RTOs--to join or not to join? CRN research zeros in on RTO costs, benefits and co-op experiences.

The march of regional transmission organizations (RTOs) across the country is placing big decisions with far-reaching implications before G&T cooperatives. Are RTOs--the traffic cops for the grid useful and suitable for coops? Some co-ops have already joined RTOs and others are looking into membership. But reports from the field have indicated that while there are benefits, there are also problems with RTOs and hidden costs for many co-op members.

NRECA's Cooperative Research Network (CRN) commissioned a research project to survey co-op executives on their experiences with RTOs and to identify key organizational, technical, financial and legal issues that co-ops must be aware of as they evaluate,joining an RTO. To gather the most relevant information possible, CRN interviewed 17 co-ops, mostly G&Ts, about their experiences with RTOs. These interviews provide important insights into the decision-making process required for determining the merits and potential pitfalls of RTO membership. The full results of the CRN research have been made available to all NRECA member co-ops through cooperative.com and via CD-ROM that will be mailed to all systems in January 2006.

The process of determining whether to join an RTO is very specific to the RTO being considered and the unique situation of the cooperative. Each RTO has its own set of policies and characteristics, even if they operate in similar electricity markets. What is right for one co-op is not necessarily the right course of action for another co-op.

A cooperative that finds itself in the situation of joining an RTO or participating in the development of an RTO (or RTO-like organization) will need to undertake a through examination of several factors. This article attempts to provide an overview of the key factors that a co-op should consider when weighing the decision to join an RTO.

RTOs Are Evolving Organizations

The FERC initially created RTOs by encouraging utilities to voluntarily form regional entities to help administer power supply transactions in the newly evolving regional power markets. The goal was to make those transactions more efficient, help ensure reliability, and remove any remaining discrimination in the provision of transmission services. An RTO controls the operation and use of the transmission system instead of the local transmission owners, and it sets the terms and conditions for use of the transmission system in the region. The RTO is also responsible for regional planning for new transmission and for allocating the costs associated with new transmission. Figure 1 identifies the existing and currently proposed Regional Transmission Organizations.

One of the fundamental underlying characteristics of RTOs is that they are not static organizations. RTOs are very dynamic, with rules and procedures continually changing. For example, during the preparation of the CRN report, the Federal Energy Regulatory Commission (FERC) issued rulings that delayed implementation of a revised capacity market in New England and rejected the Southwest Power Pool's (SPP) Energy Imbalance Service market proposal, and the Pennsylvania--New Jersey--Maryland Interconnection (PJM) filed a new capacity market proposal. In other regions, two RTOs--the Electric Reliability Council of Texas (ERCOT) (which is not FERC regulated) and the California Independent System Operator (CAISO)--are in the process of totally changing their market designs. Also, subsequent to the preparation of the report, RTO efforts in the Pacific Northwest, Grid West, have collapsed yet again.

Most co-ops east of the Rockies and north of the Tennessee Valley are affected one way or another by an RTO (Figure 2). Each RTO has its own set of characteristics (Figure 3), even if" they are operating similar electricity markets.

[FIGURE 2 OMITTED]

RTO Costs Are Significant

The costs of establishing and operating an RTO is a major issue that is receiving increasing visibility and attention at FERC. Start-up costs, annual operating costs, and per-unit operating costs for some of the existing RTOs and projected for Grid West for their existing market designs are highlighted in Figure 4.

Power supply is a major expense for co-ops, and transmission is becoming a significantly larger part of power supply. It is the duty of every co-op director, manager and senior cooperative staff person to understand as much as possible about what drives those costs so that they can make informed decisions about transmission and RTO membership and be able to communicate with members about the results of those decisions.

Transmission Access, Pricing, and Transmission Rights

Prior to changes in the regulation of wholesale power markets and the establishment of RTOs, the seller of bulk power often had to pay additional transmission charges wherever the contract path for the energy passed corporate boundaries onto the lines of another utility. This pile-up of charges is called "pancaking". RTOs provide market participants with one-stop shopping for transmission access to broad regions without being required to pay pancaked transmission rates. While perceived as a benefit, there are circumstances unique to some cooperatives that may cause concern. For example, cooperatives owning transmission facilities may have concerns about whether joining an RTO will make them FERC-jurisdictional for their transmission revenue requirements and whether they will lose transmission revenues previously received for providing wheeling services.

