Merchant Transmission Projects: Opportunity or Fantasy?

By Bob Shapiro and Adam Wenner

There is little incentive at the moment to build new power plants in the United States because of the amount of spare generating capacity. Wholesale electricity prices have fallen to levels that make it  impossible in many cases to finance additional projects. At the same time, in some parts of the country, transmission bottlenecks prevent sellers of low-cost power from delivering their product to areas where power prices are higher. This has led many companies to look at the possibility of buying sections of the existing grid or of constructing new transmission lines. Chadbourne hosted a workshop in Houston in March about the regulatory thicket through which anyone wanting to get into the merchant transmission business must navigate, the ownership structures that independent transmission companies are using, and the issues they face in doing business. The following are excerpts from that discussion. The speakers are Bob Shapiro and Adam Wenner, two regulatory lawyers from the Chadbourne Washington office, Philip Hanser from the Brattle Group, and William Hieronymous from Charles River Associates Inc. 

Regulatory Thicket

MR. SHAPIRO: Let me start with an abridged history of utility regulation. 

You may recall that, at one time, dinosaurs roamed the earth and it was very warm, and electricity was really not needed. And then it got cold, Thomas Edison invented the light bulb, and monopolists set up electric utilities. Franklin Roosevelt persuaded Congress in 1935 to pass two important pieces of legislation — the Public Utility Holding Company Act and the Federal Power Act — in an effort to
rein in those monopolists. Jimmy Carter a few years later persuaded Congress to pass still more energy legislation, including the Public Utility Regulatory Policies Act, or “PURPA,” in order to  encourage competition. George Bush I put another important bill through Congress called the “Energy Policy Act” in 1992. It created something called “EWGs.” 

Then everyone forgot about regulation altogether and Enron roamed the earth and, like the Pied Piper, the power industry followed it into the sea. 

And then everyone started out handing business cards at job fairs. 

To the question,“What does this have to do with transmission,” the answer is very little. The reason is that transmission, unlike generation, has never been perceived, at least until now, as a  competitive business. It has always been heavily regulated. It is a bottleneck monopoly. 

While the Federal Energy Regulatory Commission has undertaken a number of regulatory initiatives, very little has moved forward in the transmission area. Many proposals are pending. There remains a serious question whether FERC can do very much in this area without significant federal legislation, and there remains a question whether the FERC initiatives are even relevant any longer given the current state of affairs in the power industry where major power companies are simply fighting for their lives.

I will talk about four statutes that come into play when someone wants to acquire transmission assets. The main one is the Federal Power Act. Most of my talk will be about the Federal Power Act and the initiatives under it, but three other pieces of the regulatory puzzle that are relevant for this discussion are PUHCA, PURPA and the Energy Policy Act of 1992. 

Federal Power Act

Starting with the Federal Power Act, be aware that it covers all of the United States, except Alaska, Hawaii and a small part of Texas called the Electric Reliability Council of Texas, or “ERCOT.”

The Federal Power Act labels as a “public utility” any person who owns or operates facilities that are subject to the commission’s jurisdiction. Jurisdictional facilities include transmission facilities used in interstate commerce and transmission contracts. It excludes facilities that are owned by municipalities, federal power marketing agencies, and federal coops. Those are coops that have federal financing from an agency in the US Department of Agriculture called the Rural Utilities Service, or what used to be called the Rural Electrification Administration. 

FERC has authority under the Federal Power Act to set rates and remedy anticompetitive and unduly discriminatory practices. It is this part of the Federal Power Act that has been used to try to open the transmission system and get the integrated intrastate network moving to a fair, competitive playing field. 

FERC has authority to order electric utilities to let independent power plants interconnect with their transmission grids. FERC has authority to order utilities to provide transmission service and enlarge transmission capacity needed to provide transmission service. The Energy Policy Act in 1992 added a procedure for would-be transmission customers to ask for a transmission service from a utility
that controls the grid and, if it does not receive a timely response to its request, to complain to FERC.

What has FERC done with all these powers under the Federal Power Act?

It has issued since 1996 a series of orders and proposed rulemakings. I will mention them fairly rapidly. They are Orders 888, 889 and 2000, a proposed policy statement on new transmission pricing, a proposed rulemaking on “standard market design,” another proposal to adopt a standard interconnection agreement for electricity generators connecting to the grid, and some case-by-case adjudications of transmission issues. 

Starting in 1996 in Order 888, FERC ordered all utilities under its jurisdiction to file open access transmission tariffs, or a schedule of rates that anyone wanting service could pay for transmission. An interesting feature of Order 888 is that nonjurisdictional utilities — utilities that are not subject to regulation by FERC under the Federal Power Act, which include municipal utilities, Rural Utility Service-financed electric utility cooperatives, and federal power marketing agencies, as well as utilities in Canada and Mexico — are required also to file open access tariffs, even though they are not subject to regulation by FERC, if they want to use the open access tariffs of jurisdictional utilities. In other words, they do not have to do it, but if they do not, they will not have access to neighboring utility grids. 

