A proposal to remove the bottlenecks on grid investment.
Investments in the U.S. transmission grid have been declining since the early 1970s.1 Reasons include: 1) regulatory uncertainty; 2) onerous and multiple regulatory jurisdictions; 3) an extremely complex and time-consuming siting and permitting process; 4) uncertainty in the basic "who pays" vs. "who benefits" equation; and 5) shortcomings in the regional-planning processes.
The U.S. bulk transmission system now is stretched to the limits of its capacity. System operators are doing a remarkable job day in and day out of keeping the system in a secure state while squeezing out the last megawatt of transfer capability. Not investing in the bulk transmission system leads to congestion costs. More generation should be designated as RMR (reliability must-run generation) and higher reserve margins are necessary. In the longer term, lack of investment in transmission limits our ability to incorporate green, low-cost energy sources such as wind power into the grid. A study by ICF Consulting reported in clearly establishes that the benefits of transmission investments far outweigh the costs.2
So what is being done to facilitate investments in transmission? The Federal Energy Regulatory Commission (FERC) consistently has recognized the need to encourage investments in the nation's grid and has proposed a number of incentives for transmission companies to do so. It also has been favorable to merchant transmission proposals, and has gone so far as to back market-based bilateral arrangements for transmission (, TransEnergie's Cross Sound Cable).
FERC also has endorsed regional transmission expansion planning (RTEP) by RTOs. The RTEP process is well established in RTOs such as PJM and New England, and is under development in other regional planning entities, including New York. But given all the pushing and prodding by FERC, transmission investments remain anemic.
The lack of transmission investments transcends the usual siting and other complexities that utilities have grappled with for decades, pointing to a serious flaw in the market structure for transmission investments. In fact, the two main pricing options for transmission owners, both popular with regulators, have serious deficiencies. The first pricing mechanism involves recovering embedded costs via a network access charge (sweetened by FERC incentives). The second involves entitlements to receive congestion revenue rights (CRRs). The first pricing mechanism is a traditional cost-of-service model, which does not allow a transmission company or ratepayers to capture the benefits of innovations in technology or management. Given the costs, risks, and complexity of building transmission projects, the regulated rates of return may not offer enough incentives for transmission investments.
The second mechanism based on CRRs is simply too little and too uncertain to be bankable. The fatal flaw in this CRR mechanism is that once the transmission corridor is upgraded, the CRRs are worth a lot less than when the congestion was in effect. Former FERC Commissioner Don Santa notes that "while LMP functions as a means for rationing scarce transmission capacity in an economically rational manner … this does not necessarily mean it is a powerful incentive for transmission construction and upgrade."3
A long term (10 years +) congestion revenue rights (CRRs) administered by the RTO could be a workable solution. Like a long term bond these long term CCRs would have a guaranteed income stream even if the short term CCRs diminish or go to zero if the constraint is eliminated. This would make transmission investment financiable. Making the return on transmission investments correlated to the system economic benefits would spur technology applications in the Grid and make transmission investments more attractive to financial markets.
While regulators seem to buy wholeheartedly into the locational marginal price (LMP) concept in developing market structures, they do not fully appreciate that if LMP signals are to provide a mechanism for long-run system investment decisions, the market structure should allow rational choices to be made among generation, transmission, and demand-side infrastructure options. The concept that seems to trip up a lot of industry stakeholders is the prevalent but erroneous concept that transmission is an enabler and does not compete with generation options. A corollary to this concept is that we should not do anything with transmission that would distort the energy market. The fundamental fallacy of this agreement is that transmission does affect the energy and capacity markets. In fact, transmission defines these markets. A well-defined LMP-based market mechanism for transmission investments should allow for tradeoffs among generation, transmission, and demand-side options for serving future energy needs.
Let us explore transmission in energy markets in terms of an enabler versus a market participant. The bulk transmission system allows generating units to compete within a wide geographic area to create efficient markets. However, by building transmission we can displace the need for local generation. In this scenario, owners of displaced local generation would view transmission as a competing entity, though transmission's role merely is to "enable" remote generation to compete in a local market. Thus, the true nature of the market impact of transmission upgrade options is somewhat more complex than that of a passive "enabler."
Transmission allows power plants to compete within regions. If there is no transmission congestion the LMP in every node of the region is the same. As demand for power increases, certain lines may reach their limits over a number of hours. In a region where transmission constraints are prevalent, LMPs are not uniform across that region. Congested transmission corridors also have congestion costs associated with them that can be hedged against using CRRs and similar financial instruments. The rational mechanism for upgrading a transmission corridor would be to upgrade when the present value of the congestion costs is greater than the cost of the upgrade. The view of transmission as an enabler works very well in this scenario.
Now examine a case where several regions are interconnected by tie lines (). The graphic on the left shows a number of load-serving entities connected by weak transmission ties. The graphic on the right shows the same load-serving entities with stronger transmission ties. The connected load for the load-serving entities remains constant at 8,000 MW. The change in generation reserve requirements and production costs that follow upgrades to the transmission corridors is indicated and explained below.
