Commission Watch
Planned or Private?
January 1, 2003
By Bruce W. Radford
The case for participant-funded transmission.
There's not much funny about electric transmission. But that didn't deter James Pope, chairman of TANC, the Transmission Agency of Northern California, and director of Santa Clara's Silicon Valley Power, from trying out a little humor. Speaking at the Federal Energy Regulatory Commission in Washington, D.C., on Dec. 3, at the FERC's all-day technical conference on congestion revenue rights (CRRs), Pope managed to crack up the morning audience with the sort of wit that could come only from a veteran of California's utility industry:
"The only substitute for electricity," he offered, "seems to be darkness. And that's not a very good substitute."
Pope's quip might appear irreverent. Yet the key to success for FERC's standard market design (SMD) may well lie in deciding which electric industry assets are interchangeable, and what that means for regulation.
In particular, the evolution of locational marginal pricing (LMP) and other ideas in FERC's SMD have caused utilities and regulators during the past six months to warm to the idea of the electric grid as private property. This change in thinking comes from all over. It comes from the Northeast United States (New York, New England and PJM), as one might expect, where they love the SMD. But it also comes from the Southeast, where many disdain the notion of electric competition and newfangled markets. You could see the change as well back in November, at the FERC's prior conference on pricing policy for transmission network upgrades and expansions.
This new view sees the grid not in terms of zones, regions or voltage levels, but instead in terms of beneficiaries. Ask whether a given transmission line or project is built (a) to maintain reliability, for the public at large, or (b) to grant access to markets for a profit-seeking generator, as a single market player. The one is "reliability transmission," eligible for traditional rolled-in embedded-cost rates and socialized pricing, and is planned top-down according to good utility practice by the regional transmission organization (RTO) or independent transmission provider (ITP). The other, however, is "economic transmission."
It's a different animal entirely. It doesn't depend on a finding of certificate of need. It doesn't fall under traditional regulation. It doesn't get rolled-in pricing.
It survives not on planning or public subsidy, but on private initiative and "participant funding."
To borrow Pope's analogy, recall that transmission, as an improvement over darkness, can actually serve fairly well as a substitute for generation. And so if generation becomes competitive, why not the grid?
In short, many now believe that if we put our faith in competitive generation and locational pricing, then we have no choice but to treat much of the grid as a privately funded merchant asset.
Two Flavors for the Grid
The Southeast-bastion of traditional utility regulation-now leads the push for participant-funded transmission (PTF). Consultant Michael Schnitzer (Northbridge Group), representing the proposed SeTrans RTO, laid out the idea at the FERC's November pricing conference. "What SeTrans basically says is there's two generic kinds of transmission investments: those that are necessary for reliability, and those that are motivated by economics," Schnitzer says.
Schnitzer and SeTrans would put these two categories of grid assets into different buckets, A and B. Bucket B, the reliability category, would fall under a familiar regulatory structure:
When questioned, Schnitzer explained that SeTrans would include in "reliability transmission" any grid assets required to meet recognized reliability criteria so that all "firm resources" within the RTO (meaning generators classed as "network resources," excluding generators treated as "energy-only") would be able to serve load:
But all other transmission then falls into Bucket A-the privately funded "economic" category-as Schnitzer explained further:
"Everything else, then, by definition, is for economics. … Someone wants to try and get lower delivered prices. Someone wants to try and get higher prices at their node. Someone wants to get more 'out' or 'through' service."
Under the SeTrans vision, private enterprise takes the lead in grid expansion. The RTOs and ITPs play only a residual role. They step in with public money only where the market has failed to attract the necessary investment.
Incentives for Private Funding?
Dividing the grid into separate buckets-public and private-assumes that the private financiers of Bucket A will receive congestion revenue rights as compensation (CRRs, also known as financial transmission right, or FTRs). Yet some experts wonder whether such compensation will prove incentive enough to encourage grid expansion. One such expert is Chuck Meyer, vice president of marketing and sales at Bonneville Power Administration. He argues that CRRs will fall short, forcing FERC to award transmission rate credits to private grid builders, as is done under some aspects of FERC's generation interconnection policy.
The issue invites a comparison between participant funding and the traditional method of socializing grid expansion through traditional embedded-cost, rolled-in rates.
Rich Bayless, director of interconnected systems at PacifiCorp, tells of a study conducted out West that looked at two alternatives to bring cheaper power to Colorado and Montana. Option A would expand the grid to gain access to low-priced but remote renewable energy and coal-fired power. Option B would build more gas-fired generators close to load, to avoid grid investment. How would participant funding affect each decision?
According to the study, Option A would produce net gen savings of $7 per megawatt-hour (MWh) across the entire customer base, after paying for a roll-in of grid expansion costs. But if you financed the grid construction privately, assigning the cost only to the coal-fired plants and windmill operators, you would add $5/MWh to the price of the generation and lose the competitive advantage over the close-in gas turbines. So the merchant coal and wind plants would have no incentive to build out transmission under a PTF model.
However, the grid expansion would also produce $1.4 billion in savings through avoided congestion. Spreading those credits among the 25,000 MW of new coal- and wind-fired generators would give them about $8/MWh. So, if those merchant coal and wind plants receive credits (CRRs) in exchange for participant funding, to allow them to capture the hedge value of the congestion savings, they (and ratepayers) would come out ahead by $3/MWh ($8-$5). That implies that CRRs might offer enough incentive to encourage a privately built grid.
Yet the danger always remains that private interests may figure out a way to get private assets built with public money.
