The LMP Model: Bottlenecking Merchant Transmission

Locational marginal pricing has not been adequate in providing transmission expansion incentives. Others are needed.

With the controversy created by the inclusion of locational marginal pricing (LMP) and a two- settlement system as part of FERC's standard market design (SMD), many questions have been raised about the market rules and procedures needed to support transmission infrastructure improvements, including transmission expansion. Noting that little, if any, transmission expansion beyond direct generation interconnection has occurred in the regions using LMP, some have questioned the ability of the current LMP systems to provide effective transmission expansion incentives.

In the markets in the Northeast, where LMP has been in place and sending regular price signals to market participants, there is forward movement and progress on developing some of the necessary market mechanisms to support structural remedies for congestion; however, much more remains to be done to ensure the viability of structural solutions.

While the development of unforced capacity deliverability rights (UDRs)¹ is a step forward in providing the correct incentives for merchant transmission, it remains unclear whether these and other existing incentives will be sufficient to ensure that necessary economic improvements to the transmission system will be undertaken.

Supporting the development of transmission infrastructure requires more than simply installing wire. In a market-based system, it is vital that the underlying market rules send the correct economic signals for both the use and expansion of that transmission system. Structural solutions to congestion require market rules and procedures that promote the economic use and expansion of the transmission system. These market mechanisms must apply to transmission expansions connecting multiple regional transmission organizations (RTOs) or independent system operators (ISOs), as well as those located entirely within an RTO, and should focus on the benefits created by transmission expansion.

Capacity Benefits of Transmission Expansion

Early ISO development and implementation focused on jump-starting the day-ahead and real-time LMP markets, with additional effort focused on developing market-based ancillary services and capacity markets. Ensuring that sufficient market mechanisms were in place to provide incentives for economic improvement to the grid was not at the top of the agenda. Figuring out how to integrate merchant transmission into the market, especially when the new transmission interconnected two adjoining ISOs, was further down the list. While the Northeastern ISOs cooperatively broke the ground in the United States in implementing LMP, the success of LMP on a regional and national level requires workable mechanisms to ensure both economic and reliability improvements to the grid.

In addition to serving energy needs, one of the features of transmission expansion is that it allows more capacity located at a distance from the load to be delivered to that load. This incremental ability both changes the price and quantity of energy that can reach that load, and it also contributes to the reliability of meeting that load.

Transmission expansion can make a significant contribution to meeting local reliability requirements if market rules are structured to send the correct price signals to market participants that expand the system. Market rules governing transmission expansion should include the award of capacity deliverability in situations where transmission expansion improves the deliverability of capacity and increases the reliability of the system.

In a recent order signaling FERC's willingness to support the development of market mechanisms providing incentives for new merchant transmission, the commission approved the New York ISO's (NYISO's) proposal for the creation of UDRs for transmission expansion. UDRs are property rights that can be awarded to transmission expansion and upgrades for the increased capacity benefit of an upgrade into a constrained area. These rights are analogous to the award of congestion revenue rights (CRRs) for hedging energy congestion.

Like CRRs, UDRs are not a physical right of delivery, but rather a financial right to count the generation capacity located in one area toward the capacity requirement of another area. UDRs, once implemented, will be able to be sold bilaterally to loads or generators, or when combined with qualified capacity, to be sold in the NYISO-administered capacity auctions. Future enhancements to the NYISO auctions may allow UDRs to be combined with the capacity within the auction.

The Cross Sound Cable: A Case Study

The Cross Sound Cable (CSC), which interconnects in New Haven, Conn. (ISO-NE), and Long Island, N.Y. (NYISO), is likely to be the first beneficiary of FERC's UDR treatment. Cross Sound was the example used in the development of the market rules and procedures in the NYISO.

Developed by TransEnergie US as a merchant transmission facility and contracted on a long-term basis to the Long Island Power Authority (LIPA), the CSC is a 330-megawatt (MW) high-voltage direct current (HVDC) underwater cable. LIPA, its consultants, and TransEnergie, in conjunction with FERC, have worked together to lead the effort in developing the market rules and procedures that will integrate this fully controllable merchant HVDC cable into the northeast energy, ancillary services, and capacity markets.

Moreover, the NYISO, and its predecessor the New York Power Pool, have used a statewide installed capacity requirement (ICAP) to serve the state's resource adequacy needs, assuring that sufficient capacity exists to meet the utilities' peak load plus an installed reserve margin. As retail competition evolved and as NYISO was formed to manage the transmission grid, utilities and other energy service companies serving customers were assigned a share of the statewide ICAP requirement. In addition to the statewide requirement, New York City and Long Island, due to transmission constraints, were defined as separate localities, with additional local ICAP requirements.

There is not enough transmission capability between these two areas and the rest of New York state to serve the peak load of these constrained regions without the support of generation located within the area. Therefore, the locational ICAP requirements were established to ensure that sufficient generation capacity was built to assure maintenance of reliability standards.² Utilities and energy service companies meet their local needs with local resources and procured ICAP in excess of their local requirement from the rest of New York State or with an acquired import right from a neighboring control area such as ISO-NE, PJM, or Hydro Quebec.