Transmission access and pricing issues are complex and evolving. Due to the potentially considerable financial impact upon their systems, it is important that the cooperative board and senior management are knowledgable of some key concepts and terminology. Most RTOs use, at least initially, "license plate" pricing under which each load-serving entity (LSE) pays a rate that is derived from the costs of the transmission facilities of the transmission owner (TO) to which the LSE is connected--unless they qualify as a TO in their own right, in which case they pay their own tariff rate. While most RTOs initially begin using license plate rates, some--such as ISO-WE--have moved to a "postage stamp" rate under which all LSEs pay the same rate for use of the higher-voltage transmission system. Even those RTOs with postage stamp pricing still use license-plate rates for the lower voltage transmission. Each cooperative must analyze its own situation and the transmission rates it would have to pay for access to the RTO in its region.

In addition to transmission access and pricing, another major issue is that of transmission rights. These are the financial transmission rights (FTRs) and/or auction revenue rights (ARRs) that are used in the locational marginal price (LMP) markets adopted by most operating RTOs (ISO-WE, NYISO, PJM, and MISO) and proposed in other operating RTOs (CAISO and ERCOT). (Refer to the glossary at the end of this article for definitions of these terms.) A cooperative that has existing transmission rights should determine how such rights will be honored in the specific RTO with which it would be associated. The cooperative will need to get answers to several questions for its specific situation and RTO:

* Will the cooperative be allowed to keep its existing rights--such as grandfathered agreements--or will the cooperative have to convert them to new FTRs or ARRs?

* If allowed to keep its existing rights, how will they be administered?

* If existing rights are converted, what is the conversion process?

* How will any extension or rollover rights associated with the existing rights be treated?

* Are the FTRs fully funded--that is, will the FTR holder always receive full payment or will payments be reduced when there is a shortfall in congestion rents collected by the RTO?

The cooperative will also need to determine how it will gain access to new transmission rights in the future. Again, several questions arise that the cooperative will need to address in light of its specific situation and RTO:

* Are FTRs allocated or auctioned?

* If FTRs are auctioned, how are the ARRs allocated?

* Is there any recognition in the allocation process for FTRs or ARRs of historical usage patterns?

* Can ARRs be converted to the same FTRs--that is, same source and sink points without going through the FTR auction process?

* Are long-term transmission rights available? (Currently none of the RTOs operating LMP markets offer long-term rights, and FERC is reviewing this situation.)

* How are incremental rights created by transmission upgrades determined and allocated?

The analysis required is technical and detailed, but is critical to the decision-making process: to join or not to join? The CRN sponsored interviews with cooperatives found that, in general, those that own a significant amount of transmission assets and that derive significant wheeling revenues to the benefit of their members were less likely to find any benefits in joining an RTO. The key issue here is that, typically, joining an RTO requires that transmission assets be pooled and a single network service tariff applies. Transactions within the RTO footprint are not charged any additional point-to-point service charges for deliveries within the RTO footprint. This "de-pancaking'" of transmission rates may ultimately prove to be beneficial to buyers of transmission services, but transmission service providers often must forego significant wheeling revenues that, in the case of electric cooperatives, accrue to the benefit of their members. Thus, customers of electric cooperatives with significant transmission assets could ultimately see their rates increase as a result of loss of these wheeling revenues. The issue for such co-ops is whether the potential savings in purchased transmission services offsets the loss of wheeling revenues.

Access to Markets

RTOs, particularly those operating day-ahead energy markets, provide one-stop access to energy to cover short-term needs or to sell short-term excesses. (Day-ahead markets take offers to sell and bids to buy on the day before the trading day and determine the optimum sales and purchases for each hour of the trading day, which sales and purchases become financially binding.) This can allow the cooperative to adjust its power supply mix without the administrative burden of finding an entity with which to sign a bilateral contract, arranging any necessary transmission, and incurring additional transmission charges.

G&T cooperatives that own only a very small portion of transmission assets and that are primarily made up of generation assets are more likely to see benefits to being an RTO member. Greater access to markets for their generation assets, reduced scheduling costs, and de-pancaked transmission rates were the key reasons for the benefit.