The Planning Paradigm
Many industry players still oppose the PTF model and insist on a regulatory regime for transmission expansion and pricing that puts planning first, with markets a distant second. This interest group includes many utilities from the Upper Midwest. They fear that locational pricing will discourage exploitation of the region's bountiful potential resources in coal and renewable energy, and that the grid upgrades needed to bring such energy to market will not occur without top-down mandates. They feel that the benefits of fuel-mix diversity warrant a top-down planning policy. Moreover, they tend to oppose a strict license-plate pricing regime, as favored by RTOs, since it would impose high grid expansion costs on their own sparsely populated area. TRANSLink, for example, has proposed a combined, hybrid zone-and-highway pricing scheme to correct that problem. The RTO would not impose the high cost of grid expansion solely on the backs of ratepayers within the affected control areas (a license-plate rate), if benefits would extend beyond those areas. A "highway" charge would spread the upgrade cost throughout a broader region.
This view sees the grid not in terms of private property, but as a public resource. Listen to Leslie Stark, director of federal regulatory and legislative affairs at Southern California Edison:
"We do not agree that transmission owners and ITCs should sit back and wait to see where there's a market failure. … You need to have transmission planning conducted by regional transmission planning bodies, filled with transmission planners. ... I'm not saying that you ignore what's going on in the market. You will have merchant transmission. ...
"You will see generation projects being pursued … you will see demand response proposals … you will see distributed generation, but the transmission planner, at the regional body, ought to be cognizant of what's going on in the market, and then decide what specific transmission upgrades are necessary."
Stark reiterates that top-down planning can substitute for a market: "We're saying put [in] a transmission planner that takes into consideration what's going on in the market, but then goes off and defines the specific upgrades that need to be done. They ought to get on it and make it happen, OK?"
Back in the Southeast, they take these words to mean that congestion should be outlawed. In other words, if regulators really want to guarantee a perfect transmission grid, with prices the same everywhere, then why not pay for it with taxes, like we did for the interstate highway system, and just get rid of LMP and the SMD?
At Southern Company, policy and planning director Bruce Edelston says that socialized transmission pricing carries the seeds of its own demise. Edelston suggest that rolled-in pricing is the underlying cause of the problem seen in the South and Southeast, where merchant generators locate their plants on their own terms in the "wrong" areas, to take advantage of locational price differentials for the energy commodity. With rolled-in pricing, says Edelston, generators avoid coming to terms with the locational price disadvantage inherent in building generation far from load and forcing costly grid upgrades. That problem is simply socialized, at no added cost to the merchants.
The Technology Misfit
In the course of the debate at FERC over the SMD, perhaps the most telling argument against traditional, rolled-in transmission pricing, and in favor of a privately funded grid, has come, ironically, from the commission itself.
The argument centers around the new generation technologies-fuel cells, photovoltaics, and all manner of distributed generation alternatives. What happens if RTOs impose top-down planning, socialized costs and rolled-in rates on a new "generation" of utilities that instead dare to cast their lot with distributed generation (DG) technology, in an effort to avoid paying for costly grid upgrades? Will traditional rate-making force them to pay anyway?
In one conversation, FERC staffer Dick O'Neill, from the commission's Office of Markets, Tariffs and Rates, cross-examined TRANSLink CEO Audrey Zibelman, asking her how a small municipal utility would fare if it chose a high-tech DG strategy.
Zibelman had no ready answer for FERC, other than to concede that the small muni might have no option to escape paying higher grid charges, except perhaps to just "cut the wires." O'Neill countered that traditional rate policy for transmission would end up discriminating against innovative generation. (see Sidebar)
The issue, again, boils down to a simple truth. Generation and transmission are interchangeable-so much so that a policy applied to one (merchant competition for generation) must be repeated for the other to avoid arbitrage and market distortions.
In the end, the decision may come down to FERC Commissioner William Massey, now one of only three voting commissioners. If so, it appears that proponents of participant funding can count on him as a member of their camp.
"When I look at this issue," says Massey, "I look at it in the context of what I consider to be the centerpiece of standard market design, which is locational marginal pricing.
"It seems to me that all the working parts of the SMD ought to fit together in some cohesive way. And if the centerpiece is LMP, it seems to me that some sort of participant funding is more consistent with that."
Bruce W. Radford is editor-in-chief of Public Utilities Fortnightly.
Fuel Cells:
Deathknell for a Socialized Grid?
FERC Economist Dick O'Neill debates TRANSLink CEO Audrey Zibelman on the merits of regulated pricing for transmission in an age of competitive generation.
WASHINGTON, D.C.
NOV. 6, 2002
O'NEILL: Can I ask a question? I mean, suppose I'm a large muni [municipal utility] and I've dediced that I want to go Green. And so I make a huge investment in distributed generation and photovoltaics … and somebody says, we're going to build some transmission for your benefit, and I say, you known, I don't need it. I've put local generation in.
ZIBELMAN: Well, the question is, if you're that muni, have you just dropped of the regional tariff?
O'NEILL: No, but I want to be on the system, you know, for various reasons, but I don't need any new transmission investment. Instead of investing in transmission, you know, I've put in real-time meters; I've put in distributed generation; I have some fuel cells, you know, spread around my system, and I say I don't need transmission to satisfy my probloems.
ZIBELMAN: I guess my response would be that if you want to continue to be interconnected with the grid, then you're...
O'NEILL: You have to cut the wires … So your answer to me is, cut the wires, if you don't want to pay for the new transmission?
ZIBELMAN: My answer is yes, either you're part of the game or you're not, but you can't have it both ways....
O'NEILL: So that when generators supply reliability, that's privatized, and when transmission supplies reliability, that's socialized?
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