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Several issues need to be addressed before municipals and co-ops participate significantly in regional transmission organizations.

On the last day of the Clinton administration, the U.S. Department of Agriculture issued a controversial regulation halving the maximum hole size allowed in Grade A Swiss Cheese. The Libertarian Party attacked the USDA as "Monterey Jack-booted thugs," but domestic cheesemakers argued that cheese with big holes crumbles during mechanical slicing. When it comes to regional transmission organizations (RTOs) and the Federal Energy Regulatory Commission's (FERC's) attempt to "slice and dice" transmission functions, holes may cause similar problems. So it's important to understand the impediments to RTO participation by consumer-owned utilities, be they governmental or cooperative.

Although FERC's Order 2000 anticipated and discussed some of these impediments, it focused on threshold legal issues like tax and mortgage requirements that limit the private use of consumer-owned facilities. Such threshold issues have to be addressed carefully during RTO formation, and we start with them. However, they generally have proved to be solvable where all relevant utilities, both consumer-owned and investor-owned, genuinely want solutions. Indeed, the Midwest RTO (MISO) and the four operating Independent System Operators (ISOs) in California, the Mid-Atlantic states, New England, and New York include as participants quite a few consumer-owned transmission-owning systems.

An even stronger example of consumer-owned participation is provided by the American Transmission Company (ATC), which owns transmission facilities in Wisconsin and adjacent portions of Michigan and Illinois. Wisconsin Public Power Inc., which had not previously owned transmission, supplied capital to ATC in exchange for transco shares, and other consumer-owned systems are undertaking similar investments. The fact that existing participation is widespread demonstrates that there are no universally applicable and insurmountable legal obstacles to consumer-owned participation. The more intractable problems involve the details of what RTOs do after they are formed, such as how they pay for the facilities they use and how they plan for new ones.

Tax and Formation Issues: Congress Needs To Act

Many municipal transmission facilities have been financed using tax-exempt debt that carries with it a statutory prohibition limiting the "private use" of the funded facilities. Placing municipally owned transmission facilities under the control of a private grid operator could run afoul of these limitations, placing municipal utilities in breach of their bond covenants and exposing investors to unanticipated tax liability. Temporary regulations issued by the Treasury Department in 1998 and 2001 have attempted to deal with this issue, but the solutions are only partial and short-term. Some municipal systems have been able to get private letter rulings; while these have been helpful, such a case-by-case approach does not provide a comprehensive solution. The American Public Power Association and the Edison Electric Institute have agreed on a legislative solution to the "private use" problem, but Congress has not acted. As efforts to resolve this issue drag on, in some parts of the country the uncertainties are slowing investments in needed transmission system improvements.

Cooperatives face similar issues. Cooperatives often are charged with serving rural communities by enabling statutes, their own charters, the federal Rural Utility Service regulations,1 and bond covenants. Placing transmission owned by co-ops under control of an RTO may risk running afoul of these restrictions. Moreover, a cooperative that obtains more than fifteen percent of its revenue from non-members risks losing its own tax exemption under Treasury regulations. Widespread state law prohibitions against municipal ownership of shares in for-profit corporations have raised concerns. The recent trend away from for-profit transcos and towards a non-profit or manager-only structure for the top regional transmission entity reduces these concerns. Moreover, the universally favored form for regional transmission entities has been the LLC (Limited Liability Company), for which state law is more accepting of municipal participation.

Congestion & Rate Design: Sorting Out the Inequities

Assuming that the threshold legal obstacles to joining an RTO and turning over control of transmission facilities have been overcome, municipal and cooperative entities still face issues of rate design and implementation that may affect them disproportionately and render RTO participation disadvantageous. These issues may include:

Some of these issues are closest to resolution for the California ISO, which is involved in pending litigation before the D.C. Circuit Court of Appeals. Indeed the examples discussed below are drawn from issues that arose with the California ISO. However, similar problems have arisen in other ISO/RTO contexts across the country, wherever there was a need to bring municipal or cooperative entities into a regional transmission entity. Moreover, municipal and cooperative entities have constructed their own high voltage transmission facilities often during the past two decades, with the rise of joint power agencies as vehicles to facilitate projects on this scale. As a result, their newer-vintage transmission was built when the costs of construction were higher and is far from fully depreciated-in contrast to the much older, often highly depreciated facilities owned by most investor-owned utilities (IOUs).

