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The grid does not need a Marshall Plan for new investment.

We don't know what caused the Aug. 14 blackout, but somehow we know that our transmission system needs $50 billion to $100 billion in investment and upgrades. And utilities need higher returns to raise that kind of money. Talk about making lemonade out of lemons.

The reality is that we aren't short $50 billion or $100 billion in our transmission system. The study said to support that proposition just doesn't do the job.

The commonly cited signs of trouble-frequency of calls for transmission loading relief (TLRs) and magnitude of congestion cost-do not support any particular level of new transmission. The TLRs that curtail firm transmission are few and far between. Congestion cost is a measure of energy price differences-not an automatic mandate for more transmission.

Instead of macro estimates for new transmission, we need regulatory structures that will give the right micro answers to two questions: What new transmission is needed to sustain reliability? What new transmission is needed for economic purposes?

The need for -based transmission has been, and should continue to be, the focus of micro, bottoms-up analysis by the regional reliability councils. A stable environment for the systematic determination of need to sustain reliability will have no problem attracting capital on a traditional, regulated basis.

The need for -based transmission should be determined by the market. So long as transmission is enabled to compete with other solutions, capital will flow to the most efficient approach.

Where Did the Huge Numbers Come From?

The lights scarcely were back on after the August blackout before conventional wisdom said that our transmission system needs $50 billion or more. This was the unchallenged sentiment in the early rounds of talk shows and news stories.1 Industry raised the ante to $100 billion.2

Amazingly enough, we knew the solution to the blackout before we knew what caused it.3

Where did these huge numbers come from? The $50 billion number seems to come from a June 2001 study by Eric Hirst and Brendan Kirby, sponsored by the Edison Electric Institute (EEI).4 Hirst himself has cited this study in subsequent reports,5 as have other EEI studies prepared by other EEI consultants,6 and reports issued by the Department of Energy.7 Thus, the conventional wisdom-that this county's transmission system needs a $50 billion boost-was born.

Let's take a look at how that figure originally was determined. The June 2001 Hirst study consists of some back-of-the-envelope work that went something like this. Assume that the 1999 ratio between megawatt-miles of high-voltage transmission lines and megawatts of peak demand is the ideal value. Given that ratio, the projected growth in peak demand, from 681 GW in 1999 to 813 GW in 2009 (2 percent per year), implies a need for 54,000 GW-miles of new transmission by 2009 (with 27,500 GW-miles replacing retired transmission lines and 26,600 GW-miles being incremental new transmission capacity).

The study concludes that at an average cost of $1 million/GW-mile, the required capital for new lines is $56 billion. Hirst then contrasts this $56 billion figure with the $35 billion that he estimates utilities are already planning to spend over the next 10-year period (which he derives from an estimate of retired transmission lines to be replaced, plus new capacity that utilities plan to build). This leaves a $21 billion gap between the estimated need, $56 billion, and the estimated plan over the next 10 years, $35 billion. This $21 billion gap is the figure that EEI once promoted as the amount of extra investment needed for the transmission grid.8

The discerning reader will have noted that under this Hirst analysis we are not $50 billion or $100 billion short in transmission investment at this time. Instead, we are projected to be $21 billion short by 2009. Assuming the gap opens at the same amount each year, Hirst was forecasting a $2 billion per year shortfall in capital investment. The revenue requirement effect is perhaps $300 million in year one, twice that in year two, etc. Not chump change, but not big bucks either.

Somehow that $2 billion per year deficit became $50 billion needed now, and then $100 billion needed now.9

Is There Any Deficit at All?

But is there even an emerging $2 billion per year deficit that requires new transmission policies? The case for this is far from proved.

Each of the propositions in the case is open to question. It is far from certain that a reliable transmission system is predicated upon maintaining the 1999 ratio between megawatt-miles of transmission line and megawatts of peak demand, or that peak demand will increase by the forecasted 2 percent annually, or that utilities need a higher return to build more transmission lines.

Why? In the 1970s and 1980s utilities built a large number of nuclear generating units to meet projected peak demand. Each of these nuclear units required substantial new transmission lines to transport the power from the nuclear units located in predominantly rural areas to load centers. This phenomenon gave rise to extensive new transmission proportionate to new nuclear generation (and to a lesser extent new coal generation).10

Today, however, new generation tends to be natural-gas fired. These natural gas plants are usually located closer to load centers and closer to existing transmission lines and networks. Because of this proximity, these new plants do not require new transmission lines to the same extent their earlier nuclear and coal siblings did. The gas plants' new interconnecting lines are not anything like the transmission lines that were required to interconnect rural nuclear and coal plants in prior decades.

