How to allocate the costs.
Efforts to establish and quantify congestion-reduction and loss-reduction projects are progressing in electric markets with locational marginal price (LMP) regimes. The Path 15 upgrade approval by the California ISO two years ago was largely based upon its economic benefits. A draft report from the Electric Reliability Council of Texas (ERCOT), , states that ERCOT will consider transmission projects that are "economically justified by the reduction of congestion and losses."1
The regulations from FERC Order No. 2000 can be interpreted as placing the responsibility on the regional transmission organization (RTO) to initiate these economic upgrade projects:
Such economic projects usually involve transmission upgrades that relieve bottlenecks, thereby freeing up lower-cost power to displace higher-cost generation dispatched due to insufficient transmission capacity. In addition to causing higher operating costs, inadequate transmission may affect reliability if the full output of a generator is not realized due to transmission constraints.
In markets that impose a generation reserve requirement upon their load-serving entities (LSEs), generation should be deliverable if it is to be counted toward meeting the region's reliability needs. Despite the obvious link between congestion and reliability, most planners consider these separate problems. Meeting reliability standards is a "must," while reducing congestion is a "want," since it is viewed as an economic issue only. This paper will use this commonly accepted framework, viewing congestion-reduction projects as discretionary economic investments. Therefore, the major issue facing central planners and stakeholders in an RTO is: "Who should pay for the cost of an economic upgrade?"
In the absence of participant funding, cost-allocation is a critical issue in regions that use zonal (a.k.a., "license-plate") rates. The "who pays" question becomes, "Which zone(s) should be allocated a portion of the project's revenue requirements?" True participant funding leaves decisions on economic upgrades to the marketplace: Any entity may self-fund an economic transmission project in return for the incremental financial transmission rights (FTRs) created by the project, as well as the lower (or higher prices) resulting from the project.4 Zonal rates are not affected since the funding for the project is never included in any zone's revenue requirements. Some markets have imposed participant funding on new generation interconnections, thereby providing incentives for new generators to consider both the transmission cost and congestion impacts of their siting decision. PJM requires new generators to participant-fund their related network upgrade costs. Order No. 2003 permits participant funding in an RTO as an alternative to its "crediting with interest" policy.5
However, for non-interconnection related transmission projects targeted at congestion or loss reduction, the issue of who should pay is still being addressed in RTOs. The obvious answer is that "beneficiaries" should pay. However, the complexity of LMP markets, coupled with deregulation, has made this question a difficult one to answer. This paper addresses this issue by examining the impact of a hypothetical congestion-reduction project on generators and loads from two perspectives:
When the generators and loads are part of a vertically-integrated utility; and When the generators are independently owned in a deregulated environment.
The Flow of Money in an RTO
Figure 1 shows the flow of market money from those who pay for service to those who provide service. Excluded from the diagram are:
Payments to the transmission owners for network service; Monies collected for through-and-out service, which the RTO collects and distributes to the transmission owners; and Payments by the load to the RTO to cover the operational and administrative costs of the RTO.
No specific RTO is assumed in Figure 1. However, the model assumes that marginal losses are included in the LMP, as is the practice in the New York ISO and ISO-New England, and as is proposed in the Midwest ISO and PJM.
The basic LMP equation is represented as the sum of various price components:
LMP (at bus "i") =
LMP(at the reference bus) +
LMP(congestion at "i")+
LMP(marginal losses at "i")
This mathematical LMP framework will not be discussed here. The reader is referred to publicly available descriptions.6
A Congestion-Reduction Example
Assume a simple RTO system with four generators as the sources and five load buses as the sinks. Figure 2 shows the system for a one-hour period before a congestion-reduction project is implemented. For simplicity, assume that the Ancillary Service Revenue and Ancillary Payments are zero (i.e., ignore their impact). Figure 2 shows the generation and load, as well as LMPs at each bus for the one-hour period. By focusing on a one-hour period, the mechanics of the calculation of benefits are more easily demonstrated. For simplicity, this RTO has only one load zone. The term "Generator Variable Costs" includes fuel costs, variable operation and maintenance expenses, and emission allowance cost.
