8
2.4 What is the difference between an LMP and an LIP? 2-8
2.5 Is participation in the DA Market required? If not, what is required to be submitted to SPP? 2-8
2.6 What controls are in place to ensure reliability? 2-9
2.6.1 Reliability Unit Commitment 2-9
2.6.2 Operating Reserves Procurement 2-9
2.6.3 Unit Commitment and Economic Dispatch 2-9
2.7 Will SPP have the right to call on any unit within its footprint? 2-9
2.8 What information is required to be submitted by the Market Participants? 2-10
2.9 Why doesn’t RUC consider incremental energy costs when making the decision to commit a unit? 2-10
2.10 What happens if a Market Participant’s Resource Offer clears in the DA Market but the Market Participant does not provide that energy on the Operating Day? 2-10
2.11 What has been the design philosophy used to define the SPP Integrated Marketplace? 2-11
2.12 How will the SPP Integrated Marketplace footprint be different from the current footprint? 2-11
2.13 How can an entity outside SPP participate in the SPP Integrated Marketplace? 2-11
2.14 What is an Asset Owner and what is its purpose? 2-12
2.15 What is the cost/benefit to utilizing marginal vs. average losses? 2-13
3. Resource Statuses, Offers and Bids 3-13
3.1 What are Demand Bids and Resource Offers in the DA Market? 3-13
3.2 What are Virtual Energy Bids and Virtual Energy Offers in the DA Market? 3-13
3.3 What happens if there are more Demand Bids than Resource Offers for the DA Market? 3-14
3.4 What will the system do if an explicit offer is not submitted for a given hour? 3-14
3.5 When can bids and offers be submitted? 3-14
3.6 Does “Fixed” Dispatch Status for an Operating Reserve product mean a specifically fixed MW amount to be carried or a minimum amount? 3-15
3.7 Why did SPP choose to require separate ramp rates up and down as opposed to a bi-directional ramp rate? 3-15
3.8 Why did SPP choose to allow separate ramp rate for use in Regulation and Spinning Reserve clearing? 3-15
4. Outages 4-16
4.1 What happens when there are rapid Load changes (e.g. storm, feeder outages, etc...) that cause the actual Load to deviate significantly from the RTO forecasted Load? 4-16
4.2 How are outage schedules factored into unit commitment plans? How are unit outages treated in Day-Ahead and Real-Time? 4-16
5. Reserves 5-17
5.1 What are the BAs responsibilities with respect to reserves? 5-17
5.2 What are the Market Participant’s responsibilities with respect to reserves? 5-17
5.3 Why are reserves settled by zone in the DA Market, but settled across the footprint in the RTBM? 5-17
5.4 Does the SPP Integrated Marketplace include market functions for Installed Capacity or Reserves to meet System Capability requirements? 5-18
5.5 Why can curtailable Export Interchange Transaction Bids (physical schedules) only across DC Ties supply supplemental reserves? Why couldn’t other curtailable transactions that do not flow across a DC tie provide supplemental reserves? 5-18
6. Transactions 6-19
6.1 What is the difference between financial and physical transactions? 6-19
6.2 Can Financial Schedules also be used for Operating Reserves or just Energy? 6-19
6.3 Will there be any additional information for Financial Schedules provided through a physical scheduling system? 6-20
6.4 Which LMP will imports/exports/wheeling throughs be paid? 6-20
6.5 What is a hub? Why are they useful? 6-20
6.6 How will hubs be determined? 6-21
6.7 In today’s market, BA to BA transactions incur losses and there is a system in place for accounting for those losses, how will it change? 6-21
6.8 Will a Market Participant utilize Financial Schedules if an Operating Reserve product is provided by an external counterparty? 6-22
7. Congestion Management / Transmission 7-22
7.1 What is a Transmission Congestion Right (TCR)? 7-22
7.2 Why are TCR’s needed? 7-22
7.3 What is an Auction Revenue Right? 7-23
7.4 What entities have the ability to acquire ARRs and TCRs? 7-23
7.5 What is meant by “convert ARR to TCRs”? 7-24
7.6 When and how do I acquire a TCR? 7-24
7.7 What is the benefit of participating in the Annual ARR Allocation and Incremental ARR Allocation? 7-24
7.8 Will OASIS still be utilized? 7-25
7.9 Will RTOSS still be utilized? 7-25
7.10 How are TCRs or ARRs allocated for new load being integrated, or new transmission being built? 7-25
7.11 How could I lose a TCR which has already been granted? 7-25
7.12 How will grandfathered reservations be handled in congestion hedging? 7-26
7.13 Will Settlement Locations used for ARR and TCR sources and sinks be the same set of Settlement Locations used in the Energy and Operating Reserves Market? 7-26
8. Settlements 8-26
8.1 Why has SPP decided to perform settlement calculations for the RTBM for both Energy and Operating Reserve on a 5-minute basis as opposed to an hourly basis? 8-26
8.2 How will missing meter data be addressed? 8-27
8.3 Are Make-Whole Payments assessed on Virtual bids and/or Offers? 8-27
9. Market Monitoring 9-28
9.1 Does SPP intend to appoint an Independent Market Monitor that would oversee the new market? 9-28
9.2 Have minimum and maximum LMP prices been set for the market? 9-28
9.3 What is the anticipated offer/bid caps in the TCR and Energy Markets? 9-28
9.4 How will Financial Schedules and Virtual Energy Bids and Offers be monitored/verified? 9-29
Disclaimer: This FAQ document is intended to expand the understanding of the SPP Integrated Marketplace’s Design. These answers are intended to be representative of the Integrated Marketplace Protocols. In the event of any conflict, the Integrated Marketplace Protocols (including associated SPP Tariff Provisions) take precedent.