FERC in later orders read Order 888 also to require utilities to allow anyone wanting transmission service to be able to connect to their grids. 

A companion order was Order 889. This created the socalled OASIS system.“OASIS” stands for “open access sametime information system.” It is a real-time information system that lets users see what capacity each jurisdictional utility has for additional transmission. It also has real-time information on transmission pricing. It requires that all requests for transmission and all responses be posted on the Web. The goal is to create a level playing field for all generators and other electricity sellers who are using the transmission systems of vertically-integrated utilities. 

The next significant order was Order 2000 issued in 2000. It came about primarily because the Energy Policy Act of 1992 failed to include authority for FERC to order regional transmission organizations, or RTOs, that would control regional sections of the grid. There was language in the draft legislation that lost at the eleventh hour, and FERC lost the authority that it wanted, so, in other words, it ended up the authority the authority to order utility to transfer control over their grids to RTOs. What FERC has been trying to do ever since is to do administratively what it was never given
authority to do by Congress. And that has led a number of people to wonder what the real scope of authority is that FERC has over this whole area, and also may help to inform why FERC has not gone farther than it has today. 

The goal of the Order 2000 was to put in place RTOs nationwide by December 2001, but in fact as of March 2003, only two RTOs have been more or less completely approved — the Midwest ISO and PJM. Others have had some aspects approved, but obviously things have gone fairly slowly compared to what FERC set as its goal in 2000. 

The goal was to have utilities transfer operational control over their transmission facilities to RTOs. A key principle for RTOs was a separation between market participants and the people who are controlling the RTO. Each RTO was supposed to have sufficient regional scope to bring economies of scale. 

FERC remains concerned that entities like the New York ISO and New York power pool are too small to function effectively as RTOs. 

FERC determined that what it has done so far is not enough. RTOs have not come into being as quickly as it hoped. Consequently, it initiated more rulemakings with the goals of giving the vertically-integrated utilities an incentive to give up ownership or control of their transmission grids, of making it easier for independent generators to obtain interconnection and transmission service, and of the construction of new transmission capacity.

These new initiatives were principally the introduction of incentive pricing for independent transmission and new transmission, an attempt to impose a standard market design, and a model  interconnection agreement that all utilities and independent generators would be expected to use in the future, and the adoption of a fairly simple regulated transmission policy — the so-called “or” policy — for pricing regulated transmission interconnection. 

FERC has issued a number of orders on transmission policy. The agency tried to bundle them all together in a single proposed policy statement on transmission pricing on January 13 this year. Basically what FERC is trying to do is to create incentive rates to induce utilities to transfer ownership and control over their grids to RTOs and to build new capacity on the grid. The main carrot for new construction is the ability to earn up to 300 basis points in additional return above what a utility would ordinarily be allowed. 

This is regulated transmission. Merchant transmission is another story. FERC has been willing for purely merchant transmission to allow essentially unregulated rates — whatever can be negotiated with customers. However, to date, merchant systems have been fairly limited mostly to undersea cables.

Under the proposed policy, action must be taken by December 31, 2004 to receive the incentives. The incentive rates would be guaranteed through December 31, 2012. FERC has sought comment on whether additional incentives are needed and also how to encourage certain new technologies. 

The big rulemaking that has been debated for the last nine months is the proposal for “standard market design.” 

The goal is to remedy undue discrimination in the use of the transmission grid. One very controversial issue is that FERC proposes to exercise jurisdiction over the transmission components of bundled retail transactions — that is, transactions in which the customer receives electricity and transmission as a single product. This is something that many oppose. The goal of standard market design is to have each RTO serve as a completely independent transmission provider. It would make all the important transmission decisions, including decisions about availability, the need for
and implementation of transmission expansion, congestion management. Each RTO would create a single, very wide regionally-based tariff and avoid “pancaking” of rates. Each RTO would make all of the resourcedecisions for its region.

At the same time, FERC has been reiterating that it is stick-ing to what is called its “or” policy for existing transmission and for interconnection to the grid. The “or” policy allows the trans-mission provider to charge an independent generator connect-ing to the grid the higher of rolled-in pricing or incremental costs for any upgrades that must be made to the grid to accom-modate another power plant, but it cannot charge both. Rolled-in pricing would include the cost of the upgrade, but that cost must be allocated to all of the transmission provider’s customers. There can be no “direct assignment” of that costs of the upgrade to the generator. If the generator advances the funds for the upgrade to the utility, then the utility must credit the amount — with interest — against future transmission service payments. However, the generator is required to pay the cost of the direct intertie to connect its plant to the grid — for example, the radial line running from the plant to the grid, as well as the cost of step-up transformers.

