Major grid operators in the United States are concerned that impediments to electricity trade are costing consumers hundreds of millions of dollars per year. For example, largely because of administrative factors and impediments to trade, power is being sent from high cost regions to low cost regions for too many hours in the year it seems. Two regional grid operators, ISO New England and the New York ISO, have put together a high level team of experts to address the problem. Their white paper, "Inter-Regional Interchange Scheduling (IRIS) Analysis and Options," was released in January. They propose a number of solutions, all of which include “Elimination of charges/credits on external transactions that deter trade.” Key parts of the paper are excerpted below.
"In July 2010, ISO New England Inc. (ISO-NE) and the New York Independent System Operator (NYISO) commenced a joint project to evaluate the economic and operational performance of energy interchange on their interconnected transmission network. This long-term project has two phases. Phase I, from 2010 – 2013, seeks to improve economic coordination between the two regions’ electricity markets. Phase II, from 2012 – 2014, will focus on coordinated congestion management and network modeling. This White Paper is the initial Phase I report. It evaluates the performance of the current interregional interchange system, describes alternative market procedures that could improve this performance, and provides preliminary economic benefit estimates from these improvements. The purpose of this White Paper is to facilitate stakeholder discussion of these options, and develop consensus recommendations that NYISO and ISO-NE can refine and implement.
The Status Quo
To enable physical trade of power requires an extensive set of market rules and procedures. The market monitor for NYISO and the (external) market monitor for ISONE, Potomac Economics, have expressed concern that the current rules governing interregional trade yield frequent price disparities between regions. Unless the transmission network is congested, these price disparities imply low-cost generation is used too little and high-cost generation is used too much. That runs counter to the ISOs’ shared objective of meeting demand at the minimum production cost.
The current interregional interchange system between New York and New England does not realize all of the potential benefits from trade between regions. Analysis in this report indicates that improved scheduling would produce significant benefits.
Ideally, power should flow from the region with lower costs to the region with higher costs. However, the region with lower costs switches back and forth frequently—often reversing within each day. The current scheduling system cannot react quickly to these changes. As a result, at the primary transmission interface between NYISO and ISO-NE power flows in the wrong direction—from the high-priced region to the low-priced region—more than 4000 hours per year.
In addition, data indicate that during the remaining hours of the year there is ample transmission capacity available to move additional power from the lower-cost region to the higher-cost region. As a result, production costs would be lower if the existing transmission interconnections were scheduled efficiently.
Potomac Economics estimated the economic benefits that could have been achieved if the transmission interconnections between New York and New England were scheduled efficiently. Comparing the status quo to an efficiently scheduled system, the estimated total production cost of meeting demand in the two regions (combined) would have been lower by a cumulative $77 million from 2006 through 2010. These production cost savings accrue to both regions.
The cost reductions would also produce lower locational marginal prices (LMPs) in each region. Potomac Economics estimates that if the transmission interface had been efficiently scheduled, loads’ total energy expenditures in the two regions would have been lower by a cumulative $784 million from 2006 through 2010. Each region’s energy expenditures would be significantly lower in every year examined, with magnitudes that vary by year with fuel costs and system conditions.
Solution options
To solve the problem of inefficient tie schedules between ISO-NE and NYISO, the two ISOs established a joint design team to develop solution options and recommendations. This White Paper presents conceptual designs for two solutions: (A) Tie Optimization and (B) Coordinated Transaction Scheduling. Either of these two options would have lower production costs than the status quo and result in significant savings for load.
While other options were examined, such as maintaining the current system with increased scheduling frequency, the two solution options in this report provide the greatest potential efficiency improvement. Each option directly targets the root causes of the inefficiencies in the current inter?regional scheduling system. In addition, each solution option adheres to several key design principles:
• Market-Based Solutions. The solution options both use competitive, market-based offers to determine the real?time schedule of energy interchange between their interconnected transmission networks.
• All Settlements at LMP. All scheduled energy flows between regions are priced at the LMP. This facilitates market transparency and correctly prices congestion.
• ISOS Have No Financial Position In Markets. The ISOs do not directly participate in the markets and do not buy or sell power. The ISOs continue to act as independent settlement administrators for the payments to and from market participants.
Both Tie Optimization and CTS employ several common elements:
• Higher frequency schedule changes across external interfaces;
• Elimination of charges/credits on external transactions that deter trade;
• Financial instruments (FTR/TCC) to hedge price risk at external interfaces.