1. Acronyms
AGC – Automatic Generation Control
ARR – Auction Revenue Right
AS Market – Ancillary Services Market
BA – Balancing Authority
BAA – Balancing Authority Areas
CBA – Consolidated Balancing Authority
CBASC – Consolidated Balancing Authority Steering Committee
CBTF – Cost Benefit Task Force
CHTF – Congestion Hedging Task Force
DA Market – Day-Ahead Market
EIS Market – Energy Imbalance Service Market
EMS – Energy Management System
GCA – Generation Control Area
IPP – Independent Power Producer
LCA – Load Control Area
LIP – Locational Imbalance Price
LMP – Locational Marginal Price
MCP – Market Clearing Price
MP – Market Participant
MWG – Market Working Group
NERC – North American Electric Reliability Corporation
NITS – Network Integrated Transmission Service
OASIS – Open Access Same-Time Information System
Pnode – Pricing Node
RTBM – Real-Time Balancing Market
RTO – Regional Transmission Operator
RTOSS – Regional Transmission Operator Scheduling System
RUC – Reliability Unit Commitment
TCR – Transmission Congestion Right
TSR – Transmission Service Request
2. Basic
2.1 What are the Integrated Marketplace Benefits?
The SPP Integrated Marketplace will bring cost savings to the footprint. SPP is expected to lower total footprint production costs by incorporating unit commitment of resources on a regional basis instead of Market Participant by Market Participant. In addition, the SPP Integrated Marketplace will provide the costing mechanism to allow the CBA to procure and deploy Regulation and Contingency Reserves on a system-wide basis.
More details of the financial benefits can be found in the Cost Benefit Task Force (CBTF) findings and recommendations report located at:
CBTF Report: http://www.spp.org/publications/SPP%20Report%20April%20v8.pdf
CBTF Presentation: http://www.spp.org/publications/SPP%20CBTF%20Final%20Results%20Presentation%20MOPC%20v3.pdf
2.2 What are the major market components that SPP is adding with the Integrated Marketplace?
The SPP Integrated Marketplace will expand the current EIS market substantially. The plans include adding a Day-Ahead Market with Transmission Congestion Rights (TCRs), Reliability Unit Commitment (RUC) process, and incorporation of price-based Operating Reserves procurement.
2.2.1 Day-Ahead Market
The DA Market will be a financial market where Market Participants buy and sell Energy, as well as sell Operating Reserve, on a financially binding basis. Purchasing of Energy in the DA Market reduces the MPs exposure to price volatility of the Real-Time Balancing Market (RTBM). The DA Market will clear both price-sensitive as well as fixed (price takers) physical and virtual demand bids utilizing offered physical Resources and virtual supply offers. The DA Market will commit physical resources and calculate an hourly security-constrained dispatch level for each Resource, also setting the DA LMP for each Settlement Location. Both resources and load are settled based on the results of the DA Market.
In addition, the DA Market will also clear enough capacity to meet the Operating Reserve requirements for Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve. Reserves will be cleared with zonal constraints to ensure deliverability and each zone will have a DA Marginal Clearing Price (MCP) set for each of the four Operating Reserve products.
2.2.2 Reliability Assessment
To ensure there is sufficient deliverable capacity throughout the Market Footprint, SPP performs Reliability assessments prior to and following the DA Market. The reliability assessment executed prior to the DA Market provides SPP Operators with commitment of long lead time Resources. These Resources would have to begin their start-up process prior to completion of the DA Market, in order to be available for the Operating Day. If these Resources are determined to be necessary for Reliability purposes, the SPP Operator will commit the Resources in the DA Market.