PUHCA and Other Statutes

Let me now touch briefly on three other statutes that also affect transmission. The Public Utility Holding Company Act, or “PUHCA,” regulates utility holding companies and their subsidiaries. An entity is considered a holding company if it owns or controls 10% or more of the voting stock of a public utility company. A “public utility” company is a company that owns or operates facilities used for the generation, transmis-sion or distribution of electricity for sale, so owners of trans-mission companies could be subject to potentially onerous regulation as utility holding companies under PUHCA, unless they own less than 10% of the voting stock or they have taken care to structure things so that they qualify for an exemption.

Regulation as a registered holding company is apparently a less daunting proposition than it used to be because owners of some planned independent transmission companies seem willing to bite the bullet and become registered holding companies. In the past, people were scared of PUHCA because almost every major business decision by a registered holding company must be approved in advance by the US Securities and Exchange Commission.

Moving to PURPA and its link to transmission, “qualify-ing” cogeneration and small power production facilities are exempted from regulation under the Federal Power Act, PUHCA and state utility law. A QF can include the intertie needed to deliver the QF power to the grid. Thus, the trans-mission line that is associated with a QF would not be regulated under any of these statutes unless that line is also used to transmit power for a third party.

But a note of caution: the Energy Policy Act gave FERC authority to order transmission over anybody’s transmission lines — whether or not the lines are subject to FERC jurisdiction so that a QF could be a target of a transmission request by a third party.

The Energy Policy Act also created a category of power plants called “exempt wholesale generators” or “EWG’s.” There is a common misconception that EWGs are exempted from utility regulation. They are exempted from regulation by the SEC under the Public Utility Holding Company Act, but they are not exempted from such regulation by FERC under the Federal Power Act.

I should say something about state regulation of trans-mission. It really is the Achilles heel of transmission because siting restrictions can be devastating to the construction of new transmission capacity. The states today control all siting decisions. Also, states have condemnation authority that they can assign to franchised utilities.

The Federal Power Act gives FERC authority to license hydroelectric projects, and it has eminent domain authority over the entire property of the hydro licensee, including associated transmission lines. That’s it. FERC has no other federal eminent domain authority. So it can’t really do much to help with the shortage in transmission capacity, which is somewhat in distinction to the Natural Gas Policy Act and pipelines and gas transportation where it does have some eminent domain authority.

Congress has been debating whether to give FERC eminent domain authority for electric transmission either directly or after a period of time if the states fail to implement transmission expansion, but this proposal is vigor-ously opposed by the states. It is unlikely that we will see any federal eminent domain rights in the near term. Without federal legislation, intrastate transmission expansion is going to be very difficult unless there is a regional crisis.

In conclusion, let me leave you with a series of questions because at this point, it appears that no one has any good answers.

Who will be the next giants to roam the earth?

Who will take the dilapidated current market and exploit it for greater profits? Will it be the individuals like Warren Buffet and Bill Gates? Will it be the oil majors? Will it be the investor-owned vertically-integrated utilities again? Will it be

deep-pocket private equity funds? Will it be foreign utilities? Or will it be the law of jungle?

On the screen is a cartoon of a lion talking to its cub saying, “Fortunately, the law of the jungle doesn’t require lawyers of the jungle.” I would say, though — to paraphrase the Master Card commercial — for everything else you need lawyers.

Opportunity or Fantasy?

MR. HANSER: I want to talk a little bit about the relation-ship between transmission and generation. It is hard to talk about one in the absence of the other. That would be like talking about the design of a new automobile without talking about whether there are going to be highways on which the automobiles can drive.

I want also to talk about some problems that arise in terms of efficient investment behavior that FERC does not seem to have addressed in its standard market design proposal.

Finally, I want to talk about some roles that might arise for RTOs and I’m going to talk at the end about the general market that will arise out of this. These are my opinions and not necessarily those of the Brattle Group.

The first point is that the existing transmission systems are “legacy systems.” They are very old systems. They have been developed with some specific purposes in mind. For example, ISO New England has a transmission grid with very thin wires. The transfer capability of ISO New England is relatively limited compared to the transfer capabilities of the transmission systems for the New York ISO.

Why is that? Historically, generation in New England was built close to load centers. The result was there wasn’t a need for building a transmission system in which large amounts of power were moving around. In New York, in contrast, you had the great Niagara Falls and other hydroelectric facilities that sat in the north and the eastern part of the state, or sometimes in the western part of the state, but large amounts of power had to be moved toward New York City in the south.