Given that new plants require fewer transmission lines to interconnect, one would expect a gradual decline in the ratio of transmission lines to peak demand simply because the generation-related driver of new transmission is declining.11

In addition to the physical efficiency phenomenon surrounding new gas-fired plants, the raw data collected from utilities concerning transmission line development may be painting an inaccurate picture of the physical reality of new transmission construction. For example, it is not clear whether utility-forecasted investment in new transmission is considering transmission built by or for merchant generators. If that is not happening, then it is possible that the transmission lines associated with new generation that used to be recorded as transmission plant on the utilities' books are no longer being recorded there. Not because the transmission isn't being built, but because others, such as merchant generators, are building this transmission (or at least paying for it).

PJM seems to be an example of this phenomenon. The latest transmission expansion plan calls for more than $700 million of new transmission. Of that $700 million, merchant generators will pay more than $500 million.12 If the generators' $500 million is not being included in utilities' forecast of transmission spending, then a major chunk of new transmission investment is being missed.

Next, let's look at the peak-demand forecast. This is another possible source of inaccurate transmission-need assessment. The drumbeat for new transmission now is reminiscent of the drumbeat for new generation that started several years ago. The kick-off for that was a famous, or infamous, Forbes article by Peter Huber and Mark Mills, predicting an insatiable new demand for electricity caused by the Internet revolution (more PCs, more servers, etc.).13 That drumbeat helped propel the enthusiasm of Wall Street for new generation-and the rest, as they say, is history.

Finally, let's assume for the sake of argument that we do need substantially more transmission than that being planned. Do utilities need a higher rate of return to build it? Authorized rates of return at 11 and 12 percent already seem hefty for a low-risk investment.14 And the industry did not in the past claim these returns as a barrier to specific projects; instead, the industry has cited regulatory uncertainties and the familiar NIMBY problem15 (including the inherent reluctance on the part of states to authorize new lines from which they derive no benefit).

What We Need

If we do not have a huge transmission deficit requiring huge new investment and incentives, what do we need to secure the reliability and efficiency of the nation's transmission system in the wake of the August blackout? We need a stable regulatory environment that identifies and delivers reliability-based infrastructure on a timely and rational basis, and that enables efficient responses to market forces.

Consider first the reliability needs for new transmission. The process of determining reliability requirements is a well-established one. The North American Electric Reliability Council (NERC) and the regional reliability councils prepare a 10-years-out reliability assessment every year that includes an assessment of future transmission reliability.16 The reliability assessment includes each region's own analysis, with specific needs for new transmission facilities.

How these transmission needs are addressed is more complicated. The traditional approach of voluntary cooperation among utilities to get needed new transmission built may evolve somewhat if reliability standards become mandatory. The new RTO approach identifies, plans, and builds reliability-based transmission on a coordinated basis involving all stakeholders. The traditional and the RTO approaches both rely on a bottoms-up needs assessment-not the macro-trend analysis debunked above.

Beyond transmission needed for reliability, how can we determine what is needed for economic reasons? Where markets do not exist we will continue to rely on non-market-based institutions to identify, develop, and build new transmission. Where markets do exist and congestion costs are made explicit, the solutions will be market-based. New generation will compete with new transmission, which will compete with demand-side responses.

Our transmission system is not short $50 billion or $100 billion. What we need is a stable regulatory environment that identifies and installs reliability-based infrastructure on a timely and rational basis, and that lets market solutions compete to build whatever new transmission makes sense for economic reasons.

