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Except for local reinforcements and new generation interconnections, few transmission construction proposals are moving forward.

There's plenty of talk about transmission, says Theo Mullen. "But real action on transmission construction is scant," he adds. "Conferences and reports abound. Projects of all sizes are being proposed. But, except for local reinforcements and new generation interconnections, few transmission construction proposals are moving forward. The vast majority of larger projects are stalled for lack of financial commitment."1

Furthermore, the amount of money needed for transmission investment will depend on which categories are considered (). Opinions vary widely on the severity of our transmission problems and the need for additional capital expenditures. Steve Huntoon and Alexandra Metzner suggest we need "a stable regulatory environment" to address the "myth of the transmission deficit."2 They believe new transmission needed for reliability purposes should be determined on a regional basis through existing institutions, and that transmission needed to relieve congestion should be built on a competitive basis when that is the most efficient solution to congestion. I, along with my earlier coauthor Brendan Kirby, believe that separating reliability from economic needs is very difficult and that substantial investments for both purposes are required.3 Others believe that serious transmission problems exist but can be addressed in large part with nontransmission solutions, in particular dispersed generation and demand management.4

Historical Data: Looking at the Numbers

For the past few decades, the Edison Electric Institute (EEI) has collected and published data each year on the number of circuit miles of transmission lines in the United States.5 Since 1989, the North American Electric Reliability Council (NERC) has published similar data.6 Together, these two data sets provide a long historical record on the amount of transmission capacity available to move electricity from generators to distribution systems.

Although these data sets contain much useful information, they suffer from data-quality problems. For example, the NERC data show several occasions when the transmission mileage in a region drops from one year to the next. Almost 20 percent of the year-to-year changes in historical transmission mileage show declines. It is highly unlikely that a utility would retire a line from service rather than replace the conductors or towers with newer ones (perhaps with higher voltage and MVA ratings).

In addition to data-quality issues, multiple issues () complicate the interpretation of this data. In particular, the location of generating units relative to load centers has an enormous effect on the need for transmission. Also, not all transmission facilities add mileage to the system; devices such as transformers, capacitor banks, breakers, meters, and communication systems are important elements of the grid.

The NERC data from 1989 through 2002 and the EEI data for the earlier years allow for the development of a record of transmission capacity (in both circuit miles and megawatt-miles); see top part of Fig. 1.7 Utilities added transmission lines at a much higher rate during the first four years of this period than during the following 20 years (3.8 percent versus 1.2 percent per year).

Normalized capacity figures by peak demand are shown at the bottom part of Figure 1. Normalized transmission capacity increased from 1978 through 1982 and then declined steadily through 2002. Between 1978 and 1982, normalized transmission capacity (as measured by megawatt-miles/megawatt of demand) grew at an average annual rate of 3.3 percent; during the following 20 years, normalized transmission capacity declined at a rate of 1.5 percent per year. (The numbers for transmission miles per gigawatt of demand were similar: +2.6 percent/year for the first four years and -1.6 percent/year for the next 20 years.)

EEI collects data on annual investments in transmission facilities for investor-owned utilities.8 As shown in Figure 2, there was a steady decline in construction of new transmission facilities from 1975 through 1999, with substantial increases during the final four years (2000 through 2003).9 These results are shown in real (corrected for inflation) 2003 dollars, using the Handy-Whitman Index of electric-utility transmission costs to adjust for inflation from year to year. Between 1975 and 1999, investment fell at an average rate of $83 million per year; from 1999 through 2003, transmission investment increased at an average annual rate of $286 million, a substantial reversal of trends. The average level of investment for the last four years was $3.6 billion, 34 percent higher than the average for the prior four years ($2.7 billion). It is not clear what accounted for this reversal of trends or whether the change is temporary or long-term.

These trends in transmission capacity and investment are reflected in bulk-power operating data.10 The number of times system operators in the Eastern Interconnection called for Level 211 or higher transmission loading relief (TLR) increased from about 300 in 1998 and 1999 to more than 1,000 in 2000 and 2001, with jumps to 1,500 in 2002 and almost 2,000 in 2003 (see Figure 3). Over a five-year period, the need to curtail power transactions or deny requests for new transactions increased by a factor of six.

Current Conditions

NERC issues summer and winter reliability assess- ments, as well as a 10-year assessment each year.12 Table 1 summarizes the transmission issues noted in each region's report to NERC for the 2003 Summer, 2003/2004 Winter, and 2003-2012 reliability assessments.