The net result — I’ll give you a stupid one — is that if you look on a transmission map of ISO New England and the New York ISO, you will see that there are lines in both systems rated at 220 kilovolts, but the power carrying capability of the two lines is vastly different. The reason is the New York ISO transmission lines are four times the diameter of the lines that are used in ISO New England. Thus, New York has roughly four times as large a power-carrying capability as New England.

The net result is that you have two 220 kv lines running in parallel through Connecticut and southern New York and you say, “Why can’t you connect the two?” The answer is: You can’t connect the two easily because, if you did, you would blow one system off the map. This is a legacy of history.

In the western United States, on the other hand, you have transmission lines that are of enormous length. For example, the line that connects Bonneville to northern California is 1,100 miles long at its longest point, which is a distance longer than the distance between New York City and Chicago. There are stability problems that arise in moving power back and forth over such a long distance. Therefore, that transmission system operates differently from an electrical standpoint than any of the other systems in the eastern US.

The net result is it is almost impossible to have a “one-size-fits-all” standard market design. That’s why I think we are moving from SMD to IMD where “I” stands for idiosyncratic.

Pricing Issues

Let’s talk about location-based marginal pricing, or “LMP,” for electricity transmission. I have just a few points to make.

LMP is an appropriate short-term method for charging people to move electricity, but it has peculiarities that are important to understand and that are a function of the transmission system. With LMP, users of the grid are charged a different price depending on whether or not there is congestion. If there is no congestion, then there is a single uniform price that steers the entire transmission system and the entire market.

One of the problems is that LMPs tell you that there is congestion on the system and to make changes, but they don’t necessarily tell you exactly where. One of the problems also is that the price differences may not be sufficient to reduce demand so that the congestion is relieved. And in fact, depending on the assumptions you make about how generator costs are bid in, you can show they are insufficient to pay for the cost of the investments associated with transmission lines.

If I think about the nature of the transmission investments that I want to make, one of the problems is that there are siting restrictions that to a large degree determine where I build generation and transmission. Given this legacy grid, a lot of generation is built in places where companies could build generation as opposed to where they wanted to build generation, and the same thing goes for transmission lines.

Therefore, if you are going to talk about having an optimal investment strategy for the country as a whole in terms of social policy, you must deal with the fact there is a lot of poorly located transmission and generation already that could not have been built anywhere else.

When people say, “We’re just going to redo this and have this wonderful wholesale market based on this wonderful transmission system to move electricity,” the question that comes to mind is, “What’s the reality of it? If you could not build it when you had state-regulated monopoly utilities, what makes you think you are going to be able to build that system when you don’t have state authority.”

I don’t mean to sound pessimistic. I just want people to understand that there is a grand conception that that we will have this wonderful deregulated wholesale generation market and a transmission system to support it. I love the grand conception, but the reality is there is a lot of history to overcome and we must be realistic about what really will happen

There is certainly the appropriate economic motivation to say,“We should have transmission investments paid for by the parties that benefit,” but the problem is the benefits are sometimes so diffuse that it can be hard to identify precisely the degree to which different parties benefit.

The Federal Energy Regulatory Commission could have a completely different policy, but if it

operates in parallel to the policy it adopted for gas pipelines, this suggests the majority of transmission is going to end up being paid for through rolled-in rates.

Trends in Regulation

I think that in the long run what will develop on the genera-tor side is either quasi- or crypto-regulation. It is possible for a generator to earn enough of a return by having prices spiky enough to make it worthwhile to own a power plant. The problem is there is no political appetite for it. No one wants to wake up one morning and read in the newspaper that the price of power spiked to $3,000 per megawatt hour for one hour on August 11, 2005, even though 98% of the hours of the rest of the year were floating at $25 to $30 a megawatt hour. The reality is we have price caps. The problem is there is no money to be made to cover fixed costs in the long run in a market like that. Therefore, someone will eventually say to the regulators, “Here is the cost for capacity,” and ask them to set a price for capacity that will implicitly set a rate of return that an investor can make. I don’t know whether the forum for this argument will be the RTO or FERC, but it will mark the return to good old rate of return regulation.

In the end, what will happen is we will have a system in which there is regulation for generators at the RTO level and for transmission at FERC. The only way the twain will meet is when generators and transmission owners are put on committees together to decide what new transmission will be built and where new power plants can be located in relation to the grid.

Here is my bottom line. Basically we are back to the bad old days. A competitive strategy on the part of a company, whether it is a generator or a transmission company, is essentially a regulatory strategy at this point. Where you will make your money is by being inside the regulatory process. Fundamentally, you have to be as big a technocrat as the technocrats who are running the RTOs and ISOs. You have to know their models. You have to understand their informa-tion. You have to understand the rules by which they operate. This is true whether you own an existing power plant or you are trying to figure out where to build a new power plant or you are planning to build a new transmission line.