Endnotes

  1. (CBS television broadcast, Aug. 17, 2003).
  2. See John J. Failka, "Power Industry Sets Campaign to Upgrade Grid," . Aug. 25, 2003, at A3 ("The nation's electric power industry … is preparing to launch a public-education campaign to help it raise $100 billion from investors, governments and consumers to upgrade the nation's power grids.").
  3. The Joint U.S.-Canada Task Force does not expect to issue even a preliminary report before the end of the year, and the North American Electric Reliability Council will not issue its report until mid-2004. See "Blackout 2003: How Did It Happen and Why?" Hearings Before the House Committee on Energy and Commerce, 108th Cong. (Sept. 3, 2003). One voice in the wilderness has been Bruce Radford, publisher and editor-in-chief of . In May 2003 he wrote, "Where is the proof that the electric utility industry needs more investment in electric transmission? Is it not possible that we already have enough miles of high-voltage line?" Bruce W. Radford, "Grid Glut?," , May 2003, at 4.
  4. Eric Hirst and Brendan Kirby, "Transmission Planning for a Restructuring U.S. Electricity Industry," June 2001, available at: http://www.eei.org/industry_issues/energy_infrastructure/transmission/transmission_hirst.pdf.
  5. See, , Eric Hirst, "Expanding Transmission Capacity: A Proposed Planning Process," Feb. 2002, available at: http://www.ehirst.com/PDF/PlanningProcess.pdf; Eric Hirst, "Transmission Planning and the Need For New Capacity," Dec. 2001, available at: http://www.ehirst.com/PDF/TXPlanningNTGS.pdf;
  6. See Roger W. Gale & Mary O'Driscoll, "The Case for New Electricity Transmission and Siting New Transmission Lines," at 16, Sept. 2001; Stanford L. Levin, "Electricity Competition and the Need for Expanded Transmission Facilities to Benefit Consumers," at 10, Sept. 2001, available at: http://www.eei.org/industry_issues/energy_infrastructure/transmission/transmission_series.htm.
  7. See U.S. Dept. of Energy, "National Transmission Grid Study," at 7 and 50, May 2002, available at: http://tis.eh.doe.gov/ntgs/gridstudy/main_screen.pdf
  8. Edison Electric Institute, "Energy Infrastructure: Electric Transmission Lines," at 2 (last visited Sept. 25, 2003), available at: http://www.eei.org/industry_issues/energy_infrastructure/transmission/infrastructure2.pdf.
  9. The origin of the $100 billion figure is murky. The , supra, note 2, attributed this figure to the industry, which in turn relied on a report released by the Electric Power Research Institute in August of this year titled, "Electricity Sector Framework for the Future" ("EPRI report"), available at: http://www.epri.com/corporate/esff/. However, this EPRI report has no $100 billion figure; the closest thing is a reference to an October 2002 estimate by "energy analysts at the Oak Ridge National Laboratory" of a $56 billion need in this decade (EPRI report, Volume II, p. 30). It turns out that this reference is to an article in the October 2002 issue of the written by Hirst and Kirby, "Expanding Transmission Capacity: A Proposed Planning Process," Vol. 15, p. 54, which is citing their own 2001 study.
  10. One can "eyeball" this by looking at a map of transmission systems. An example is a map of the PJM Interconnection LLC transmission system, where one can readily see that many of the 230-kV-and-above transmission lines are connecting nuclear and coal generating units.
  11. Hirst acknowledged a similar proposition in an earlier study, namely that if transmission and generation are correlated then it may be appropriate to "normalize" the trend in transmission capacity with generating capacity. When he did that, a downward trend in transmission disappeared: "Normalized by generating capacity, transmission capacity increased by about 2 percent per year between 1978 and 1984 and then remained essentially unchanged from 1984 through 1998." Eric Hirst, "Expanding U.S. Transmission Capacity," at 5, August 2000. This thought in the August 2000 study was missing from the June 2001 study.
  12. W. Scott Miller III, "A Call for Reason," , June 1, 2003, at 12.
  13. Peter Huber & Mark Mills, "Dig More Coal-the PCs are Coming," Forbes, May 1999, available at: http://www.forbes.com/forbes/1999/0531/6311070a.html. There is a fascinating e-mail exchange between Mark Mills and Amory Lovins that followed the article, available at: http://www.rmi.org/images/other/E-MMABLInternet.pdf. By the time Mills broke off the dialogue in September 1999 it was pretty clear that the Forbes article had been skating on thin ice. And subsequent research confirmed that, showing, for example, that Mills had assumed average PC electric load at 1,000 W when measured data was more like 135 W. Lawrence Berkeley Labs, "Research Finds Computer-Related Electricity Use to be Overestimated," Press Release, Feb. 1, 2001, available at: http://www.lbl.gov/Science-Articles/Archive/net-energy-studies.html. But by then it was too late-the conventional wisdom had set in.
  14. See "Blackout 2003: How Did It Happen and Why?" Hearings Before the House Committee of Energy and Commerce, 108th Cong. (Sept. 3, 2003) (statement of Secretary Abraham) (finding it difficult to explain why an 11 to 12 percent rate of return on transmission investment is not sufficient and explaining that regulatory uncertainty is actually the bigger hindrance to transmission investment).
  15. The NIMBY problem is the "not in my backyard" sentiment.
  16. The most recent annual report is Reliability Assessment, 2002-2011, October 2002, available at ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/2002ras.pdf. The overall transmission assessment is at pages 20-22.