Once the DA Market is complete, SPP will run a DA-RUC to commit additional resources in order to meet the full capacity requirements of energy and Operating Reserves for each hour of the next day. SPP will follow-up and continue to run intra-day RUC processes throughout the operating day, ensuring that the proper resources are committed as conditions change.
The outputs of the RUC are “start” and “stop” signals to Resources. There is no dispatch or settlement associated with the RUC. However, units called on by SPP are guaranteed to recover start-up, no-load and incremental energy costs in return for bringing their capacity to the RTBM.
2.2.3 Real-Time Balancing Market
The RTBM will continue to be a 5-minute market that dispatches energy, similar to today’s EIS market. However, as with the DA Market, the RTBM will also include the price-based procurement of Operating Reserves (Regulation-Up, Regulation- Down, Spinning, and Supplemental) on a security constrained, co-optimized, least-cost basis.
2.2.4 Transmission Congestion Rights Market
In the EIS market, physical schedules in RTOSS, including Native Load Schedules, are used to hedge the congestion costs of each Market Participant (i.e. the physical schedules remove the scheduled Energy from market settlements and serve as a hedge against congestion costs). Only energy deviations from the net schedules are charged out in the market settlements.
In the SPP Integrated Marketplace, all supply and demand is settled at the LMP. The TCR will work in much the same way that the schedule does today with regards to being a hedge against congestion. It backs out the congestion price for paths where a Market Participant holds the TCR. The SPP Congestion Hedging Task Force (CHTF) determined, after much education and debate, that a congestion hedge independent to the physical schedule would be preferable for the SPP Market Participants. TCRs are obligations, which could result in either a charge or a credit, and will be settled regardless of physical delivery of energy along the path.
2.2.5 Multi-Settlement
In the current EIS market there is a single settlement for the market. This is because there is only one market (i.e. RTBM). In the SPP Integrated Marketplace there will be two settlements, one for the DA Market and a second for the RTBM. The DA Market settlement is based upon the amounts of Energy and Operating Reserve cleared multiplied by the applicable DA Market LMPs and MCPs. The RTBM settlement is based upon deviations from Energy and Operating Reserve amounts cleared in the DA Market. These deviations are then multiplied by the RTBM LMPs and MCPs to calculate the settlement amounts.
2.2.6 Consolidated Balancing Authority
In coordination with the SPP Integrated Marketplace implementations, the current Balancing Authorities will be combined to form a single SPP BA.
2.3 What is the difference between the Day-Ahead Market and the Ancillary Services Market?
The term Ancillary Service Market is somewhat a misnomer. While it is true is that the Integrated Marketplace will set prices for certain Ancillary Services, specifically Operating Reserves (Regulation-Up, Regulation-Down, Spinning and Supplemental) it is not a separate market. Both the DA Market and the RTBM will set prices for energy and each of the Operating Reserve products as part of a co-optimized, least cost, solution.
The Operating Reserve procurement will be simultaneously co-optimized with Energy procurement in both the DA Market and RTBM. This process will move reserves when it is more optimal to carry energy on a resource, or vice versa while the pricing mechanism will ensure that the owner of the Resources is indifferent to which product they are supplying.
2.4 What is the difference between an LMP and an LIP?
From a calculation process there is little difference between the current Locational Imbalance Price (LIP) and Locational Marginal Price (LMP), which will be used for the SPP Integrated Marketplace. They both represent the price to serve the next increment of energy at a given location, or Pricing Node (PNode).
The difference lies in what quantity the price is used to value. In the current EIS market, LIP is used to value energy deviation, or “imbalance” from the net scheduled energy at the location. In the Integrated Marketplace, all energy in the market, both generation and load will be valued at LMP as part of the DA Market settlement.
2.5 Is participation in the DA Market required? If not, what is required to be submitted to SPP?
In the Day-Ahead Market, Market Participants must offer sufficient Resources to meet their forecasted net real-time load obligation and their load ratio share of the SPP Operating Reserve requirements. Market Participants may bid in any, or all, of their expected load. The load bids may be a combination of Fixed (Price taker) and Price-Sensitive bids. For the Day-Ahead Reliability Unit Commitment, and the Real-Time Balancing Market, Market Participants must offer all resources that are not on a planned, forced, or otherwise approved outage.
2.6 What controls are in place to ensure reliability?
Reliability is a function of the Reliability Authority and Balancing Authority roles that SPP fulfills, as opposed to a strictly market function. However, the implementation of the NERC reliability standards crosses many desks and departments. Compliance with the standards will be partially facilitated via the SPP Integrated Marketplace software and processes including: