Some thoughts on who should take the lead and how to set up financial incentives.
One of the most interesting questions that arises from federal restructuring of the electric grid, with regional transmission organizations (RTOs) and a standard market design (SMD), concerns the risk of building transmission in an RTO environment.
In the traditional setting, without RTOs, and with utilities controlling generation, transmission, and distribution, state regulators are involved in both the permitting and the rate making. If development costs should become stranded for a lack of permits before construction begins (NIMBY comes to mind), the utility can recover its sunk costs on showing a good-faith effort to obtain the necessary authorizations. And once construction begins, a tracking account (AFUDC-allowance for funds used during construction) will allow the utility to accrue a return on investment until such time as the asset qualifies as "used and useful" and is added to the rate base.
By contrast, investors lack a proven road map in the case of RTOs, where transmission is unbundled and the case lies within the jurisdiction of the Federal Energy Regulatory Commission (FERC). Utilities might well harbor concerns that transmission development costs could end up stranded.
Nevertheless, a careful look at the risk involved reveals a hint of policy taking shape in a variety of novel cases.
Construction Costs: Proof of Reasonableness
FERC has provided a strong signal about reasonable transmission construction costs, in a dispute over Sempra's $2 million expansion of California's import capacity. Approximately 900 MW were proposed, but the state of California objected on the basis that the costs incurred were not reasonable.
Of course, it is nothing new for regulators to conduct a review of reasonableness of costs at the time a new asset is placed in service. Yet the case is notable, as FERC dismissed the state's objections as unsupported, and signaled how it will weigh evidence in these types of cases. FERC's assessment of the costs and benefits is important, and provides much needed guidance.
In fact, FERC went so far as to encourage additional expansion, providing an advance opinion, that stated further tie expansion with Mexico was virtually a "no brainer."
Larger RTO-driven projects present far greater dollar disputes, and the added potential of state regulators pushing a single project's costs across service boundaries. If the project had involved $2 billion and more local jurisdictions, as it might under an RTO, continued uncertainty about the strictness of FERC's review standard could chill development. The Sempra case involved unfortunate political dynamics, but FERC's resolution of the dispute goes a long way to dispel investor concerns.1
Socializing the Costs: Proving System-wide Benefits
An RTO decision for an upgrade likely will affect the rate and risk structure of the transmission owner's investment. For example, the owner's risk may depend on the subjective determinations an RTO makes about whether the new investment has system-wide benefits.
If the RTO makes such a finding, it may be argued that the costs should be "rolled into" regional embedded costs, as are upgrades that enhance stability and must-run contracts with certain generators. In fact, with an RTO opinion on system-wide benefits, the risk of a stranded investment should be quite low. Any energized high-voltage line (unless it is radial) that is certified as offering system-wide benefits is probably always going to carry some trickle of power due to Kirchoff's law. Continued "usefulness" is more assured than it is for projects that lack system-wide benefits.
The more realistic source of risk of stranded investment comes before the line is energized.
In such a case, when transmission is planned in an RTO or ISO (independent system operator) context, the project may combine merchant and regulated participation, and cross jurisdictional lines, service territories, and state boundaries. FERC is just beginning to develop case law in this area, in a test case involving California's long-standing Path 15 bottleneck, and has taken the first tentative step in approving a three-party deal involving public and private interests.()
Revenue collection on behalf of joint developers likely will involve the California ISO. If, hypothetically, the project ultimately cannot be permitted, collection of development costs will be reviewed in an entirely new context. Even if the project is permitted, the ISO's revenue collection on behalf of a consortium presents novel return on equity (ROE) issues. Is the ISO to collect ROE for some (FERC regulated) members of the consortium, or all? For entities not FERC regulated, should the same ROE be used?
Initial Planning: RTO Monopoly or A Role for Owners?
Another wrinkle to be ironed out concerns transmission investment that is not decided by an RTO but by the transmission owner.
Many investments that improve stability fall short of a new major line or equipment with any regional importance. Transmission owners (rather than the RTO) likely might undertake such projects voluntarily.
