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Organization of Transmission
First, consider the organization of the transmission sector and then tell me, with a straight face, that it is a business.
Most transmission lines are owned by the utilities, but are under the operating control (or soon will be) of non-profit, supervising monopolies called regional transmission organizations. RTOs have no fiduciary responsibilities to the owners of the lines, as far as I can tell, and do not report to the owners of the lines or to consumers or to local regulators. They do report to the Federal Energy Regulatory Commission (FERC), which has no contact with consumers and no direct control over the local utilities. Since the lines remain in the state rate base, most of the profit earned on the lines comes from the local consumer, who may or may not benefit from their operation.
A handful of regulated independent companies own lines, but they report to the RTO in the same way as the utility owners, despite that fact that they do not have the conflicts of interest that caused the FERC to force the RTOs on the utilities in the first place. The Feds regulate these companies, though, because they no longer have assets in state rate base.
Merchant transmission companies can fill gaps in the network, put in lines where doing so would profit them. Despite the fact that the merchants receive no assurance of regulatory return, and they have no conflicts of interest, they still have to jump through all the hoops required by the FERC and the RTO.
FERC has instituted a congestion-pricing scheme called locational marginal pricing (LMP) to signal generators (after the fact) which lines are overloaded so that generators will put their facilities where the lines can carry the output.
The RTOs have instituted procedures whereby users can acquire the rights to those congestion charges, thereby protecting themselves against unexpected congestion charges because they would collect those charges back through the rights.
Presumably, owners of the congestion rights could put up merchant transmission projects that would solve the congestion problem and collect the charges, and that is the bait originally dangled in front of potential investors.
Of course, if the merchant solves the problem, the congestion charges will fall for lack of congestion, making for a poor investment on the part of the transmission builder. Proponents of the system have finally figured that out.
So, how can a merchant finance a line and still make money? Simple: offer contracts to use it. That creates another problem, nowadays. In this age of freedom of choice, what entity could, prudently, sign a long-term contract when its own customers can walk away from it? Why is a long-term transmission contract any more prudent than a long-term power purchase contract?
Some now argue that in instances of market failure, the signals will not attract investment. The RTO will mandate the investment. Just to maintain the facade that the pricing system works for commercial uses of the lines, how about mandating capital expenditures for reliability purposes, because the market does not send signals for reliability?
Do they mean, “We won’t force anyone to put up lines for commercial purposes when the market does not want them, but we will make the RTOs and transmission owners put up lines needed for reliability,” or do they mean, “We’ll put a reliability label on anything we want built?”
It does not matter, though, because the transmission owner (generally the local utility) will have to build. But, what constitutes a reliability investment? Every instance of unreliability has commercial consequences for users and, I suspect, the RTO, in many cases, could find commercial solutions to unreliability, such as paying certain customers to go away or to install and operate distributed generation that would mitigate the unreliability problems on the grid.
Does forced investment produce satisfactory profits?
That brings up another issue. Nobody on the grid, as far as I can make out, has the incentive to find the lowest-cost means of furnishing service to consumers. Transmission owners have no control over charges for various transmission services, many of which have skyrocketed, which will affect the demand for transmission services. Basically, they have little say about the pricing or service levels of the products they get paid to furnish.
Does that have the makings of a good investment?
Business Structures
“But somebody has to do it!” say the industry engineers. Who are the somebodies?
First, the regulated utilities – Undoubtedly, somebody will order them to do it, and they will, possibly reluctantly and possibly enthusiastically, depending on the project. They will earn what the regulator allows, assuming that the RTO operates the system in a manner that so permits.
Second, independent transmission companies – Originally, those entities thought of themselves as like National Grid or Red Electrica, transmission companies that would own and operate the grid, under a regulatory regime that encouraged them to find ways to provide services at lower costs. Those would have been real businesses. But FERC pulled the rug out from under them. Now they resemble real estate trusts, except for these two critical differences: real estate trusts actively manage properties in order to improve value, and real estate trusts lock in returns through long-term leases. The transmission companies cannot actively manage to create value and the regulator will not provide a long-term return.
“Oh, but didn’t FERC offer high returns to independent companies?” the optimists ask. Yes, of course, but read the fine print. FERC did not specify the duration of the extra returns and did not specify extra over what.