The development of the Cross Sound Cable increased reliability in New York and New England by increasing energy deliverability between the areas. NYISO has determined that the additional transmission capacity provided by the CSC will increase the limited quantity of capacity import rights from New England to New York, decrease the ICAP locational requirements for Long Island,³ and potentially reduce NYISO's statewide ICAP requirement by allowing additional sharing of resources across the Northeast. The CSC could provide similar resource adequacy benefits to New England, although as yet no commensurate property rights have been defined or allocated to the expansion.

Since the Cross Sound Cable is a merchant transmission facility, the resource adequacy benefits of the transmission expansion should be collected as a property right and provided to the transmission expander as an offsetting benefit for the investment in the transmission facility.

Market participants in NYISO created UDRs or capacity deliverability rights for the purpose of capturing the resource adequacy benefits of the transmission expansion and allocating them to the transmission expansion. In the case of the Cross Sound Cable, the Long Island locational ICAP requirement will remain unchanged, but the CSC will be allocated approximately 315 MW of UDRs that, when combined with qualified capacity resources in New England, will count toward the Long Island locational ICAP requirement. The CSC UDR is essentially a capacity deliverability right between the two regions. The value of the UDR will approximate the difference in capacity costs between the New England market and the higher-priced, constrained, Long Island market less any transaction costs. UDRs can be used by the transmission expander or sold bilaterally to other customers to be used to meet their locational capacity requirement and allow the valuing of the capacity benefit of merchant transmission. Defining the development of UDRs and their assignment to the transmission expander provides one additional incentive to undertake economic improvements to the grid.

The Future of Merchant Transmission

Merchant transmission can play an important role in improving transmission infrastructure, but merchant transmission expanders should be distinguished from transmission owners with the opportunity to be reimbursed through cost-based rates. Merchant transmission expanders are much more sensitive to market structures and economic price signals than are traditional regulated transmission providers that can average the costs of a transmission expansion along with existing transmission costs into regulated rates. Thus, merchant transmission is particularly sensitive to the underlying market rules and getting the prices right.

Supportive market structures identify areas where merchant transmission adds value, defines property rights associated with this added value and allocates them to the transmission expander, allows for the transferability of these rights, and avoids regional differences that extend old or create new seams issues. Although regulatory certainty cannot be assured, the rights created should be as robust and permanent as possible and incorporated in formal tariff language, with revisions requiring FERC approval. Certainty and stability of property rights and the market rules that support them improves the viability of structural solutions. Transferability of property rights allows parties that have transmission development skills to develop facilities on behalf of other parties who may have a specific need for the expansion or the rights associated with the expansion. Regional differences in market structure should be carefully reviewed to assure that new seams issues are not created.

By defining rules that specify revenue streams and/or other privileges that match the characteristics and capabilities added by the expansion, the value to the expander is increased. As the expander captures more of the value that the expansion creates, the viability of this structural solution is improved. Thus, while allocating congestion, energy, and capacity revenues is important, the challenge facing regulators going forward is to think beyond congestion reduction to other sources of revenue that are appropriate to allocate to the expander because they would not be possible "but for" the expansion. Some of the broader benefits of transmission expansion include the following:

Increasing reliability by improving the deliverability of generation to load during conditions that stress the reliability of the system;

Creating the ability to move energy from one location to another where the energy has greater value, including the ability to move high priced emergency power;

Improving the ability of power to move through the remainder of the transmission network by reducing the impacts of system contingencies on the rest of the system. In a security-constrained dispatch, this can improve normal flow limits on constrained transmission elements outside of the expansion;

Providing ancillary services such as voltage support service by providing controllable reactive power output, both when there is flow over the expanded facilities and when there is not;

For transmission expansions connecting multiple control areas, improving the ability of these areas to share operating reserves;

Reducing market power by increasing the size of relevant geographic markets, thereby increasing the apparent number of competitors in energy, capacity, and ancillary service markets; and

Within a control area, reducing the number of units that must be committed to meet expected regional loads by allowing a wider pool of generators and potentially diverse loads to be considered in the unit commitment decision thereby reducing system uplift costs associated with unit commitment.

In approving UDRs, FERC has signaled that it is willing to support new market incentives for structural improvement to the grid. To ensure that structural remedies to congestion such as merchant transmission are viable, much more must be done. Further progress on developing additional market incentives and related mechanisms is important to ensure that economic improvements to the transmission system can and will be undertaken.

Unforced Capacity is the means for accrediting generating capacity in NYISO, ISO-NE and PJM. Unforced capacity adjusts the amount of capacity a generating unit can sell to meet a resource adequacy requirement by that unit's availability (i.e. a 100-MW unit with a 95 percent availability can provide 95 MW of unforced capacity). This discussion focuses on capacity for simplicity.

Customers in New York City must procure enough ICAP from resources in New York City to equal 80 percent of their peak load. Customers on Long Island must procure ICAP from Long Island resources to equal 93 percent of their peak load.

Preliminary studies demonstrated that if the benefits of the CSC were spread to all customers on Long Island that the locational ICAP requirement could be reduced from 93 percent of LI peak load to 87 percent.

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