Should FERC encourage such investments? How would their benefits be measured? Will such investments continue to take place, or will they simply have to wait until the RTO's planning staff and the organization are more mature, and more pressing facilities all have been built?
For example, an RTO finds an automated switch would improve ATC (available transmission capacity) and reduce congestion during enough hours to be cost effective. But what if its intended use of the switch would be inconsistent with generally accepted, lower industry standards? Can it order the investment and raise the standard, or must it live within the equipment tolerances as it inherited them? Should such investments be left to an owner's performance-based rates (PBR), flowed through by virtue of an RTO's PBR, or deferred in favor of regional-scale projects the RTO wants? What if these smaller projects fall into limbo between the disincentives for localized projects and the larger regionalized planning?
If an ITC (independent transmission company) operates under an RTO umbrella and chooses to sponsor its own grid expansion project, it might well agree to provide investment capital in exchange for receipt of all associated firm transmission rights (FTRs) or perhaps other types of congestion rights. In this case, the line begins to approximate the merchant nature of gas transmission lines, and the topic of stranded transmission post-construction becomes a more pronounced part of novel problems and possibilities.
Industry players are only now getting around to the question of how RTOs and transmission owners should interact on planning issues.
If an RTO always approves the recommended transmission projects of a member, and never requires planning for a project the owner did not recommend, does this suggest that the RTO is not truly independent? Some might argue that the RTO merely "rubber-stamps" whatever the owner supports and recommends. The opposing argument is that the owner has exceptionally good planners that are accurately anticipating the RTO's needs, and are in constant communication with it to develop well-coordinated planning. As such distinctions would be nearly impossible to judge without both day-to-day involvement, and assessment of people's state of mind, these nuances should not be permitted by regulatory policy to affect the risk assigned to the owner or the return on equity obtained through the RTO.
Performance-Based Rates: Who Takes the Lead?
In Order 2000,2 FERC encouraged RTOs to consider performance-based rates and other types of incentive-driven methods (such as an enhanced ROE) to fund current investment and future capacity expansion.
FERC has issued decisions to indicate that traditional utilities, i.e., vertically integrated transmission owners, cannot unilaterally propose PBR options for funding grid expansion. However, it remains an open question whether transmission owners will be able to carve out a scope of performance for PBR that is compatible with the scope of an RTO's performance. Hopefully, FERC's new rule on standardized market design will make it easier for ITCs and RTOs to reach agreement on this issue.
As FERC policy stands now, transmission owners (TOs) that participate in an RTO can determine their own transmission revenue requirements, and can file such data unilaterally as a rate, in the absence of an agreement with the RTO. But structural changes to transmission rates that include PBR elements must be proposed by the RTO itself.3 Otherwise, the RTO would not meet the criteria of administering a single, region-wide transmission rate and providing a cohesive tariff.
An RTO that "endorses" a filing made by all participating transmission owners, but does not "sponsor" the filing, may therefore find its tariff rejected without prejudice until the RTO becomes the applicant.4 At a minimum, this would require RTOs to provide witnesses to support the request.
ROE Incentives: Some Policy Guidance
Unlike PBRs, enhanced ROEs have few of these procedural requirements. Whether they are reasonable will be subject to the same sort of customary debate that for some time now has attended the traditional utility rate case. The case to watch is the Midwest ISO (MISO), the nation's first officially certified RTO.
FERC offered some important guidance on this question in a key preliminary ruling issued in January. In April, FERC Administrative Law Judge Carmen Cintron made additional findings on how to use the discounted cash flow (DCF) method to set ROE for RTOs.
Initially, MISO TOs had sought an ROE premium level of 11.5 percent to encourage utilities to join the regional grid, but FERC had rejected that request without prejudice because the MISO itself had not yet won certification as an RTO.5
Later, on Dec. 3, 2001, MISO sought to raise ROE to 13 percent for all ISO pricing zones other than American Transmission Co., the ITC formed under Wisconsin law. In addition, MISO sought to add 1 percent (100 basis points) to the proposed 13 percent baseline for RTO construction of new facilities. Finally, it asked for a 15-year depreciation rate for new facilities, plus a special incentive of 200 basis points (on top of the 13 plus 1 percent rate) for new transmission projects determined by MISO to require expediting.