Consequently, in any region that uses or expects to use a region-wide rolled-in rate, mixing in newer, relatively more expensive municipal and cooperative facilities tends to raise the overall rate. This has given rise to claims of "cost shift," usually raised by IOUs and sometimes by state public service commissions (PSCs), especially if they regulate IOU rates but not municipal or cooperative rates. The IOUs and PSCs claim that this result somehow unfairly "shifts" municipal and/or cooperative costs to IOU customers.

In California, the claims of "cost shifts" resulted in an ISO proposal for a Transmission Access Charge, which capped the amount by which the rates of IOU customers could rise when municipal or cooperative transmission was added to the mix. This decision effectively left those costs with municipal and cooperative customers, who still had to pay a full share of the costs of the IOU facilities. Also, the charge required municipals and cooperatives to use their transmission revenues to pay down their Transmission Revenue Requirements (TRRs) in advance.

FERC rejected the "pay down" requirement restricting municipal and cooperative owners' use of their own transmission revenues, but otherwise accepted the filing and set the case for settlement negotiations, where it remains at press time.2 It is perhaps significant that the only municipal entity to contribute transmission to the ISO under that arrangement did not own enough to implicate the cost-shift caps.

There is, of course, no inherent reason why all customers of an RTO should not share equally in paying for all facilities, of whatever vintage that the RTO controls and uses to provide its services. This result is particularly appropriate when one considers the usual rate treatment of transmission facilities built today. Usually built by the IOUs, these brand new facilities are the most expensive of all. Yet most rate treatments, including that of the California ISO, roll the full costs of the newest vintage transmission facilities into rates immediately, without caps or concerns about "shifting" costs to non-IOU customers. The end result is to carve out different and discriminatory treatment for a particular vintage of facilities between one and twenty years old, sometimes only if they are owned by municipal or cooperative entities.

While the California ISO methodology may be an extreme example, to the extent that any RTO rate methodology draws lines between facilities based on vintage, cost, or ownership, owners of disfavored facilities will be more reluctant to participate in an RTO. Only full recognition of the total costs of all grid facilities, to be borne equally by all similarly situated customers, is likely to solve the "Swiss cheese" problem of the missing consumer-owned entities.

Even assuming that an RTO will include all TRRs in its rates, there remains the problem of how municipal and cooperative TRR is to be determined. There are several issues. First, since these entities have not historically been regulated by the FERC, they have never been required to keep their books in accord with FERC's Uniform System of Accounts (USOA). Often, these entities could not comply with a requirement that they submit TRR data in USOA format. While newer, large projects may conform to USOA requirements, older facilities may have been recorded on a wholly different basis, or may have been bundled as part of a generation project. Since municipalities do not pay taxes, there may have been no reason to track depreciation.

Return on Equity: Is the City of Vernon the Model?

There is also the question of a reasonable return. After all, surely municipals and cooperatives are entitled to a reasonable return on their investments. But since they do not issue stock, they cannot earn a return on equity as the IOUs do. A final issue is how the TRR of a non-FERC jurisdictional entity is to be reviewed. While IOUs and state public service commissions might like to see a full FERC section 205 filing and review, similar to what the IOUs must undergo, FERC has made it clear that such an undertaking for municipals and cooperatives simply is not within its statutory authority. The California ISO sought to deal with the question by having non-FERC jurisdictional entities file TRRs with it, for an ISO review. While FERC eventually rejected any TRR review panel that did not include a right of appeal to FERC,3 the current mechanism offers non-jurisdictional entities a choice between filing with the ISO and filing its proposed TRR directly with the FERC.