Cooperative Administrative Burdens

Joining an RTO will impose certain administrative burdens on the cooperative. Some of these are in addition to existing administrative burdens and some will replace existing administrative responsibilities. Several administrative issues that the cooperative will need to analyze for its specific situation and RTO include:

* Application and membership fees; these are usually relatively small, but could be a burden for very small cooperatives.

* The cost and burden of meeting RTO credit requirements.

* The costs and burden of meeting the data exchange requirements of the RTO and then analyzing the accuracy of all data, including billing data.

* Cooperatives that operate control areas and schedule and dispatch their own generation already are incurring costs for scheduling and dispatching that generation. If they join an RTO, the RTO will take over some scheduling and dispatch responsibilities for the generation, so a cost comparison must be done.

* To the extent that the RTO does weekly billing, probably only for the energy market, there is the cost and burden of having the staff in place or hiring another entity to handle the weekly invoices and money transfers.

* The costs and implementation of RTO-imposed hardware and software requirements. To the extent that the cooperative currently operates a control area and can turn some of those operating responsibilities over to the RTO, there can be a savings.

* The cost of attending RTO meetings, monitoring changes filed with FERC, and intervening, when necessary, in FERC proceedings.

The majority of the cooperatives interviewed stated that an additional three to four full-time equivalents (FTEs) were hired to support all of the stakeholder committee activities and other administrative burdens. This burden was viewed as significant. Additionally, the majority of the cooperatives interviewed expressed concern that the current governance structures in the existing RTOs--consisting of independent boards with stakeholder advisory committees give too much power to the RTO in decision making. Most independent boards generally favor the RTO's view if that view is in contrast with the stakeholder views. The independent board members do not have any financial interest in the RTO and, therefore, the impacts of their decisions are only felt by the market participants, not by the board members.

Sharing Additional Costs

All RTOs have costs that cannot be directly allocated to those causing the costs to be incurred or that are being socialized across all market participants for various reasons. These "uplift" costs can be caused by a variety of RTO actions and the cooperative will need to analyze its exposure to such costs for its specific situation and Examples of these uplift costs may include:

* Reliability must-run and related out-of-merit costs incurred to preserve reliability. In some RTOs, these costs are allocated to the sub-region experiencing the reliability problem and in other RTOs such costs are socialized across the entire RTO.

* Intra-settlement period costs not reflected in LMPs--that is, payments to high-cost generators that operate for only a portion of a billing hour at a cost higher than the weighted average LMP for the whole hour.

* Possible allocations of shortfalls in FTR revenue adequacy.

* RTO operating costs not allocated in another manner.

Legal Implications of Membership

The prospect of joining, or being thrust into, an RTO, ISO or similar scheme separating control of certain aspects of transmission from ownership of the facilities poses various potential legal issues for cooperatives, whether they own transmission that is being placed under the control of the RTO or not. What follows is a high level summary of some of those issues and not a legal opinion. Each cooperative should conduct its own legal review of issues unique to its situation.

Limitations Imposed by State Law

If the cooperative is considering joining an RTO, a threshold question is whether the enabling law under which the cooperative is organized imposes limitations or restrictions. If joining involves some form of corporate affiliation--such as by purchasing an equity interest in the entity--it is important to determine whether such affiliation is permitted by state law. For instance, assuming that the RTO is not itself organized as a cooperative, does the state law providing for organization of cooperatives permit such an affiliation? If the cooperative is not prohibited from joining, is approval by some state authority required? Does joining trigger new or different regulation of the cooperative by the state?

If joining involves transferring some measure of control of the cooperative's transmission facilities to the RTO, it is important to determine whether state law permits transfer to an entity organized in whatever corporate form the RTO takes. If transfer is permitted, what approvals, if any, are required by state law? And how is state-mandated regulation of the cooperative affected by the transfer, if at all? If these issues raise problems, can they be solved effectively by some form of reorganization such as by spinning off the transmission assets? There also may be significant tax issues. Will the cooperative lose existing state tax exemptions or become subject to new forms of state taxes?

Corporate Governance and Contract Issues

The cooperative's articles of incorporation and bylaws may raise similar legal issues. Do those documents permit the cooperative to join the RTO? If so, are there any special requirements for such action? If those documents do not appear to permit the cooperative to join, it may be possible that they can be amended, unless the strictures against joining are imported from the enabling state law as discussed above.