The table shows considerable variation among regions in the status of their transmission systems. Some regions, such as the Florida Reliability Coordinating Council (FRCC), Mid-Atlantic Area Council (MAAC), Southeastern Electric Reliability Council (SERC), and Western Electricity Coordinating Council (WECC) report no serious problems. Others, however, note episodic or ongoing problems. For example, imports to southwestern Connecticut remain a serious and perhaps long-term problem in New England. The Electric Reliability Council of Texas (ERCOT) faces problems moving the output from generation to the growing urban loads in Dallas-Ft. Worth and Houston. However, ERCOT, unlike some other regions, is able to plan and build new transmission facilities in a timely fashion.13 Imports from the Mid-Continent Area Power Pool (MAPP) to Wisconsin (Mid-America Interconnected Network) remain a critical concern. Curiously, not one of the Northwest Power Coordinating Council (NPCC) reports mentions the transmission constraints for imports to New York City and Long Island.

Projections of the Future

Each year, as part of its annual reliability assessment, NERC issues its . This database shows planned transmission-line additions for each of the following 10 years, from 2003 through 2012 for the latest version (see Figure 4).

The projections are consistent with the historical data: Both show continuing declines in normalized transmission capacity. Between 1992 and 2002, 9,600 miles (7,300 GW-miles) of transmission were added; between 2002 and 2012, an additional 10,400 miles (10,300 GW-miles) are expected to be added.

Although normalized transmission capacity declined by almost 19 percent between 1992 and 2002, it is expected to drop by only 11 percent during the following decade (2002 to 2012). In other words, transmission capacity is expected to continue to decline during the coming decade, but at a slower rate than during the past decade.

The NERC data and projections show results for each of the 10 reliability regions as well as for the United States as a whole (see Figure 5). Between 1989 and 2002, normalized transmission capacity declined in all 10 regions by amounts ranging from 14 to 27 percent. The largest declines (more than 25 percent over this 13-year period) occurred in SERC and NPCC. The smallest declines (less than 20 percent) occurred in MAPP, Southwest Power Pool (SPP), and WECC.

Over the next 10 years, normalized transmission capacity is expected to vary from +2 percent (NPCC) to -18 percent (FRCC) across the regions. All but one region (NPCC) projects declines in normalized capacity, with the largest drops (more than 15 percent) expected in MAAC, MAPP, and FRCC.

Because the individual transmission-owner reports show that almost 70 percent of the new transmission lines are to be built during the first five years of this 10-year period, the projections for 2007 might be more meaningful than those for 2012. Between 2002 and 2007, normalized transmission capacity is expected to vary from +8 percent (NPCC) to -10 percent (MAPP). Three regions (ERCOT, SPP, and NPCC) show expected increases for this initial 5-year period, while four regions (SERC, MAAC, FRCC, and MAPP) show declines of 5 percent or more.

Of the 416 transmission projects planned for the next 10 years,14 95 percent are shorter than 100 miles, with an average length of only 18 miles. These numbers suggest that most planned transmission projects are local in scope and are not intended to address large regional issues. The 21 longer projects (5 percent of the total) average 170 miles in length.

Table 2 shows growth in transmission capacity and summer peak demand for three decades: 1982-1992, 1992-2002, and 2002-2012. Although transmission capacity increased during each decade, growth in peak demand was always greater. The gap between the two growth rates was greatest during the middle decade (a 2.1 percent per year decline in megawatt-miles/megawatt demand versus 0.9 percent and 1.1 percent declines in the first and third decades).15 These trends are roughly consistent across all 10 reliability regions. This planned reduction in the transmission-capacity gap combined with the recent increases in transmission investment (see Figure 2) offer some optimism about the future of transmission capacity in the United States.

Interpreting these trends is difficult because details on the types of transmission construction and the problems these investments are meant to solve are not available. While I consider these trends troubling, others might view them as an indicator of increased efficiency of transmission usage or a consequence of the recent construction of gas-fired generation close to load centers.

This data and these projections provide useful indicators of the state of transmission grids in the United States. However, they are not necessarily accurate measures of transmission adequacy because of the factors listed in the sidebar on page 53. Unfortunately, no better regional and national information on U.S. transmission systems exists.