In the first case to come before FERC or the courts, the City of Vernon, California, filed its proposed TRR with the FERC when it sought to become a Participating Transmission Owner (PTO) with the California ISO. Vernon noted that it was a non-jurisdictional utility, but proposed to meet any standard the commission cared to apply.4 The filing did not contain the standard material and statements required of an IOU in a Section 205 filing. It is significant to note, as the commission did, that Vernon's transmission facilities consisted of entitlements in large projects built by others (so that Vernon merely was passing along costs set by others).

In addition, Vernon was in the atypical position of having financed its facilities out of current earnings, without borrowing by issuing municipal debt or other financial instruments. In order to calculate a reasonable return on the capital asset that it had purchased for cash, Vernon sought the same number used for return on equity by Southern California Edison, the IOU in which the Vernon system is embedded, as a proxy for a reasonable return on its investment. While the IOUs and the CPUC argued that Vernon's return should be based on the cost of debt, Vernon had no debt to consider.

FERC chose not to require a full section 205 review of Vernon's TRR, though it claimed the right to assure itself that the addition of the Vernon TRR would not render the ISO's jurisdictional rates unjust or unreasonable. In this respect, the assurance that Vernon made to FERC that it was merely passing along costs rather then developing them was important. Indeed, Vernon had entitlements in certain lines in which the IOUs also had entitlements. Given that the IOUs had been allowed to include the same costs from the same lines in their own, fully reviewed, FERC-jurisdictional TRRs, there was actually little reason to be concerned.5 However, FERC did order certain changes to Vernon's TRR, which Vernon voluntarily made. Given Vernon's non-jurisdictional status, FERC would have faced substantial legal obstacles to ordering Vernon to make the changes and join the ISO, but since the changes were acceptable to Vernon, the question did not arise.

FERC did approve Vernon's proposal to adopt Southern California Edison's return on equity as a proxy, provided that Vernon also used the capital structure and debt cost the utility had filed. The IOUs and the CPUC objected to both the use of the utility proxy return and the lack of full section 205 review. The IOUs appealed the case to the D.C. Circuit Court of Appeals, where it has been fully briefed and is set for argument in the fall.

Unintended Consequences: Locational Marginal Pricing vs. State Mandated Universal Rates

A further problem for small utilities of any sort can result from the unintended consequences of the commission's favored locational marginal pricing (LMP) methodology for managing transmission congestion. FERC favors LMP largely because it conveys a price signal regarding the cost of generation in particular locations, so that customers in high congestion areas pay more for transmission, and generators who site plants inside constraints receive higher payments. As FERC noted in its working paper:6

Market design flaws are visible in every regional electric market today under the existing tariff. These flaws are allowing operational problems such as the "socialization" or "uplift" of congestion management prices across all customers in a region, which obscures the potential for price signals to indicate where new generation, demand response, or transmission is needed.

However, most state retail rates are "universal;" all customers located in the same IOU's service territory face the same rates, with class variations for customers' character, size, voltage, and load shape, but not location. Consequently, IOUs socialize the locational transmission costs by spreading them evenly across their entire service territories, blunting the demand-side price signals that LMP is intended to provide.

More seriously for municipal and cooperative entities, the conflict between LMP and state-mandated universal rates causes LMP to have a disproportionate negative impact on small entities. For example, picture twin cities located in a transmission-constrained load pocket. City A is served by the local IOU, as are many areas outside the load pocket. The residents of city B take service from a municipal utility located entirely within the load pocket. Under the state universal rate policy, the increased congestion costs incurred by A's customers are spread to all of the IOU's rate base, in congested and non-congested areas alike. While everyone will pay a slightly higher rate, A's citizens will not see a large increase. In contrast, B's inhabitants have no choice but to absorb the entire increase due to congestion costs. Even if the municipality is subject to state regulation, as a local entity it has no other customers with whom to share the costs. B's customers thus see a comparatively large increase. Small utilities in congested areas have little incentive to participate in RTOs if the congestion management systems will disadvantage them this way.