Third, the merchants – So far, I think that one merchant line has gone into operation, and that only after the Secretary of Energy intervened to prevent an emergency. That line, planned years ago, depends on a contract from the user for its viability.
For all practical purposes, a utility that signs a long-term contract might just as well own the assets, because it takes the financial risk of ownership, as signers of long-term independent power producer (IPP) contracts found out when they had to buy out expensive contracts. Project sponsors have claimed the support of a number of big time bankers and investors for various projects, but the support seems more in the nature of polite interest until such time as the project has the users signed up on contract. Once that happens, the project developers can lean on the credit-worthiness of the contract users to raise money.
Regulators cannot force merchants to invest, but they can exert heavy pressure on regulated transmission owners to do so, and they seem ready to do that in the name of reliability, while still maintaining the facade of market pricing.
Repeat Performances?
Some of the transmission investors and bankers remind me of the hot shot generation builders before the crash, who depended on optimistic projections and the belief that all the other irrational players would back off and leave them with the markets. Or better yet, the energy players that went into foreign projects with only limited assurance of favorable tariffs, but with confidence that the host government would not act irrationally, that is, in a way would discourage future investments. Many foreign governments, however, figured out that once the investor had built the power plant, the investor could not move it out. The foreign governments captured the asset.
Now to another risk, similar to what happened after electric utilities built expensive nuclear power plants and discovered, after the fact, that they did not need them. The industry, at present, has no way to know how much investment in transmission it really needs. It does not know, and will not know, until it prices its product in a way that reflects costs.
For instance, peak-load pricing might reduce demand at key times by enough to obviate the need for new transmission lines. Nor has the industry considered whether use of local resources could relieve strain on the network more economically than through system expansion. Furthermore, neither industry nor regulator considers whether more efficient operation of the existing network could accomplish as much as new investment in the grid.
After previous experiences involving merchant generation, foreign investment, nuclear power and price elasticity of demand, it is amazing that investors would march into the middle of a dysfunctional transmission morass.
Distribution Differs
Financially speaking, distribution is more than twice as important as transmission to the industry. Most reliability failures take place on the distribution network, so improving service to 21st century standards will require more work on distribution than transmission. In the future, any move to a market in which customers can choose services and products will require a revamping of the distribution network. The new distribution grid will require sophisticated metering, individual turn on and turn off, and placement of distributed resources.
From an organizational standpoint, distribution looks more business-like. One entity owns and operates it and answers to one regulatory agency. Legal precedents tell what to expect from regulators. Customers view the distributor as the electric company.
In much of the period during which transmission expenditures fell off, spending on distribution held up. Once utilities signed on to price freezes as part of regulatory deals, distribution capital spending began to taper off.
Now that the price freezes have begun to expire and the economy has picked up, I would expect a sharp increase in distribution spending.
If the utilities actually intend to modernize the network and improve reliability, that spending will have to include sharply higher sums for communications, metering and distributed resources. With the higher spending, expect rate filings as well. Those filings will concentrate managerial and regulatory attention back on the distribution network.
The fact that so few customers have left the utility for the
competitive providers may offer a business opportunity to the utility, under the right regulatory framework. A modernized distribution entity could offer a sophisticated menu of pricing and services to the consumer, and could use its bargaining power to force better products and services from the other components of the supply chain, just as General Motors or Wal-Mart does in its markets. Regulators could reward the distributor for doing a better job for its customers. I suspect that investors would put money into utilities that make more money by satisfying customers.
Conclusion
Do not conclude that putting money into transmission has to be a bad idea, only that the current American framework for transmission seems an uninviting place for equity money, although it might provide opportunities for those seeking high return securities with fixed income characteristics.
As an equity investor, I do not see it as a business, and I would prefer to gamble on something that provides more fun or make charitable contributions to a worthier cause than to invest in a non-business.
I see greater opportunities in modernizing the distribution network business and in services that mitigate deficiencies of what the transmission network provides. But even those businesses require recognition from regulators that the purpose of the electricity delivery system is to provide consumers with the best products at the best prices, and those in the supply chain must all get paid on the basis of whether they have helped to meet that goal.
