Some believe that the Federal Energy Regulatory Commission's (FERC) proposal for reorganizing the nation's wholesale electricity market has been a power grab. With crises and scandals surrounding deregulation efforts occurring on a daily basis, the standard market design (SMD) is not popular with everyone. Even if legal obstacles to joining a regional transmission organization (RTO) are overcome, municipals and cooperatives face issues of rate design and implementation that may affect them disproportionately and render RTO participation disadvantageous. Issues may include rate designs that do not incorporate transmission-revenue requirements of municipals and cooperatives, accounting structure differences and unequal application of congestion management programs, causing discriminatory rate impacts.
As competitive markets evolve, we may observe several phases. Prior to deregulation, pricing is based on system average prices. As deregulation and competitive forces are introduced, market participants arbitrage the average pricing by “cherry picking” the most attractive customers with products and services, ultimately driving up the price for remaining customers.
To combat this, California adopted zonal pricing, which carved the state into several generation-pricing zones. These zones then became the next opportunity for arbitrage.
The final phase in the evolution of the electric market is the abandoning of zonal pricing and the adoption of locational marginal prices (LMP), which establish a unique price for each node or location in the transmission system. This theoretically sets the stage for eliminating cross subsidies and fostering competition, both from a supply and demand perspective.
What is LMP?
LMP is the price of the last megawatt of generation capacity that must come online to serve the last megawatt of incremental demand. When there is no congestion in the transmission system, the LMP is the same throughout the transmission grid. When the grid is congested, the LMP has different values on different sides of the congestion path because higher cost generators serve the local load.
Currently utilities are reluctant to build transmission lines, because deregulation has increased the perceived risk of recovering investment through rates, even if new lines eliminate congestion in the transmission grid and promote competition. FERC recognized this problem and provided for an increased rate of return to builders of transmission lines to try to strike a better balance between the perceived transmission investment risk and the return on investment. Specifically, FERC provided for an additional 2% rate of return on new transmission investments to eliminate congestion.
Even with this additional incentive, many transmission bottlenecks still exist within the United States. As one might expect, some market participants benefit from the bottlenecks by selling at higher prices and, therefore, it is difficult to achieve broad support for upgrades. In an efficient market, both the transmission and generation solutions must have a way to compete for that next megawatt of capacity. This is best understood through the application of LMP.
We know FERC's goal is to promote competition in generation. In an effort to put all market participants on equal footing, FERC has proposed a SMD that may apply to all RTOs throughout the United States. Though regional variations have been recognized and will be the subject of further discussion, FERC has universally embraced the concept of LMP in its proposed market design.
Given the pervasiveness of this concept and its many ramifications, it is obvious that the success of SMD mainly depends on the understanding and acceptance of the concept of LMP by market participants. The adoption of a market-based LMP transmission congestion management system is premised upon allocating scarce transmission capacity to those who value it most. Proper price signals should encourage short-term efficiency in the provision of transmission service and encourage long-term efficiency in the development of transmission, generation and demand-response infrastructure. FERC expects market participants will strike an appropriate balance between bilateral contracts and spot market transactions, causing the two prices to converge.
Challenges of LMP
Although FERC has embraced LMP for its market design, it has some drawbacks. Market participants may take advantage of generation market power by gaming their bidding process. Also, the economic cost of transmission constraints may be overstated since the LMPs may be temporarily inflated due to market power. We could also see uneconomic long-term transmission investments to solve short-term market problems. For LMP to be effective, it must incorporate real-time operations characteristics of the system into pricing and market response to achieve optimal dispatch of the generating plants in real-time, recognizing transmission constraints that include capacity, voltage and stability. Sophisticated tools are needed to handle real-time market dynamics and the complexity of the transmission system.
Application of SMD to all RTOs is a bone of contention. While FERC has had maximum experience with the markets in the Northeast with independent system operators (ISOs) addressing pricing issues and specifically with the PJM-ISO, the adoption of the PJM-ISO model to all other RTOs and ISOs is questionable.
Clearly, the West Coast market is different, simply because of the major hydro component; the “one-size fits all” approach adopted by FERC has the impractical requirement for short-term dispatch of the hydro system. At best, some design accommodations need to be made for LMP to account for this difference.
By proposing a SMD, FERC is trying to provide direction in the evolution of competitive energy markets. However, FERC's experience may be limited to the success stories of the East Coast ISOs, and applying it to markets nationwide may create more problems than solutions. While it is important to recognize regional nuances and allow for their inclusion in the design, FERC's bold initiatives to create a “brave new world” evoke mixed reactions at best. No doubt LMP is a great tool for some markets; however, its application to diverse markets will require some enhancements and modifications.