FERC has an obligation to recognize the multi-jurisdictional context in which its policies play out and ensure that they work, without causing undue discrimination in those contexts. Notwithstanding the academic case for LMP, it makes little sense to impose LMP if its goals will not be achieved because state policies pull in the opposite direction. The commission will have to examine the true impacts of its policies in the jurisdictions where they will be applied, to make certain that hidden disadvantages do not undermine RTO participation.

Municipals & RTOs: How to Divvy Up Operational and Planning Issues?

Governmental utilities who are considering placing their transmission facilities under RTO ownership or control also face the fact that transmission is difficult to extract from municipal utilities' other functions. Functional disaggregation has proved complex throughout the industry. For example, ancillary "control area services" that provide the border between generation and transmission are still being defined, and the border between transmission and distribution is still being drawn through tests like the "seven factors" of Order 888. But the task is especially difficult for governmental utilities because their electric transmission assets are intertwined with so many other missions.

First, governmental facilities traditionally have served numerous non-electric functions, in addition to multiple electric functions. A single governmental right-of-way may contain towers supporting both transmission and distribution lines, optical fiber, cable, a water main, a sewer line, a gas line, roadway, and a bicycle path. RTOs create region-wide efficiencies by unifying the control over transmission maintenance timing, but governmental utilities who need to open a transmission line in order to maintain their distribution systems safely need assurance that the transmission efficiencies won't be purchased at the price of distribution inefficiencies. Governmental utilities understandably are reluctant to turn over the transmission component of such multi-function assets unless the transfer terms clearly protect their ability to perform their other functions.

Second, governmental utilities have special planning concerns not typically shared by private utilities. The shared right-of-way discussed above may include expansion space that was planned and retained with the idea that any one municipal function could use it if necessary, but which is not wide enough to accommodate expanding all of the shared uses. And governmental utilities are used to planning their transmission system development to serve public purposes that go beyond delivering electricity. They may want to encourage local economic development by routing their transmission lines near anticipated industrial sites, adopt unusually high aesthetic standards in sensitive locations, or provide exceptionally reliable service to sensitive loads. For example, the Reedy Creek Improvement District that serves Florida's Walt Disney World has sought assurances that the developing Florida RTO known as GridFlorida will include in its plans the underground and extra-reliable service that Disney demands. Other Florida municipals have similar concerns. Accordingly, the GridFlorida planning protocol provides that in addition to their rights to comment on regional plans, participating systems may insist that GridFlorida construct "enhanced facilities" that alter the regional plan, provided that they pay the differential cost, and that the enhancement is consistent with reliability.

Third, governmental utilities historically have not had to distinguish between controlling their facilities as public-spirited utilities, and regulating their facilities as holders of the police power; the policeman was the utility. Governmental utilities contemplating RTO participation need assurances that despite transferring operational control, they will retain their safety, zoning, and other police powers over transmission facilities located within their jurisdictions. It seems obvious that municipalities who operate an electric system and participate in an RTO should retain all of the police powers that are held by municipalities lacking publicly-owned electric systems, and some developing RTOs have made the retention explicit.

  1. 7 C.F.R. ยง 1710.104
  2. California Independent System Operator Corporation, 93 F.E.R.C. 61,104 (2000).
  3. Id.
  4. City of Vernon, California, 93 F.E.R.C. 61,103 (2000); Order Denying Rehearing, 94 F.E.R.C. 61,148; Order Accepting in Part and Denying in Part Compliance Filing, 94 F.E.R.C. 61,344; Order Accepting Compliance Filing as Modified, 96 F.E.R.C. 61,312 (2001); appeal pending; Pacific Gas & Elec. Co. and Southern California Edison Co. v. FERC, Nos. 01-1187 and 01-1190, D.C. Circuit.
  5. Indeed, any result other than full inclusion would appear discriminatory.
  6. Working Paper at 2.

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