Potential impacts on the cooperative's contracts with members and non-members raise issues that are, as a practical matter, as fundamental as those related to enabling legislation and governance documents. A number of questions may arise. Do the RTO's legal documents for example, its operating agreement and transmission owners' agreements--and the FERC orders approving the entity, permit grandfathering of existing agreements? Which agreements? Only bundled requirements agreements? Only agreements with a certain minimum term? Are member agreements treated differently from third-party agreements? Is there a limited period during which grandfathering is permitted? Are there likely eventualities that would result in ineligibility for grandfathering? What is the process for obtaining grandfathered treatment? What is the process for terminating grandfathered status? What happens if and when grandfathered treatment is terminated?

Assuming that the cooperative's contracts are eligible for grandfathering, what are the relative roles and cost responsibilities of G&T cooperatives and their member cooperatives under grandfathered contracts? That is, who is the RTO's transmission customer? Who pays the RTO for the various services it provides? Is amendment of existing contracts required to provide the desired answers to these questions, and if, so would amendment affect the grandfathered status of the agreements?

Joining an RTO is likely to affect contracts the cooperative may have with other utilities and suppliers at least equally significantly. If a transmission dependent utility (TDU) cooperative's transmission provider joins an RTO, the TDU's power supply arrangements (as well as its transmission arrangements) may have to be changed significantly. This may occur even if the contracts regarding those arrangements are technically grand fathered. Transmission agreements may proliferate. That is, the cooperative may have to enter into new service and operating agreements with the RTO, and, at the same time, replace the old service and operating agreements with transmission owners with new "wires-to-wires" agreements with the transmission owners. Similarly, a transmission-owning cooperative with delivery obligations to non-members likely will have to revisit at least those obligations, whether the agreements are nominally grandfathered or not.

Joint ownership, joint operation, and joint-dispatch arrangements for both generation and transmission are especially likely to be affected and require significant change to accommodate transfer of transmission operations to an RTO. This would be especially so if some of the owners join and others do not. In any event, one party's joining an RTO will have the effect of creating a virtual third party to such arrangements.

Tax Issues

Joining an RTO is likely to raise a number of tax issues. Both transmission-owning cooperatives and transmission-dependent utilities that hold financially tradable transmission rights are likely to receive significantly increased amounts of revenue from nonmember sources. Again, a number of questions must be raised and addressed: Will non-member income generated by participation jeopardize the cooperative's federal income tax status? Will a change in revenue stream affect the income tax status of a counter party to power supply arrangements--such as a state or municipal power agency? What if status rests on a unique IRS letter ruling that is based on facts that will change as a result of RTO membership? How will tax accounting be affected?

Rate and Member Impact Issues

Participation in an RTO as a transmission owner is likely to involve new kinds of cost. Accordingly, a cooperative should consider what changes, if any, to existing wholesale rates would be required to assure recovery of all costs associated with participation. What approvals would be required for such rate changes? There may be a number of parties involved in that process: members, RUS, other lenders, state regulatory authorities, the FERC.

Ceding the role of transmission provider to an RTO could, but need not necessarily, require changes to other terms and conditions of a G&T cooperative's contracts with its members. This may be avoided fully or in part by the G&T becoming the "transmission customer" of the RTO. Even in such a case, however, some member contracts may be structured such that changes, or even supplemental agreements, will be needed to reflect the new, three-cornered transmission arrangement. For instance, what is the extent of the service offered by the RTO? Will supplemental bilateral agreements or tariffs be required for sub-transmission service at relatively low voltage, or for service using distribution facilities?

The difficulty of considering changes to rate and non-rate terms and conditions of transmission-owning cooperatives' contracts may increase dramatically if the RTO operates, or is likely to operate, day two markets--that is, day-ahead energy markets. There are complex technical and business issues raised by the transformation of transmission service from the "wires plus ancillary services" service, familiar under the contract path regime, into a new, locationally sensitive energy service that must be addressed. Examination of most of these issues will raise corollary questions with regard to a transmission-owning cooperative's contracts, both with members and non-members. Examples of these issues include allocation of locational congestion costs and revenues, losses, charges associated with voltage support, and the like. A particularly problematic issue for G&Ts may be potential member discord if locational prices deviate materially from one member's delivery point to another's. G&Ts that have priced sales on system average prices may encounter pressure from members in lower cost locations to bring locational marginal pricing to the member level.