TLRs and Congestion: Signs of Trouble?

Beyond the decline in the rate of new transmission additions, the case for a transmission deficit relies on other alleged signs of trouble. None bear out.

In his 2001 study, Hirst cited an increase of more than 200 percent between 1999 and 2000 in the number of calls for transmission loading relief as evidence of a transmission deficit. For starters, Hirst was looking at the wrong universe of TLRs-level 2 and above. Anything less than level 5 is not a curtailment of firm service. Non-firm service is purchased with the expectation that it can and will be cut when necessary; market participants fully understand this. TLRs below level 5 do not cause a reliability problem.1

When TLRs of level 5 and above are examined, there are few calls for relief. For example, in 2001 there were only 28 calls in this group, 27 in 2002, and 34 so far in 2003.2 It should be understood that these TLRs affect a minuscule percentage of all lines, curtail a minuscule percentage of transactions, and occur a minuscule percentage of the time. In addition, the bulk of the level 5 and above TLRs occurred on the systems of just two reliability coordinators, the Midwest Independent System Operator and the Southwest Power Pool. These insignificant events do not imply a need for an enormous increase in transmission lines across the entire country.

Hirst also points to transmission congestion costs as a symptom of an ailing transmission system, citing a study that reports congestion costs in 2000 to be $800 million in PJM, the New England Independent System Operator, the New York Independent System Operator, and the California Independent System Operator. EEI also claims there is "tremendous congestion" throughout the country.

These claims reflect a fundamental misapprehension of the import of congestion. Congestion occurs whenever lower cost energy does not reach all potential load-thus creating a price differential between area A, the exporting area, and area B, the importing area. There is, in that sense, tremendous congestion all across the country as price differentials abound. Some of that congestion is caused by physical constraints of the system, but some is not physical at all (arising from non-integrated and inefficient dispatch of electricity, pancaked transmission rates, etc.).

Congestion costs do not equate to reliability problems. Assume there is coal-fired generation in area A that from time to time exceeds demand in area A, but where the excess cannot reach area B due to a transmission constraint. Assume also that area B has plenty of oil-fired generation (no reliability problem). This is an example of congestion cost-a simple price differential between areas A and B-but no reliability problem.3

Only regional transmission organizations (RTOs) report congestion costs as such, which gives rise to the common misconception that creating an RTO creates congestion. Of course, creating an RTO that reports congestion costs does not create congestion but only makes known what was not known before and assigns the additional (marginal) cost to those areas that require the higher-cost energy.4 This identification of congestion costs allows for efficient responses. The response can be to do nothing (if the solution is more costly than the congestion), to build more transmission, to build more generation, or to reduce demand.

With this background, we can see that neither TLRs nor congestion costs support a conclusion that there is too little transmission capacity. The relevant TLRs are simply too rare in occurrence and limited in scope to translate into a generic need for more transmission. The reported congestion costs are only price signals that enable efficient responses.

Endnotes

  1. It can be contended that increased non-firm TLRs simply reflect more aggressive sale of available transmission capacity, and thus greater use of the grid. The greater use of non-firm service wrings the maximum efficiency out of the system.
  2. Compiled from monthly summaries on the NERC Web site, http://www.nerc.com/~filez/Logs/index.html.
  3. Another way to look at it is that in a reliable system there is always a set of fuel prices for which congestion is zero, i.e., it is all about economics.
  4. A good example of this is the increase in reported congestion in PJM that arose from the addition of Allegheny Energy as PJM West. With integrated dispatch, efficiency increased from what it was before. But PJM's reported congestion went up with Allegheny now part of PJM. See , p. 103. It is also important to distinguish gross congestion cost from net congestion cost (net being the congestion cost to load that is not hedged by fixed/financial/firm transmission rights [FTRs]). Taking PJM as an example, gross congestion cost was $430 million in 2002, , at 101, but net congestion cost was $115 million, W. Scott Miller III, "A Call for Reason," , June 1, 2003, at 14.

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