I don’t mean to be cynical about this, but I don’t see any other possibility at this point unless somebody comes up with a brilliant new theory for how to make all of this work.

Merchant transmission in the long run will be a no go. There are a few isolated places where you can put merchant transmission lines and collect revenues for relieving conges-tion, but each new line built reduces the amount of conges-tion revenue and the potential profit. You will never get to the “necessarily optimal level.”

In the end, you will need to understand the regulatory process and the technical details. There is a stupid paper that I love that says it turns out there are these things called algorithms that choose which power plants will run. They all have approximations in them. The computer model can come to two solutions that are nearly identical, but the problem is it chooses different generators when it gets done with the program. So here is a situation in which this model is making choices about which generators will run. From the stand-point of the technocrat, the two solutions are equivalent.

From the commercial interest of the generator, they are very different because in one situation one generator runs, and in another situation another generator runs. That is the kind of thing that it will be important to understand because that is where the money is to be made.

Policy Challenges

MR. HIERONYMUS: I think FERC has a lot more to do. I plan to touch on three subjects. The first is transmission investment. We have created the right incentives. Phil Hanser and Bob Shapiro talked about the problem of siting. We are not going to fix that, at least not through this process.

The second thing I want to talk about is the allocation of congestion revenue rights, or “CRRs,” and the third thing is what FERC refers to as “resource adequacy,” which is to say the mechanism by which we assure that a reliable system gets built.

I’m not going to mention everything about these subjects. Rather, I have tried to focus on things that are of particular interest to merchant generators. In particular, I want to talk about the allocation of transmission costs as between merchant generators and the other users of the transmission grid, about the process of determining who gets CRRs, and how we handle the problem of assuring suffi-cient capacity for reliability purposes.

The standard market design proposal that FERC issued assumes that transmission will enter the merchant business and that people will build transmission lines for profit. I agree with Phil Hanser that this is not going to happen. The US electricity grid is an interconnected system. The system cannot tolerate merchant transmission facilities except for direct current, or DC, facilities. It cannot tolerate alternating current, or AC, facilities that perform on a merchant basis where capacity is sold to the highest bidder.

FERC has said the costs of new transmission should be allocated on a user-pay basis. That’s fine, except that it turns out that it is really difficult to determine who the beneficiaries are. FERC has recognized this to the extent it said,“If somehow or another there are transmission assets needed that participants won’t voluntarily pony up to have built, then we will allow the cost to be rolled into rates or allocated among the participants within the rate-making process.”

This leaves the question, “Can you really have a system that at its core relies on voluntary investments from partici-pants?” Is it a viable system if people know that investments that are needed but don’t get made voluntarily will be paid for in rolled-in rates?

To give you a notion of the scale of the problem — and this is admittedly one of the worst examples — Entergy estimates that accommodating the 21,000 megawatts of planned and reasonably committed generation on its system will cost more than $1 billion. The generation itself will cost more than $10 billion. The dollars involved matter to the public utility commissions in Arkansas, Louisiana and Mississippi and, because of rate freezes, they matter a whole lot to Entergy. There is a huge fight by Entergy and these commissions to avoid having to roll into rates the costs that are needed to accommodate all of this generation, most of which, they contend, is of no benefit to the Entergy system.

Utilities historically have used high participant funding allocations as a way of putting costs onto merchant genera-tors. I worked on one case where a merchant plant was being built in Boston that would actually eliminate all the conges-tion into Boston, and the home utility — to whom the ISO had handed off the job of determining what the generator owed — said, “If you will solve $50 million worth of transmis-sion problems within the city of Boston and also pay us $30 million for the excess power costs when we’re doing the transmission upgrades, then you can build your plant.”

The extraordinary thing is the generator is going to save that utility and its ratepayers a great deal of money by making available 1,600 megawatts of brand-new combined-cycle capacity in a city that has nothing but ancient units.

But that is the way the game is played. It wasn’t done in this case to preserve a market for the utility’s own electricity generation. The utility had already sold all its power plants. It was done because the utility is subject to a rate freeze, and if the utility had to add to its grid while still subject to a rate freeze, it would lose money.

On the other hand, we have a situation where many generators have built their plants without any regard whatsoever to the relationship to the transmission system. There is currently no way to get all that electricity to market. We have this problem in New England, in Rhode Island, in southeastern Massachusetts and in Maine. That happens to be the system I know the best.

Around the Palo Verde belt in Arizona, there was all this generation built to serve California load and there is no way to get the electricity to market.