To implement these elements, the two solution options share many operational and settlement details. However, they differ in the information they require of market participants. Conceptually, Coordinated Transaction Scheduling (CTS) is more like the current interregional trading system: CTS retains a role for external transaction offers to help determine real-time interface schedules between regions. In contrast, the Tie Optimization option is like the least-cost economic dispatch system used internally for each ISO’s energy market: It relies on the bid-based supply offers from generators and demand resources to determine real-time LMPs and transmission flows within and between the two ISOs’ networks.
Solution option A: tie optimization
The core concept of Tie Optimization is for the ISOs to optimize their external transmission links in the same way, or as closely as possible, that the ISOs optimize transmission internally. This achieves the lowest possible production cost and efficiently uses the existing transmission infrastructure.
The concept that underlies Tie Optimization is not new. It is the same bid-based, security-constrained least cost dispatch logic that underlies the wholesale energy market administered by each ISO. This competitive market design applies to all internal nodes and internal transmission facilities today. Tie Optimization simply extends this standard market design to cover the pool transmission facilities that interconnect the two ISOs.
Operationally, Tie Optimization coordinates real-time energy dispatch across both ISOs’ control areas through the exchange of load and offer data every fifteen minutes. This is made possible because of advances in communications and information technology, which allow the ISOs to implement a (near) joint energy dispatch without merging control rooms. We describe this system, called High Frequency Scheduling (HFS), in detail in Part III.
A subset of each ISOs’ market participants actively trade energy across the interface today. For them, important considerations are (1) hedging (congestion) price risk at the interface, and (2) fulfilling existing contractual obligations that involve scheduling between ISO regions. To address (1), the ISOs anticipate developing financial products (TCCs/FTRs) that would provide greater hedging ability at the interface than exists today. To address (2), the ISOs would revise certain ISO-specified scheduling obligations to conform to the Tie Optimization system, simplifying the current scheduling requirements, and work with other market participants to handle existing contractual scheduling obligations under the new system.
Solution option B: coordinated transaction scheduling
The second solution option is a package of external transaction enhancements called coordinated transaction scheduling (CTS). Like Tie Optimization, CTS employs higher frequency scheduling (HFS) and eliminates charges/credits on external transactions that deter trade. In contrast to today’s interregional scheduling system, CTS features:
• A simplified bid format, called an interface bid, for real-time scheduling;
• Coordinated acceptance of interface bids by the ISOs, using an improved clearing rule.
Like the current external transaction system, the ISOs would use two sets of market-based offers under CTS to set real-time external interface schedules: (1) participants’ external transaction offers to buy and sell across an interface, cleared against (2) the real-time generation supply stacks in each region. However, the structure of the external transaction bid format, and how it clears, differs between CTS and the existing inter-regional trading system. An interface bid is a unified transaction to buy and sell power simultaneously on each side of the interface. This bid structure is designed to resolve one of the root causes of the current system’s inefficiencies, ensuring that transactions determining real-time flows result in a net interface schedule that moves power from the lower-cost region to the higher-cost region.
As with Tie Optimization, CTS would enable market participants that actively trade energy across the interface today to (1) hedge (congestion) price risk across the interface, and (2) fulfill existing contractual obligations that involve scheduling between ISO regions. To address (1), the ISOs anticipate developing financial products (TCCs/FTRs) that are compatible with CTS and enable greater hedging ability across the interface than exists today. To address (2), the ISOs would revise certain ISO?specified scheduling obligations to conform to the CTS system and work with market participants
to handle existing contractual scheduling obligations under the new system.
Recommendations
The ISOs recommend the Tie Optimization option because it is the more efficient solution. This emphasis on efficiency reflects the ISOs’ shared philosophy of using competitive wholesale markets to meet power demand at the minimum production cost. The CTS system is presented as an option because it has the potential to provide significant efficiency improvements over the current system.
Tie Optimization and CTS will both enable the real-time net tie schedule to be adjusted frequently (every 15 minutes) in response to changing system conditions. This HFS procedure represents an important solution to a second root cause of inefficient schedules today: The inflexibility of current market rules to change tie schedules more frequently than hourly, in a power system where the location of the lowest-cost resource can change every dispatch interval.
The CTS system is not expected to produce as complete a price convergence between regions as Tie Optimization. The profit margin that market participants require to accept real-time price risk between regions when trading power will result in a price difference between New York and New England. That difference means the CTS system will tend to produce less efficient schedules, and higher production costs, than Tie Optimization.
With HFS and the improved clearing rule, it is possible the CTS system might yield price convergence that is nearly as efficient as Tie Optimization. The efficiency loss with CTS is difficult to quantify prospectively because the CTS bid format is a new product without clear parallel in other electricity markets today. The ISOs are actively engaged, with the assistance of Potomac Economics, in an effort to gauge whether production costs would be materially higher with CTS than with Tie Optimization."