Other analyses indicate that the transmission investments planned for the next several years may not even be enough to replace today's aging infrastructure, let alone meet growing demand: "The evidence suggests that investor-owned utilities have reduced transmission and distribution spending to bare-bones levels, that spending will have to rise significantly in the near future in order to meet the needs of customers, and that the higher level of spending will trigger rate hike filings in order to cover the costs of the new capital."16 And U.S. transmission investment as a share of electric revenue declined from 10 percent in 1970 to 6 percent in 1975, 4 percent in 1980, and just over 1 percent from 1985 through 2000.17

Given the value of this NERC and EEI information, more time and attention should be devoted to ensuring complete reporting by all transmission owners, expanding the data collected to cover facilities that add capacity but do not add mileage to the transmission system, verifying the accuracy of the data, analyzing it, and reporting the results of these analyses. Although the Energy Information Administration (EIA) and FERC collect data on past and projected transmission facilities, neither cleans the data nor publishes summaries. This situation should change even though tight budgets limit what can reasonably be done. EIA proposes to expand its data collection on Form EIA-412 to include "transmission system upgrades" on existing lines (, reconductor line, install dynamic thermal rating, install capacitors, or install reactors) and terminal stations (, transformer, bus bar, protection system, or switchgear).18

Endnotes

  1. T. Mullen, "Is $27.5 billion enough?" , 4, Fall 2003.
  2. S. Huntoon and A. Metzner, "The Myth of the Transmission Deficit," 141(20), 28-33, Nov. 1, 2003.
  3. E. Hirst and B. Kirby, , Edison Electric Institute, Washington, D.C., June 2001; U.S. Department of Energy, , Washington, D.C., May 2002. E. Hirst and B. Kirby, Letter to the Editor, 141(22), 12, December 2003.
  4. D. White et al., "The 2003 Blackout: Solutions That Won't Cost a Fortune," 16(9), 43-53, November 2003.
  5. Edison Electric Institute, , Washington, D.C., May 2003.
  6. North American Electric Reliability Council, , Princeton, N.J., November 2003.
  7. These values are as of Dec. 31 for the year stated, , from the end of 1989 through the end of 2002.
  8. Investor-owned utilities own about three-fourths of the total U.S. transmission grid, with municipal, federal, and rural cooperative utilities, and transmission-only companies owning the rest.
  9. Data for the last three years are from NERC.
  10. North American Electric Reliability Council, "Transmission Loading Relief Procedure Logs, Trend Charts,"
    ftp://www.nerc.com/pub/sys/all_updl/oc/scs/logs/trends.htm, Princeton, N.J., accessed Jan. 18, 2004.
  11. NERC has six levels of TLR, ranging from 1 (least severe) to 6 (emergency conditions). Level 2 requires the system operator to "hold Interchange Transactions at current levels to prevent Operating Security Limit violations." Higher levels restrict nonfirm transactions first and then, if necessary, firm transactions.
  12. North American Electric Reliability Council, , Princeton, N.J., May 2003; North American Electric Reliability Council, 2003/2004 Winter assessment, Princeton, N.J., November 2003; North American Electric Reliability Council, 2003-2012 Reliability Assessment, Princeton, N.J., December 2003.
  13. According to Jones (personal communication, Electric Reliability Council of Texas, Taylor TX, February 2004), "ERCOT is very active in improving its transmission infrastructure and has added over 700 miles of new 345 kV and 200 miles of 138 kV transmission in the past three years. Many more miles are now in the construction and certification phase."
  14. Only seven of these projects are retirements, with a total of only 220 miles of transmission lines to be retired between 2002 and 2012. Even if transmission lines have a 50-year lifetime, at least 2,500 miles would be retired each year (or, more likely, replaced with newer facilities using the same right of way). The unreasonably small number of retirements is another indication of data-quality problems.
  15. Projections of new transmission capacity have traditionally been optimistic, overstating the construction that actually occurred.
  16. L.S. Hyman, "The Next Big Crunch: T&D Capital Expenditures," , 86!93, R.J. Rudden Associates, Hauppauge, N.Y., January 2004.
  17. T. Boston, personal communication (citing a study done by the Electric Power Research Institute), Tennessee Valley Authority, Chattanooga, Tenn., April 2004.
  18. Energy Information Administration, "Agency Information Collection Activities: Proposed Collection; Comment Request," 69(64), Washington, D.C., April 2, 2004.

Transmission Infrastructure: How Much To Invest?

How much should we invest in the U.S. transmission grid to meet the needs of our growing economy? Estimates range from $27 billion over the next several years1 to $50 or $100 billion during this decade.2 The answer to this question is fraught with difficulties, including:

More broadly, new transmission can be built for different purposes, including:

Endnotes

  1. A.B. Richardson, "$27.5 billion of new transmission projects planned,", 10-15, Fall 2003.
  2. "[Department of Energy] Secretary Spencer Abraham suggested ... that $50 billion in new transmission system investment is needed. Others have suggested that the total amount needed is over $100 billion" (D. White et al., "The 2003 Blackout: Solutions That Won't Cost a Fortune," 16(9), 43-53, November 2003.

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