complete the economic picture for this one hour, the following will be calculated:
Marginal loss credits FTR revenues
Marginal loss credits represent the over-collection of monies for losses: they represent the difference between the payments from the load (excluding congestion) and the revenues paid to the generators (excluding congestion). Figure 3 shows the marginal loss credits for this hour. As a practical matter, these would not be settled hourly. Excluding congestion-related payments, loads paid $252.00 more to the RTO than the RTO paid to generators. This overpayment is returned to the load.
FTR revenues represent payments to FTR holders. FTR revenues represent the difference between congestion payments by the load and congestion revenue paid to the generators. The total FTR revenue that the RTO will collect is shown on Figure 4. Like marginal loss credits, these revenues belong to the load.7 Likewise, FTRs are not settled hourly as they are in this example.
One may now calculate the revenues and payments for generators and loads in this RTO. Figure 5 shows the tally. If the generators and loads in this example are part of a vertically-integrated utility, the net generator revenues of $928.25 in this example (= $5,838.25 - $4,910.00) are "owed" to the load. If these net generator revenues are subtracted from the net load payments of $5,838.25, the net cost to serve the load is equal to $4,910.00, or the sum of the generators' variable costs (the system's production costs). These computations are shown on Figure 5, lines 16-18. While one might expect this to be the case in a vertically-integrated utility, it is comforting to know that this approach arrives at a familiar result using LMP mathematics. In fact, one carefully examining the equations in Figure 1 would have predicted this result.
After a Congestion- Reduction Project
One may now examine the same one-hour period with one change: implementation of a project to reduce congestion. This project might be the addition of a phase-shifting transformer or a new or upgraded transmission line to add redundancy (new) or to increase its capacity (upgrade).8 While the loads are the same as before, the generation dispatch has changed, reducing costs. Although total losses would be slightly reduced (thereby reducing the generators' collective output), they are assumed to remain the same in this example. The results are shown on Figure 6, along with comparable tables showing the impact on marginal loss credits (Figure 7), FTR revenues (Figure 8), and RTO revenues and payments (Figure 9).9 As one might expect, the congestion-reduction project reduced costs: The zonal LMP decreased from $24.92 to $23.81/MWh and total production costs declined from $4, 910 to $4, 516, or $394. In a vertically integrated utility, this reduced production cost would measure the entire economic benefit of the congestion-reduction project. However, if generation is independently owned, their economic gains or losses they experience may not flow back to the customers. The change in net revenue for each generator will determine which generators benefit or lose from the congestion reduction project.
Winners and Losers
Figure 10 shows the project's benefits to the load and to each generator, and Figure 11 shows this data graphically. As noted previously, if this congestion-reduction project were implemented in a vertically integrated utility, the measure of benefits is the change in production costs, or $394 ($4, 910 to $4, 516). A vertically integrated utility would be expected to compare the revenue requirements of implementing the congestion-reduction project with the fuel (and purchased power) savings forecasted over some future period. However, in an RTO with deregulated generation, the benefit from the perspective of the load is only $193.08. In this simple example, Generators #1 and # 3 increased their net revenues (or profits before taxes) by $185 and $178.67, respectively, while Generator # 2 and # 4 lost $137.75 and $25, respectively.
Consider an RTO like the Midwest ISO. It serves 11 states, three of which (Illinois, Michigan, and Ohio) have deregulated. The remaining states have traditional vertically integrated utilities. The Midwest ISO is in the process of trying to define the proper "benefits" measures for economic transmission upgrades as well as an equitable means for allocating costs to customers from such upgrades. In the Midwest ISO as well as other RTOs, the resolution of the issue is still a work-in-progress.