Billions of dollars have been put into the ground without the slightest conception about who is going to build the highway to get it to market and how that highway will be paid for. What we see in many cases is a game of chicken. The utility says, “When you come up with the money, we will build the transmission.” The generator says, “But you are the transmission utility. You build it.” In this situation, the utility holds the winning hand.

That having been said, if we systemically ratify these bad siting decisions by generators, then generators will continue to build new power near gas lines, near cheap water sources and so on without any regard to what it costs to get the electricity to market.

Who Should Pay?

A useful framework to think about is you have the costs of direct interconnection — the leads, the switchyards. That incontrovertibly is something that the generator pays for. Then you have what FERC has in mind when it talks about a base load, which is the kind of generation that customarily would have to be built in order reliably to serve the load in the control area.

In Entergy’s case, I think it says about 6,000 megawatts of generation is needed and so, at least in some sense, Entergy ought to pay for the cost of grid improvements to accommodate the 6,000 megawatts. Of course, that begs the question: “Which 6,000 megawatts?”

Then there is economic reinforcement. Entergy has mostly old gas steam units. They are not very efficient. The new power plants are efficient combined-cycle units. They can indeed economically displace a lot of the older Entergy units. Thus, there is a benefit to Entergy’s ratepayers to gain access to an additional tranche of this generation. Of course, there is also a benefit to the generator to be able to sell its output. This suggests something about how to allocate the costs. The other piece of it is for the next six, eight or 10 years, there is no use for the additional capacity on the Entergy system. So the excess load is resold in the meantime to another region. Intuitively, the beneficiaries are the generator and load in the importing region, but there is no way under the current rules to force the importing region to pay any of the costs.

Another question about interconnection is, “Who decides what is the incremental amount of grid improvements that is needed to support merchant generation?” This is partly a boundary issue. In the Duke Energy Hinds decision, FERC said the substation upgrades that Entergy demanded of Duke — and that Duke in the first instance agreed to pay for — are part of the network. Duke could not be required to bear their cost as an interconnection asset. Duke may advance the funds, but it receives a refund through transmission credits with interest. It is partly a question of deciding what is being done for the benefit of the independent generator and what is being done for the benefit of other users of the grid. FERC would leave this decision to the RTO or ISO, but it often lacks the capacity to answer the question. It is also like putting the fox in charge of the chickens. It is not necessarily an honest broker. We see frequent capture of ISOs by subsets of their participants. RTOs currently have an incentive to shift the costs to merchant generators because of rate caps.

This may change if the government starts giving meaningful incentives for building new transmission lines. However, at least for now, FERC is saying if you have hot-shot transmission project to build and you will receive CRRs from it, that should be enough incentive by itself to build. As Phil Hanser alluded to, as a general, that is not going to work. Transmission investments are lumpy. If you have a lot of transmission and congestion before you build it, you will have a lot less congestion after you build it, with the result that you have solved a big problem and will never receive the congestion revenue on which you were counting. Meanwhile, generators get the benefit of being able to sell at higher prices into what were previously constrained markets. Loads, in turn, get access to lower cost generation and face lower locational marginal pricing at the load buses. The bottom line is there is a large benefit that is extracted by someone other than the owner of the CRRs.

Another problem with any transmission investment in this new world is that if I am building transmission to reduce congestion — let’s say into New York City — and someone else comes along and builds a thousand megawatts of new generation in New York City, the value of my transmission investment just went south. So in the absence of central planning, there is the hazard of competing investments.

The last topic is resource adequacy. In its SMD proposal, FERC came up with something truly bizarre. The essence of it is the idea that everyone will contract forward for capacity, but no one will have to pay for it unless the system turns out to be short in real time. If you want your basic free-rider problem, you have created it here in spades.

FERC has recognized that this will not work. The plan is basically off the table. I don’t know what we will see in April when it issues a white paper, but we will see a different approach.

So where do we want to go? We have forward markets for power in substantial part due to new generation. New devel-opment can compete. That’s what FERC has been trying to achieve. We need to make sure that the electricity is really deliverable, that the additional generating capacity is real. We must come up with a way to accommodate retail access. That may involve the ISO buying capacity and then a forced resale to people who lack it. We need to move to where we accept reliability levels that are by the market.

We have the short-run stuff right. FERC still has a long way to go on the long-term stuff. And since FERC chairman Pat Woods wants us all in RTOs operating under a standard market design by the end of his term, we are going to have to move fast.

Two Different Project Models

MR. WENNER: Let me try to inject some optimism in this discussion. I will try to describe some of the actual projects that real world investors have invested in notwithstanding the risks that have been identified by some of our speakers.

FERC has divided the transmission that it is trying to encourage into two categories: merchant transmission and the independent transmission company model.