The regions in the hypothetical example started with weak inter-regional ties. When these ties were strengthened, 3,000 MW of local generation were "displaced." Costs came down while the reliability index was maintained at the previous level (one day of shortage in 10 years). In reality, stronger transmission ties "enabled" low-cost generation to compete in local markets, and the ability to share reserves during peak loads and outages allowed individual regions to cut installed capacity while maintaining the same level of reliability. This exact scenario prompted utilities to build strong tie lines with their neighbors in the 1950s and 1960s, thereby saving substantial amounts of money, in terms of generation investments, by building transmission tie-lines with their neighbors. In today's market environment, the weak tie-lines indeed would show congestion and accompanying congestion costs. However, any attempt to upgrade these corridors would be seen by local generation as competition. To a local generator, any proposed transmission upgrade of tie lines would probably be more of a threat than would the addition of a neighboring generating plant.
A mechanism that works for transmission investments is a market-based bilateral arrangement for transmission that competes with generation and demand-side solutions. In the words of former FERC Commissioner Don Santa, "As long as the proposed transmission facility places downward pressure on the price of market-based solution to high prices at a node, from a public policy perspective why should the regulator care whether the economic rent is being collected by a generator, a demand-side operator or a transmission provider?"3 FERC recognized this paradigm in the case of TransEnergie's Cross Sound Cable project.
It is worthwhile to examine the Cross Sound Cable model. In this model, the load-serving entity (LSE)-Long Island Power Authority (LIPA)-purchased long-term transmission capacity rights on a high-voltage direct current (HVDC) cable into Long Island. New York has a locational capacity market (LICAP), and the price of a megawatt of capacity in Long Island is significantly higher than the price of a megawatt of capacity in upstate New York. The extra capacity and energy provided by this cable allowed LIPA to meet its capacity requirements and import lower-cost energy from New England. In this case, FERC allowed a market-based bilateral arrangement for transmission that competed with generation and demand-side options. The success of this model allowed LIPA to go for the next round of competitive bidding between generation and transmission options that resulted in the selection of a second cable project into Long Island (Neptune Project). Both transmission cables selected by LIPA are HVDC cables. HVDC cables are controllable so that the flow into Long Island can be controlled. However the same construct may be used for the more common alternating current (AC) upgrade where incremental transfer capability (which has a value in the LICAP market) can be used as a basis of a long-term bilateral financial contract.
The three pillars of the Cross Sound Cable model are:
A locational capacity market; A long-term bilateral contract for transmission rights; and LSE sponsorship.
The critical element of this is the ability of the LSE to enter into a long-term contract for transmission rights. That makes the project financeable and allows a true market mechanism to function for transmission.
To remove any conflicts of interest and create a level playing field for procuring the most reliable and low cost energy supply for the loads they serve, it may be necessary for LSEs to divest their generating assets to satisfy their regulators. If the LSEs are pure distribution companies, they would be in the best position to source the wholesale power needs of the served load. LSEs are in the best position to do a market trade-off between generation, transmission and demand side alternatives in procuring energy at the lowest cost and highest reliability.
The tortured process of regional planning by RTOs and protracted negotiations on "participant funding" simply will not produce a market-driven solution that will get the job done in terms of upgrading the U.S. transmission grid. Regulators need to recognize that transmission, along with generation and demand-side management options, is part of a rational economic market structure for electricity markets. The paradigm shift that needs to occur in the mind of regulators is to put the LSEs in the driver's seat and have the RTO provide regional planning oversight rather than try to be a rate-maker, regulator, facilitator, and arbitrator rolled into one.
Having a market driven process for transmission expansion would spur innovation and applications of new technology solutions. The current regulated approach rewards investors based on dollars invested rather than benefits of the upgrade. There is little incentive for innovation or investments in new technology. For example let's assume a $10 million transmission line upgrade or a $5 million investment in Flexible AC Transmission Technology Systems (FACTS), both generate a 9 percent regulated return and provide the same $100 million in energy cost savings. The regulated return on the investment in FACTS would be half of the low tech solution so there is no incentive for transmission system owners or investors to push the envelope in terms of technology applications. To foster innovation, the payback in the transmission investment should be in terms of the savings and not on the dollars invested. A market based procurement of transmission capacity or generation capacity by LSEs would provide a market mechanism to do just that without the complex, long drawn and contentious cost allocation process that the RTO based transmission expansion planning entails.
LSEs "own" the load. They are required to ensure adequate capacity and to provide low-cost power. Putting LSEs in charge of procuring the best combination among generation, transmission, and demand-side options to satisfy their capacity and energy needs is fully consistent with an LMP-based market structure and constitutes an effective solution to the "big brother RTO" approach. This market-driven solution is possible only if regulators recognize the fact that transmission is part of the decision mix and not a passive "enabler." Truly efficient and market-driven energy markets will be possible only when regulators recognize this truth and act accordingly.
- Eric Hirst, .
- "Profiting From Transmission Investment," Kojo Ofori-Atta, et al. , October 2004.
- "SMD: Performance Versus Promise," , Edison Electric Institute, November/December 2002.
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