MISO had supported its request with a DCF analysis of gas pipelines and other utilities, as well as independent DCF analysis of utilities' cost of capital by Moody's and Standard and Poor's. MISO had argued that a 13 percent return fell within a range of reasonableness between 9.28 and 15.48, and that an ROE slightly above the median was justified by the risk to owners of relinquishing control. MISO also argued that transmission was risky relative to gas pipelines, and that the higher return was needed to induce transmission owners to join the RTO.
In January, FERC granted authority to MISO to claim a 13 percent return, but suspended the rate and set the matter for hearing.6 But for our purposes the significance of the order lies with the policy guidance found elsewhere in the opinion.
In particular, FERC emphasized that 13 percent was not a premium ROE for new investment, but simply the higher end of the reasonable range for existing plant.7 This decision is therefore very important for utilities that are still working towards RTO approval.8
Were a higher ROE considered a PBR or premium, it may be required to "incent" the behavior of joining the RTO. Cases have found that an incentive may not be established if the conduct is already underway.9 Additionally, the PBR would have to establish an "additional" benefit, beyond compliance with Order 2000-an order that has not yet involved strictly enforced performance deadlines. Such proof would be fraught with debate over whether refusal to join an RTO was an option, and joining was a material "additional" benefit. The MISO order relieves utilities of any perceived timing conflict between establishing a PBR and joining an RTO. Higher ROEs should be available to a transmission owner without respect to when it joins.
The MISO decision clears up some confusion created by other rejected proposals. For example, in , FERC rejected a PBR mechanism outside the context of an RTO that met independence criteria.10 In that context, FERC stated "other incentives such as the increased ROE on existing plant … are not designed in a manner consistent with Order 2000 because incentives would flow to transmission owners who, " (emphasis added) The MISO decision makes it clear that increased ROEs are possible even though the non-profit MISO will be flowing those higher returns back to transmission owners who are passive and make no decisions regarding grid operations.
Does the RTO context change the nature of how to go about setting ROE? Perhaps it does.
For example, in the MISO order, FERC rejected for now each of the two incentive "adders" (100 and 200 basis points), along with the 15-year depreciation period, saying it wanted more stakeholder input. One might infer from this distinction that a stakeholder process is not employed when a utility transmission owner files a request for a changed ROE. However, it is customary for all RTO filings to be subject to a stakeholder process. FERC added that MISO "should also consider the role of performance-based rates within the context of its innovative rate proposal for new transmission facilities."
Because MISO is a non-profit and independent entity, it has the theoretical ability to minimize transmission costs by balancing its operating decisions and upgrade decisions through a PBR. Yet other failed PBR cases indicate the challenges involved in such "balancing."
In , FERC did not act on the region's PBR request, but ordered GridFlorida to explain in a future compliance filing why retention of 25 percent of revenue was an incentive likely to enhance throughput.11 (Throughput is a term usually applied to pipelines, which are not entirely analogous operationally.)
FERC stated that because Order 888 entitled customers to short-term and non-firm service, if it was available and at a tariff rate, GridFlorida must explain how its conduct would improve efficiency or maximize use, relative to historical levels.12 Similarly, Northeast Power Pool's pilot project for maintenance of a 345-kV line was rejected in part for failure to explain any additional benefit relative to prudent utility practice: minimizing total cost by working on the line while it was energized to reduce higher cost replacement power.13 The standards set for PBR are fairly high, and are perhaps more difficult during the RTO startup phase.
Given the large amount of change attending startup of RTOs, benchmarks for performance could be defined over the first one to two years of operations if mature and stable congestion management techniques are implemented. Many ISOs and RTOs have staged their functionality, and congestion solutions are sometimes deferred, phased, or planned to evolve based on empirical market demands. However, if locational marginal pricing is used from the outset to establish baselines for congestion, RTOs can begin to define PBR rates for performance that increases stability or reduces congestion, measured in dollar values.
