To: John Carr, Chair, Transmission Finance Committee
From: Phil Carver, Oregon Office of Energy
Subject: Final Version of “Financing Electricity Transmission Expansion in the West, A Report to the Western Governors”
The Oregon Office of Energy participated in the Transmission Finance Committee (TFC) that produced the report in the packet for the upcoming WGA meeting. The report notes that “… there has emerged among the TFC members a broad consensus on the following points.” The Office of Energy concurs on the recommendations, but does not concur on the report. I and others proposed corrections that were not included in the final version. As a result, it still contains serious errors and omissions.
Specifically the report should have noted:
1. For the West, there is no evidence of the need for bulk transmission lines beyond those currently being planned;
2. Regulatory uncertainty is not the only factor that has inhibited transmission investments;
3. Utilities and state public utility commissions would lose control over transmission investment decisions under the total system cost allocation model, but not under the market-driven model;
4. The concerns in the report about the market-driven approach have been largely resolved by the RTO West approach; and
5. The market-driven model is more likely than the total system cost model to meet electricity needs at the least total cost.
The report notes that “Analyses performed by the FERC, the Edison Electric Institute, as well as other individual industry participants agree that there is a “need” to build more transmission infrastructure.” (Page 14, third paragraph) These studies do not relate to the West.
There are several transmission projects under way in the
West. These include twenty proposed
projects by the Bonneville Power Administration and several projects in
California and Arizona. These are
largely to interconnect new generation or to relieve local transmission
congestion. Studies for the IndeGO
proposal for an independent grid operator and the WGA Conceptual Plan have
shown that there is not enough current or anticipated transmission congestion
to economically justify transmission projects beyond those underway. The models indicate that the roughly 25,000
MW of new gas-fired generation now under construction
will reduce the need for bulk transmission across the West.
Regulatory Uncertainty and Risks
The report discusses
the financial risks to transmission investors due to regulatory uncertainty. These risks have likely deterred some
transmission investments. Perhaps
equally important is the risk that near-term implementation of alternatives to
transmission investments may make large-scale transmission projects useless
shortly after they are built. The major
risk is the construction of new gas-fired generation close to loads. Other such risks include load controls, fuel
switching, and new efficiency technologies.
The report recognizes that “this lack
of durability of market signals for transmission investment increases the risk,
regardless of which party bears that risk.” (page 19, fourth paragraph). It does not acknowledge that this real risk
may be why there are so few proposed transmission projects.
The formation of RTOs is likely to reduce the need for transmission investments by allowing more efficient use of the existing system. RTOs plan to price congestion so that the value of power at specific locations will be apparent. They also plan to improve the ability to trade existing transmission rights. These will further encourage alternatives to transmission. RTOs will also free up capacity that is currently lost through contract path scheduling or withheld by rights holders and only released as non-firm capacity at the last minute.
Under the total system cost model, regional transmission organizations (RTO)s would decide which transmission projects to pursue and how to allocate the costs. Cost recovery would be subject only to approval of the Federal Energy Regulatory Commission (FERC). Project costs would likely be spread to all or most users. Allocating costs to beneficiaries is difficult as forecasts of a project’s benefits over its lifetime are highly uncertain.
In contrast, the market-driven model would leave decisions on how best to serve loads to utilities and other suppliers, as is the case today. State public utility commissions would continue to review decisions by investor-owned utilities. Locally elected boards would continue to oversee consumer-owned utilities. Since the governors are likely interested in this distinction, it should have been included in the report.
Under either model, projects would have to meet state siting standards, if any. By allocating costs, rather than facilitating projects, the total system cost approach would tend to provoke conflict. If the parties that benefited from a project agreed to pay for it, there would be no need to allocate costs.
Implementation Issues for the Market-Driven Financing Model
The report raises a number of concerns about implementing the market-driven financing model. These issues were discussed in the Planning and Expansion Content Group for RTO West and resolved. This group agreed that the market-driven model would be superior and should be tried first. If it fails, the proposal would give RTO West the authority to allocate costs.