This example in this paper raises policy issues that all stakeholders (loads, generators, and state regulators) should consider in the Midwest ISO, as well as in other RTOs where there is a mix of vertically integrated and deregulated utilities.10
1. The revenue requirements for new transmission facilities are currently recovered in the transmission rates charged to customers (i.e., the load in this example). If generators benefit from an economic upgrade, should they be assessed a charge that is proportional to their benefits? If so, how should such a charge be calculated and levied? What about generators who lose net revenues as a result of the upgrade? Should they be compensated?
2. If the answer to charging or crediting generators is "no" because some of the generators are deregulated, should the RTO benefit/cost criteria for implementing economic upgrades only measure the benefits to those loads that will pay the cost? Assume that a "load-only" benefit measure is adopted in an RTO because of the presence of deregulated generation.11 Since loads only receive a portion of the benefits, the resulting benefit/cost ratio will be lower in a deregulated model than in a vertically integrated regulatory environment. To illustrate, suppose that the cost of the upgrade in the example is $100, and that the RTO has adopted a minimum acceptable benefit/cost threshold of 2.5. With a "load-only" RTO test, the benefits are $193.08, resulting in a B/C ratio of 1.93. In the vertically integrated environment the benefits are $394, resulting in a B/C ratio is 3.94. The project would fail the RTO test and not be constructed. However, it would probably be built in a vertically integrated environment since the B/C ratio is much more favorable.
3. Given that the "benefits" from an economic project can vary among any subset of market participants, should any market participant be allowed to voluntarily self-fund (i.e., participant-fund) economic transmission projects that fail the RTOs economic criteria but that meet its own criteria? The answer should be "yes" since this approach would leave all market participants (loads and generators) with more ability to lower costs (loads) or improve profitability (generators) than in a centrally planned RTO with a minimum economic criterion. State regulators in vertically integrated regime should determine whether the RTO has left unfunded additional cost-effective economic transmission projects that its utilities should fund.
Participant funding will give stakeholders an additional method of funding economic transmission upgrades. Projects that meet a "load-only" benefits test can be planned and implemented by the RTO, with their cost recovered in zonal rates. However, with participant-funding, market participants can work with the RTO to plan additional upgrades that meet their own economic criteria. They can elect to participant-fund projects that are beneficial to them and thereby not impose the economic cost of the project on zonal rates.
- See ERCOT draft dated July 12, 2004.
- See 18 CFR, § 35.34 (j) (1)
- See 18 CFR, § 35.34 (j) (7).
- Lower prices are beneficial for loads, but higher prices benefit generators.
- Order No. 2003 (104 FERC 61,103), paragraph 28, discusses participant funding. The default "crediting with interest" approach is in Order 2003-A (106 FERC 61,220) in the Standard Large Generator Interconnection Agreement, Section 11.4. Under this approach, the transmission customer receives transmission service credits that amortize its initial cost of the "Network Upgrades" the transmission customer initially funded. The transmission customer receives interest on the unamortized balance, and any balance remaining after five years must be completely refunded.
- See New York ISO Technical Bulletin 062, "Locational Based Marginal Pricing - Meaning and Myths" dated Sept. 20, 2000.
- In RTOs where FTRs are directly allocated to loads, the load directly receives congestion payments. In RTOs that auction off the FTRs, the loads receive the auction revenues and the FTR holders receive congestion payments. Assuming that FTR auction revenues approximate actual FTR payments in total value, then the result, from the perspective of the load, is the same.
- Added redundancy reduces single contingency ("n-1") constraints that limit loading on facilities.
- Software such as NewEnergy's PROMOD IV® can be used to determine the forecasted impacts associated with an economic transmission upgrade.
- Although not yet a FERC-approved RTO, ISO New England is an example of another mixed region. While Vermont is the only state still vertically integrated, some public power entities do not offer retail choice.
- A "load-only" benefits test makes allocating transmission investment to zones straightforward since the costs can be allocated in proportion to the benefits in each zone.
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