Looking Ahead: An Upcoming Case
Interesting questions remain in the wake of these cases, and a pending filing by TransConnect, an ITC that would operate under the umbrella of RTO West, may help answer some of them.
The TransConnect filing of November 2001 seeks a 14.5 percent ROE under a partially capped five-year zonal rate. Benchmarks for reliability and throughput are to be published for a year before they are used to measure performance. New transmission costs may be directly assigned to a third party, who then obtains the Firm Transmission Rights associated with the project, or directly assigned to the ITC. If system benefits are determined by the RTO, the costs would be embedded, using accelerated depreciation and a basis point adder.14
Some have opposed the TransConnect proposal, arguing that FERC should defer any decision on ROE until it is able to rule simultaneously on both the ROE request and the entire "stage two" application for RTO West. They claim that initial protocols submitted by RTO West plans still leave things uncertain about how TransConnect and the RTO would share the responsibilities in grid planning. They say that FERC should not set ROE until such questions can be answered. Other opponents ask about non-wires solutions to grid expansion. They suggest that any planning protocol should also include a competitive bidding requirement that would give opportunities to others besides the ITC or the RTO to participate in planning and construction, with "first refusal" rights given to TransConnect to match a winning bid.
For its part, TransConnect has acknowledged that FERC precedent denies a right of first refusal to an RTO in a competitive bidding scenario, but claims that rule should not bar such rights to an ITC operating under the RTO umbrella. TransConnect adds that it has "provided a mechanism" to allow third-party players to make capital contributions to TransConnect and to participate in economic benefits generated by the ITC.15
At press time, the TransConnect Case was still pending, though a decision on RTO West, including protocols for grid planning and expansion, was expected sometime this summer.
- San Diego as & Elec. Co., FERC Docket No. EL02-54, Mar. 27, 2002, 98 FERC 61,332.
- 65 Fed. Reg. 809 (1/6/2000).
- PJM, Order Provisionally Granting RTO Status, FERC Docket No. RT01-2, July 12, 2001, 96 FERC 61,061.
- MISO, FERC Docket Nos. ER98-1438 et al., Opin. No. 453, Oct. 11, 2001, 97 FERC 61,033.
- MISO, FERC Docket No. ER01-485, Jan. 30, 2002, 98 FERC 61,064.
- With the termination of the 30-year government bond as an indicator of risk-free return, these "reasonable" ranges may be widening. The issue of determining additional utility risk relative to long term government issues may become moot, as rating agency data becomes more important.
- Note that ALJ Cintron issued an initial decision on Apr. 25. In that order, the judge OK'd an ROE of 12.38%, that being the midpoint of a range of reasonableness running from 8.79% to 15.96%. The judge relied on a nine-company proxy group suggested by the expert witnesses for both the FERC staff and MISO. But the judge rejected the DCF analyses offered by Moody's and Standard and Poor's. The judge also rejected the concept of using a proxy group composed of gas pipeline companies. See MISO, FERC Docket No. ER02-485, Apr. 25, 2002. 99 FERC 63,011.
- New England Power Pool, Order on Transmission Incentive Pilot, FERC Docket No. ER01-2922, Oct. 25, 2001, 97 FERC 61,093.
- FERC Docket No. RT01-77, Mar. 14, 2001, 94 FERC 61,271.
- GridFlorida, Order Provisionally Granting RTO Status, FERC Docket No. RT01-67, Mar. 28, 2001, 94 FERC 61,363.
- It is generally assumed that utilization levels of transmission before and after an RTO are likely to vary, with higher levels of use following formation. If so, the historical level is itself relatively generous as a PBR benchmark, until one figures in RTO fees and upward changes in total transmission charges. In instances where through and out rates may increase up to 50% to offset lost pancaking revenue, it remains to be seen whether and how much this rate impacts usage.
- FERC Docket No. ER02-323, filed Nov. 13, 2001.
- TransConnect, Applicants' Motion for Leave to File Answer and Answer to Protests and Comments, FERC Docket No. ER02-323, filed Jan. 11, 2002.