Merchant transmission projects are discrete new projects that involve DC interties that permit load flow to be controlled and that connect regions with significantly differ-ent energy costs so that the owner of the transmission system can capture the benefits of those differences and make a profit. FERC has permitted deregulated rates for merchant transmission. Thus, if the cost of generation is $40 merchant transmitter can capture all the benefits by charg-ing up a toll of to $19 for use of its transmission lines to move the power.

FERC has required that an “open-season” process be used to award entitlements for merchant transmission projects, much like the process that is used for gas pipelines. Although FERC has the usual affiliate concerns, it does allow a project to be developed by a company that has both a power marketing affiliate and a generation affiliate. In essence, FERC does not view merchant transmission projects as having monopoly power. It views them as taking genera-tion and moving it — in the example I described — from Connecticut to Long Island. There is no reason to regulate the transaction.

Merchant transmission involves DC transmission lines that allow the load flows to be controlled. Because of this, one doesn’t have to worry about the congestion rights that occur on an AC system. In an AC system — the traditional utility grid — electricity moves in the direction of least resist-ance. DC lines are used more typically to move power in a particular direction. In other words, if you buy 50 megawatts of firm capacity on the cross cable that connects Long Island to Connecticut, no one is going to interfere with your 50 megawatts. Those flows are controlled, since the transmis-sion line operates like a gas pipeline.

The other side of the coin of being allowed to charge unregulated rates is that the merchant transmission owner must bear all market risk. There are no captive customers on whom to impose the costs of a failed or uneconomic merchant transmission project. The developer is at risk if he builds a project that fails to attract enough use to pay for itself. This problem is addressed by having firm contracts in place before the project is financed.

One disadvantage for merchant-transmission projects is that since they are not “franchised” utilities, they do not have the authority to exercise eminent domain to acquire rights-of-way. Moreover, were they to receive such authority, FERC has indicated that it would be concerned, since eminent domain authority usually gives a company an advantage over competitors.

There are concerns — since rates are left to the market— that a franchised utility whose affiliate is developing a merchant transmission project could either cross subsidize the project by having the work done by its regulated side a mWh on Long Island and $20 a mWh in Connecticut, the and direct the costs through the merchant project, or use its own transmission system to limit access to the merchant project so as to favor its own affiliated generation. Northeast Utilities, which has proposed a merchant project, withdrew its initial request that for its merchant affiliates to participate after FERC made it clear that it was concerned with this issue.

As of today, FERC has approved five merchant transmis-sion projects. They are the cross-Sound cable project connect-ing NEPOOL to the New York ISO in Long Island. High energy cost differentials justify that project.

The harbor cable project would connect New York City and the New York ISO with the PJM system in New Jersey, another underwater project. Again, you can see that these projects are used to cross geographic barriers. Indeed, that is why there are such big rate differentials. Otherwise, there would be a free flow of energy, and these differentials would not exist in the first place.

The Northeast Utilities project would go from NEPOOL to Long Island to New York ISO.

Hydro One is a project that would connect Ontario, by going under the Great Lakes, to either the PJM or the Midwest system. The point of connection has not been determined yet.

Finally, at least on paper, there is the Neptune project, which would be hundreds of miles of cable under the ocean. It would connect the power-rich areas in Maine, New Brunswick and Nova Scotia with New England loads.

The second type of merchant transmission is the “independent transmission company” model. Projects in this category do not involve new construction. The independent transmission company owns an existing utility grid and is no longer affiliated with any generation or merchant function. It is a “pure” transmission company. FERC’s goal in the independent transmission company model is to eliminate the favoritism that transmission owners might accord to their affiliated merchant functions and eliminate the discrimination that they have the temptation to exercise against competitors.

By focusing only on transmission, a company has an incentive to disfavor generation. Independent transmission companies will own AC systems for which load flows are not subject to control, and so congestion rights are necessary to ensure that the holder of legal rights gets the financial benefit of its investment.

FERC has proposed incentives for companies to become independent transmission companies. Rate regulation for such transmission companies will be done under traditional costs of service as opposed to the deregulated rates that merchant companies will be allowed to charge. So you have a cost-of-service model, and then FERC is proposing benefits on top of that to provide incentives for becoming independent and for investment in innovative technologies.

One benefit to independent transmission company status is that if a company becomes a transmission-only company, it becomes subject only to regulation by FERC and ceases to be subject to regulation by state commissions. FERC generally is viewed as a more stable regulator than a state commission. It more removed from the pressures of consumer intervention. This is the big unspoken benefit from spinning off transmission assets into a transmission only company: the owner is insulated from state commis-sion regulation.