The report states that changes in electric flow patterns “could present difficulties in defining firm physical rights for investors.” (page 19, third paragraph). But RTO West would not require physical rights to use the grid. It will accept all proposed uses of the grid. Users would be responsible for the costs to clear congestion.
Instead of physical rights to schedule, RTO West plans to sell or issue financial hedges against transmission congestion costs. If flow patterns change, holders of financial hedges will remain protected from congestion costs. The price of new hedges would be based on the cost of transmission investments to clear the bottleneck, so they would not “result in radically different pricing for equivalent but sequential expansions.” (ibid.).
The report states that “a market-financed transmission project may have a bias towards under-sizing the transmission expansion since an expansion that completely removes a constraint would also remove the scarcity value of transmission access across that constraint.” (page 19, end of the fourth paragraph). This is incorrect for an RTO West type of market-driven model. Generators, utilities or electricity suppliers (load-serving entities) would invest to protect themselves against high costs of delivering power to loads. If price differentials disappeared due to the transmission project, that would not invalidate the decision to invest. Load-serving entities would only invest if that appears less expensive than suffering congestion costs, absent the project. This is the economically efficient comparison.
The market-driven model, by itself, would not guarantee that load serving entities will provide the socially desired level of electric reliability, any more that the current system. To account for this contingency, RTO West would have the authority to implement transmission and non-transmission alternatives if reliability standards were not met. RTO West would allocate these costs to loads that did not meet the standards. Faced with this threat, load-serving entities would likely meet the standards themselves.
The RTO West proposal also provides for allocation of costs if there is a market failure to mitigate “chronic, significant, commercial congestion.” RTO West would “address the cause of the market failure” and seek to remedy design flaws and change market rules, as well as expanding the system (Feb. 6, 2002, RTO West Planning and Expansion Proposal, page 14, text and footnote 4)
The report states that “Advocates of the total cost model argue that the penalty of not building enough transmission capacity can be many times the cost of building too much. Hence, even if, as opponents of this approach contend, the total cost model did tend to err on the side of building too much transmission, this approach would be preferable to one that resulted in too little transmission.” (End of Section 7.2.2, page 19). The “penalty” presumably refers to blackouts or spikes in power prices. This incorrectly implies the only options are too little or too much transmission investment. The options also include the appropriate location of new generation and implementation of the other non-transmission alternatives. These alternatives can meet electric needs just as reliably and at lower cost than over-building transmission. RTO West would have the authority to enforce reliability standards.
As transmission organizations, RTOs are likely to focus on transmission projects and will have limited ability to implement non-transmission alternatives. Many of the alternatives to building transmission lines can only be implemented by utilities or other entities that directly serve end use customers. These include siting new generation closer to loads, end use load controls, demand buy-back programs, and retail rate designs to encourage end users to shift use away from peak times. RTOs can only influence these decisions indirectly.
Under the market-driven model, utilities and other entities that serve loads could invest in the mix of transmission, local and distant generation and demand-side measures that they expect will minimize their costs and risks.
The distinction is clearest on incentives to locate generation appropriately. If the total system cost model removes congestion and spreads the costs to all users, it removes the incentive for builders of new generation to locate on the downstream side of transmission bottlenecks. Under this model builders could locate on the upstream side, confident the RTO will charge others to remove the congestion costs the builder creates. Yet, the generators, or the loads they serve, would pay the full cost of delivering fuel to their power plants. This would bias the choices toward mine-mouth coal-fired plants and away from gas and coal-fired power plants built closer to loads, even when the total cost of the latter was less. It would also encourage gas-fired plants to be built further from loads than would be economic.
Under the market-driven approach, operators of new power plants would pay the transmission congestion costs of delivering the power to loads. If power plant builders, utilities or other load-serving entities thought these congestion costs might be too high, they could invest in transmission and be protected from future congestion costs. This provides them with the correct incentives to minimize costs.