Additional State Law Issues

Joining an RTO will likely raise a number of additional state law issues. For instance, does the state's public utility regulatory law provide for different regulation of facilities--such as distribution facilities or services provided using such facilities that are transferred to the control of an RTO? If the state has a retail territorial allocation law, and if control of transmission facilities confers service rights under that law, does transfer of control of such facilities affect service rights? Does the state's public utility regulatory law regulate the affiliate relationship differently from the way it regulates the cooperative's existing activities, if at all? Does control of cooperative facilities within the state by a non-cooperative affect state or local taxability of either those assets or revenue derived from use of those assets?

Implications for Financing

A cooperative that elects to join an RTO is likely to face a number of legal issues with respect to its financing. For example, assuming that financing documents--mortgages, indentures, guarantees, leveraged leases--permit transfer of control of such assets, does the specific nature of the transfer of control require endorsements or other approvals from mortgagees, trustees, guarantors, lessors? Do RUS's regulations or its loan documents require consents?

Until passage of the Energy Policy Act of 2005, it could be said that joining an RTO would likely subject the revenue requirement of a RUS-financed cooperative to more intrusive regulation by the FERC--under the City of Vernon case--than would otherwise be the case. In its City of Vernon orders, the commission addressed a situation where a non-jurisdictional utility, the City of Vernon, turned its system over to the California Independent System Operator (CAISO) to operate. The CAISO then sought to incorporate the Transmission Revenue Requirements (TRR) into the rate that the CAISO charges its transmission customers for transmission services. Under those circumstances, the commission may review the justness and reasonableness of that rate component for the non-jurisdictional entity (City of Vernon) as part of the rate charged by a jurisdictional, public utility (the CAISO). Under the new legislation, however, it appears that transmission rates of RUS-financed cooperatives may be subject to significantly enhanced regulation by FERC, whether they join RTOs or not.

There is at least one non-legal issue that will affect how the cooperative fares legally in an RTO environment: transaction costs. A cooperative facing the prospect of operating under an RTO regime should anticipate a significant increase in resources to address the proliferation of legal issues associated with transition to membership and ongoing participation in RTO activities.

Obtaining Exit Rights

Assuming that questions about the permissibility of participation allow a co-op to participate in an RTO, a transmission-owning cooperative would, nevertheless, wish to preserve at the threshold the right to exit the RTO in the event that participation becomes prohibitively costly or otherwise infeasible on account of changed circumstances. Does the RTO membership agreement contain adequate "regulatory outs" to enable response to state regulatory authority action; Rural Utilities Services (RUS) action; action of taxing authorities? Does the RTO impose exit fees that can create large contingent liabilities?

Do Co-ops Have a Choice?

One aspect of the debate about RTO membership that became clear during the CRN research is that unless the G & T cooperative operates a NERC-certified control area or is willing to invest the time and resources to become a NERC-certified control area, it may not have much choice but to join an RTO if one forms in its region. Cooperatives that operate NERC-certified control areas can operate independently from the RTO and simply pay the RTO for any necessary transmission wheeling or other services. Those cooperatives, depending on their load connections, may still be exposed to some other RTO costs--such as reactive power charges for remote load connected to the facilities of a transmission owner (TO) that does belong to the RTO. Cooperatives that cannot operate a NERC-certified control area will probably have to either join the RTO or negotiate an arrangement with a TO to provide control area services--within or outside the RTO--much the same as they would have done before the RTO formation.

Conclusion

Many co-ops that are members of an RTO felt that they had little choice but to join. Even when that is the case, the co-op may still want to undertake an exhaustive analysis of the costs and benefits of RTO membership. Participation in an RTO imposes many costs upon the cooperative and requires significant additional staff work. As such, it is prudent to do a thorough analysis of the net benefits of membership. Whether a co-op will realize any benefit in joining an RTO is dependent upon a number of factors and there is no one size-fits-all answer. Each co-op will have to undertake an extensive exploration of the financial, legal and administrative questions unique to their particular RTO. Co-ops can and should learn from each other to make co-op investigations in this area as productive as possible. One thing is known: Being a member of or even adjacent to an RTO will change business as usual for co-ops.