FERC has acted on several independent transmission company applications already. These involve real-world sales of utility transmission systems by an integrated utility to a trans-mission-only company. They include the sale by Consumers Energy of its transmission grid to Trans-Elect, the proposed sale by Illinois Power Company of all of its transmission system to another subsidiary of Trans-Elect, and a sale by Detroit Edison Company of its system to International Transmission Company. FERC has also approved formation of the Translink Transmission Company, which would own, lease or exercise operating control over participating utility systems.

Ownership Structures

Now let’s see how the regulatory issues that Bob Shapiro described are affecting how these transmission-only compa-nies are structured. First, as Bob pointed out, an entity that owns transmission assets is a “public utility” under the Federal Power Act and, as such, is subject to regulation by FERC. That’s not really a problem, and it does not affect the structure because FERC regulation does not go upstream. It applies only to the transmission company.

However, as Bob also pointed out, the owners of that company are owners of voting securities of an “electric utility company” under PUHCA and, therefore, unless they can find a way to get out of it, they would become subject to SEC regulation as a registered holding company under PUHCA. That’s not something they want to be because, unless an exemption applies, the holding company can only own utility businesses or utility-related businesses, and all its utility subsidiaries must be in a single region of the country.

In practical terms, this means that a company like Microsoft, Marriott and McDonnell Douglas cannot acquire the common stock of a transmission company, because it would have to divest its core business. That is not going to happen.

It also means that the owners of independent transmis-sion companies are going to be a small class of companies. They will not be the traditional utilities. Those are the companies that divested themselves of their grids. The crite-ria for an independent transmission company would not be satisfied if American Electric Power, for example, owned it. In general, the owners will be new companies that are not very highly capitalized so that they can tolerate PUHCA regula-tion. They will significant outside investment.

There is an alternative ownership structure that those of you who lived through the independent power project movement before 1992 and the creation of EWG’s will recog-nize. “PUHCA pretzels” are back. That is a structure in which individuals own the voting securities of the transmission company with outside investors participating through a limited partnership.

Three of the independent companies that have already been created have dealt with the structuring problems as follows. Michigan Independent Transmission, which owns the Consumers Power system, was sold to Trans-Elect. Trans-Elect is a Canadian company. It will be a registered holding company, but it can tolerate PUHCA regulation. The outside investor is General Electric Capital Corporation. GECC is putting in a lot of money through a limited partnership that enables GECC to avoid PUHCA regulation.

The Illinois Power transmission grid is being sold to the same company, Trans-Elect. AIG will be the outside investor in this case, and it will invest through a limited partnership to preserve its non-PUHCA status. The transmission system of Consumers Power Company is being sold to a new company, International Transmission Company, that will have Kohlberg Kravis Roberts, or “KKR,” and Trimaran as the passive investors and an individual, Lewis Eisenberg, as the owner of the voting securities.

The same structuring challenge exists merchant trans-mission projects. The same PUHCA issue must be solved. In the cases of the cross-Sound cable project and Hydro One, the owner is TransEnergie, which is a subsidiary of Hydro-Quebec and which is entitled to an exemption from PUHCA as a foreign utility holding company. Northeast Utilities, another owner of a merchant transmission project, is already a registered holding company. PUHCA regulation is not an additional burden to it.

Turning to rate-related issues, when a new company buys a transmission company, it is convenient to hire the employ-ees who operated the grid to continue servicing it. They are familiar with the system. They are trained. For example, one might hire Detroit Edison to operate a grid that it sold to an independent transmission company. FERC has expressed concern that such an arrangement results in a grid that is not really independent of the utility that originally owned it. Thus, it has given the new grid owner only a year to keep the former utility owner under contract as the operator. After that, the independent transmission company needs to have hired its own employees. This has created stress because it is not easy to do this within a year. Expect to see the industry to ask FERC to revisit the issue

Now for the good news: FERC allowed the International Transmission Company, which is acquiring the Detroit Edison grid, a 13.88% return on equity in a capitalization structure that included 60% equity. This is significantly higher than what is normally allowed in the utility industry. FERC hopes this will serve as an incentive for the creation of more independent transmission companies.

FERC permits the recovery through rates of accumulated deferred income taxes that become due on the sale. This is the accumulated difference between the book and tax depreciation to the date of sale on the grid.

Conclusions

The regulatory climate is not ideal, but investors are going ahead with independent transmission companies.

PUHCA repeal would make it unnecessary to have the convoluted ownership structures I mentioned, but based on recent events, PUHCA repeal is not likely to happen soon.

Finally, as Bob Shapiro mentioned, many people feel that the deadline of 2004 to vest operating control of the national grid in regional transmission organizations, or RTOs, is too short. They are asking FERC to allow more time. Similarly, the short deadlines for reworking the O&M arrangements for the system are creating problems.