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Public-private upgrade breaks new ground on funding, need, and oversight.
On June 12 the Federal Energy Regulatory Commission (FERC) OK'd a three-party deal for upgrading California's notorious "Path 15" transmission bottleneck.
But the story was not yet over, as the state public utilities commission (PUC) was still arguing that the deal should wait until it could finish its own study on whether the project was cost effective.
In open session at the FERC meeting, chairman Pat Wood acknowledged that the state commission "has a role to play in permitting this facility," but others were not so sure.
The $306 million deal calls for merchant transmission developer Trans-Elect to supply most of the funds, with PG&E upgrading existing facilities (including substations and low-voltage facilities) and the Western Area Power Administration (WAPA) adding new construction and taking ownership of the transmission line and associated land. The upgrades to the already existing 84-mile stretch of transmission include a new 500-kV transmission line that will increase north-south transmission capacity from 3,900 MW to 5,400 MW. The expected completion date is in the fall of 2004.
Commissioner William Massey queried FERC staff about the approved target 50/50 capital structure for Trans-Elect for the first 36 months of the project, asking if it was "a good idea."
Staff replied that Trans-Elect was in a position to raise most of the funding of the project, so the capital structure was a predicate for obtaining financing.
Speaking at the FERC's June 12 meeting, chairman Pat Wood said he was "encouraged" by the "creative approach" of the three very different partners.
"I do think the need for this line has been made and proven in more different forms than just about any other transmission project in U.S. history," he added.
FUNDING RATIOS. Trans-Elect would raise $250 million in equity and debt to fund the construction. In return, the parties would receive entitlements to transmission rights in the following ratios: WAPA-10 percent; PG&E-18 percent; and Trans-Elect-72 percent.
And therein lies a key bone of contention.
In briefs filed earlier, the PUC had argued that WAPA's 10 percent share of project entitlements was unreasonable in comparison to its funding contribution. The PUC calculated that Trans-Elect (and PG&E) would each contribute about $30 million in construction and operation funding for each 10 percent share of project rights, but that WAPA would get a 10 percent share for only $1.3 million in contributed funding.
PRIVATE MONEY. In briefs filed earlier, PG&E and WAPA had argued that the introduction of private capital from Trans-Elect should cause no legal problems.
In a separate brief, WAPA attorney Koji Kawamura had noted that federal Reclamation Law and the 1985 Energy and Water Development Appropriations Act allowed for funding contributions from private sources for transmission grid upgrades. He explained that the laws treat such private capital as if appropriated for the purpose by Congress, with full discretion to federal agencies on how to use those private funds. (The 1985 act authorized WAPA to construct the California-Oregon Transmission Project, or COTP.)
"Under the COTP legislation and Reclamation Laws, Trans-Elect may contribute money for the construction of a federal project … [and] Western may use the money advanced by Trans-Elect as if Congress had appropriated such funds."
Kawamura argued that the CPUC cannot question WAPA's discretion in ironing out a project agreement.
"Western's minimum share [to project entitlements] is a decision that is reserved for Western as a matter of law."
STATE OVERSIGHT. In a brief filed June 5, PG&E Attorney Mike Patrizio argued that the project should fall entirely under CAISO and FERC control. He pointed out that California A.B. 1890 granted full responsibility to CAISO for grid expansion policy, and that CAISO tariffs dictate that economic need for a project need can be shown without a finding from the PUC.
As Patrizio wrote, the legislature "specifically transferred responsibility for short- and long-term reliability away from … regulatory bodies to the [CAISO]."
He added that under CAISO tariff §220.127.116.11.2, it is "sufficient to demonstrate need," if a project sponsor commits to pay the full cost of construction and operation of a transmission addition or upgrade, and demonstrates the financial capacity to do so.
"By its clear terms," he concludes, "the ISO tariff outlines the procedures and standards by which transmission projects are determined to be needed.
"Nowhere does the tariff provide for PUC determination of need for a transmission upgrade."
Source: FERC Docket No. ER02-1672, pleadings filed June 5, 2002.
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