Transmission: Tough Terms Defined

Auction Revenue Rights (ARR): A financial instrument that entitles the owner to receive revenues from the auction of Financial Transmission Rights.

Financial Transmission Rights (FTR): A financial instrument that entitles the owner to receive a share of the congestion rents that arise when the grid is congested and differences in prices at different locations that result from the redispatch of power to relieve that congestion. While FTRs can be used to hedge the holder's exposure to congestion charges, it is not necessary that the holder actually experience such congestion charges. FTRs do not hedge transmission losses, which can also cause prices to be different at different locations even in the absence of congestion.

License Plate Rates: Under this rate design, transmission owners whose systems move power long distances no longer receive separate revenue from those wheeling transactions. They only receive revenue from customers that actually take deliver from their grid, including wheeling out transactions, and at a rate calculated to be sufficient to cover the transmission owner's transmission revenue requirements. Locational Marginal Pricing (LMP): A method of assigning a price to energy at specific locations on the transmission grid, taking into account the ability of the grid to carry that energy and any losses incurred. As the name implies, the price is based on the marginal cost to deliver the next increment of energy at a specific location.

Pancaked Rates: As energy crosses from one transmission system to another, access charges may be "stacked" on top of each other, increasing the price of transporting the energy from remote locations across the systems of multiple transmission owners.

Postage Stamp Rates: Under this rate design, the RTO charges the same transmission rate to all users of the transmission systems within its region and the collected transmission fees are divided among the transmission owners in proportion to their individual revenue requirements.

Uplift Costs: Costs of operating the RTO that are not directly allocated to specific transmission transactions or activities but are shared by certain members of the RTO on a regional or RTO-wide basis.

William H. Dunn, Jr., Managing Director, Gestalt, LLC 

Bill Dunn has over 34 years of experience working with electric utility organizations. He specializes in electricity market design and implementation, ancillary services, utility and power pool/market operations, inter-utility coordination, contractual power supply arrangements, and transmission access and pricing. Mr. Dunn has held senior positions in utilities and on power pool/market committees. In addition, his experience in electric utility markets includes electric utility market restructuring in the U.S. and across the globe. He frequently speaks at senior electric utility industry forums and provides papers for journals.

Figure 1

Regional Transmission Organizations
Pennsylvania--New Jersey--Maryland (PJM)
Interconnection
ISO New England (ISO-NE)
New York ISO (NYISO)
Midwest ISO (MISO)
Southwest Power Pool (SPP)
Electric Reliability Council of Texas (ERCOT)
California ISO (CAISO)
WestConnect (Desert southwest)
Grid West (Pacific northwest)
Southeast US

Figure 3 RTO Characteristics

Some of the basic characteristics of the existing RTOs are
summarized in the table below.

                 PJM     NYISO    ISO-NE     MISO

States *                                     15 +
(number)       13 +DC      1        6      Manitoba

Employees
(number)         600      400      400       600

Transmission
(miles)        56,000    11,000   8,000    100,000

Generation
(MW)           164,000   38,000   31,000   132,000

Peak Load
(MW)           131,000   32,000   27,000   112,000

Energy Load
(Annual TWh)     700      160      135        ??

                 SPP     ERGOT    CAISO

States *
(number)          6        1        1

Employees
(number)         130      500      500

Transmission
(miles)        52,000    37,000   26,000

Generation
(MW)           45,000    77,000   55,000

Peak Load
(MW)           41,000    60,000   46,000

Energy Load
(Annual TWh)     192      290      230

* Some states are served by more than one RTO.

Figure 4

RTO Start-Up, Annual Operating, and Per-Unit Costs

                              Annual
               Start-up      Operating    Per-unit
                 Cost          Cost         Cost
RTO           (million $)   (million $)   ($/MWh)

CAISO             240           225         0.92
ERGOT             137           120         0.42
Grid West *       133           66          0.29
IESO **           198           110         0.72
ISO-NE            55            120         0.91
MISO              157           255         0.40
NYISO             82            120         0.73
PJM               140           265         0.40

Data derived from "Grid West Cost Discussion" document, dated
July 20, 2005. These data may differ slightly from data derived
from other sources.

* Projected

** Independent Electric System Operator (Ontario, Canada)