LMP is one way to quantify the impact of transmission constraints and a starting point for providing an incentive to market players to build transmission. To the extent that there is not sufficient incentive to eliminate the constraint, LMP becomes the basis for designing hedging instruments. A financial instrument called a congestion revenue right (CRR), or firm transmission right (FTR), has been designed to provide customers with price certainty for transmission.
While an FTR provides market participants with the opportunity to hedge their positions, it leaves a lot of uncertainty. Market participants must realize which lines are congested, must buy enough rights to cover them against congestion charges, and must know how to make their bids based on the amount of rights. All these are important decisions that market participants must make to maximize profits. While historical analyses are only a guideline, a strong need exists for analytical and software solutions that will empower the market participant in this regard.
The West Speaks Out
The Western Governors' Association sent a letter to FERC, signed by Wyoming Gov. Jim Geringer and Oregon Gov. John Kitzhaber, listing their concerns about the proposed SMD. The letter pointed out:
The SMD rule “seems to mark an end” to efforts to form voluntary RTOs in the West.
The proposed rule appears to include improper federal intrusion into areas of state authority.
The proposal is based on a geographically small East Coast RTO that appears to be impractical for the “huge Western Interconnection that spans parts of three nations.” In addition, unlike the West, the East Coast RTO known as PJM is not heavily reliant on hydropower.
The SMD proposal needs much further study as to impacts on the West.
FERC's proposal to “unravel protections afforded to utilities' native loads is very troubling.”
The “presently fragile Western economy cannot afford missteps that may result from the unprecedented changes to our electric power system that are embodied in the SMD rule.”
The U.S. House Appropriations Committee passed a bill directing the Secretary of Energy to report on the costs and benefits of a federal agency's plan to standardize electricity markets. The committee is concerned about the possible impact on regional electricity prices of FERC's proposed rules for SMD. This independent analysis must compare wholesale and retail electricity prices in the major regions of the country under existing conditions and under the proposed new rule.
Distributed Generation and LMP
LMP makes distributed generation more attractive in congested areas because load served by the distributed generation avoids paying the high price. Distributed generation also can fetch the locational energy price for the excess power sold to the market. FERC's SMD requires a proactive planning process in which all resources are treated the same, making SMD principles amenable to distributed generation. SMD also specifies that intermittent resources should be allowed to participate in the day-ahead and real-time market on the same basis as other resources.
What Does it All Mean?
Transmission congestion is one of the most important features that signals the need for expansion in the system. Transmission congestion will always exist in the system, because it is a natural consequence of supply and demand. Without the use of LMPs as a means to identify locations that require transmission expansion, it will be difficult to know when and where transmission expansion should take place.
LMP provides a framework for comparing transmission and generation investments. Eliminating all congestion on the transmission grid would not make sense. Congestion and LMP form the fundamental concepts for optimizing the mix of generation and transmission solutions in a deregulated electric market. The LMP methodology will work if diverse regional electric markets are willing and able to adapt to their unique power system characteristics.
Virgil Rose is senior vice president of energy delivery and management for Nexant Inc. (San Francisco, California, U.S.), where he serves the North American utility market's major electric and gas utilities, energy companies, energy service providers and government agencies. He also investigates technology-based solutions for the utility sector. Prior to Nexant, Rose was senior vice president of electric supply with Pacific Gas & Electric Co., responsible for power generation, high-voltage transmission, power contracts and system dispatch. He is a senior member of IEEE and a registered professional engineer.
Siri Varadan is a senior consultant at Nexant Inc., where he heads the transmission and distribution services business area, presently addressing transmission planning needs for Pacific Gas & Electric Co., as well as demand-side management investigations for the California Energy Commission. He has conducted LMP studies on the CAISO grid using SCOPE™, and is an expert in EMS/SCADA applications. Dr. Varadan is a senior member of the IEEE and a registered professional engineer.
How LMP Works
Perhaps the best way to illustrate the concept of locational marginal pricing (LMP) is with a simple two-node power system example (see page 72).
A line flow constraint of 500 MW is imposed on the transmission line between Node 1 and Node 2. With an incremental increase of load at Node #2, generator C sets the price, as no additional power is available for import from generator A, due to the line constraint. This results in a LMP of 5 cents/MWh at Node 1. Generator A may support an incremental increase of load at Node 1, resulting in an LMP of 4 cents/MWh at Node 1. The figure also shows the payments made by loads ($69.50) and the payments to generators ($64.50), illustrating a non-zero sum game. The difference in monies (congestion fee) received and paid remains with the ISO/RTO and is to be distributed to the transmission owners or to transmission rights holders.
For the same example, without congestion (no constraint on line flow between nodes), economic dispatch would prevail with Generator A supplying the incremental load at both nodes at a LMP of 4 cents/MWh. In this case, loads pay $62 and the generators receive $62, illustrating a zero sum game for that hour of operation.