NERC ID's three regions for possible power shortages
By Staff -- Purchasing, 7/13/2000 2:00:00 AM
For two summers running, industrial companies operating on interruptible electric power rates have had to choose-for a matter of days-between ceasing their operations or paying exorbitant market rates for power during peak demand periods (read, heat waves). The 2000 Summer Assessment from the North American Electric Reliability Council (nerc) suggests more of the same this year, although the nexus of the problem has shifted away from Canada and the Midwest and into the Northeast, New York, and southwestern regions of the U.S.
Compared to last summer, nerc reports that "improvements have occurred in several areas including the Canadian province of Alberta, Illinois, Eastern Wisconsin, and Eastern Missouri where substantial amounts of new resources will be in service for the coming summer."
This year, the council says power companies in New York and New England have said they may not be able to meet generation reserve obligations during peak load conditions. While New England has added 1,000 MW of generating capacity since last summer, nerc suggests that the positive impact of these additions may be offset by three situations:
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Plattsburgh Phase Angle Regulator (PAR) failure which could result in a 100 MW reduction of transfer capability between New York and New England and a reduction of imports to New England from Hydro-Quebec from about 1,800 to 1,200 MW.
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Outage of Indian Point No. 2 nuclear plant (930 MW in the New York control area). The plant went down on March 10 and was due to return to service by mid-June. Continued outage at this plant would "reduce the ability to import electricity into New York City in addition to the loss of a large generation resource."
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Hudson Transformer failure (New York-PJM interface). One of two transformers will be out of service for the entire summer, reducing transmission capacity between PJM and New York by 200-400 MW (from 1,000 MW).
nerc suggests that both New York and New England are likely to require power from the open market at the same time. "The need for these purchases will vary and will be made more difficult if (1) generator unavailability is higher than expected, (2) weather is more severe than expected, (3) other transmission facility outages occur, or (4) generator maintenance outages are not completed according to current schedule." What's more, nerc says, "If hot weather ensues in a wide area of the Eastern Interconnection, as occurred last summer, the ability to acquire energy, or more importantly, emergency energy during a capacity emergency could be very challenging."
Meantime, in the Southwest, nerc says an extended or widespread heat wave could tax capacity in California. "Operating margins may be slim and thermal-loading problems may require curtailment of firm demand in Northern California, the San Francisco Bay area, and the San Diego area." What's more, voltage and voltage stability concerns could lead to curtailment of firm demand, during extreme conditions, for both the Fresno and Sacramento Valley areas, nerc says.
Overall, nerc expects peak demand to rise 1.7% in summer 2000 compared with last summer. It also assumes no problems with fuel supplies. "Fuel supplies, inventories, and deliveries are expected to be adequate this summer. For the three major Interconnections-Eastern, Western, and ercot (Texas)-nerc anticipates "adequate generating margins," but notes that "these margins do not indicate the distribution of resources within the Interconnection or the deliverability of those resources to generation-deficient areas."
At present, the council observes that the Eastern Interconnection is experiencing "new loading patterns" resulting from open transmission access. "Transactions are occurring in large numbers across long distances, and often in directions that were not anticipated when the transmission systems were planned and built." The upshot, according to nerc, is that the systems "may be operating in a previously unanalyzed state at some times," raising the possibility of "operational challenges to ensure that the system is not exposed to unacceptable risk."
Summer peak demand and resources by interconnection(MW unless specified)
| East (July) | West (July) | Ercot (August)* | |
|---|---|---|---|
Projected total internal demand |
564,303 |
132,528 |
55,319 |
(-) Interruptible demand and DCLM |
23,867 |
4,671 |
3,167 |
(=) Projected net internal demand |
540,436 |
127,857 |
52,152 |
Last summer's peak demand |
556,445 |
129,059 |
54,849 |
Change (%) |
1.4 |
2.7 |
0.9 |
Projected generating capacity |
621,170 |
159,134 |
61,706 |
(+) Interconnection tie capability |
1,850 |
1,080 |
785 |
(=) Net capacity resources |
623,020 |
160,214 |
62,491 |
Margin |
82,584 |
32,357 |
10,339 |
Capacity margin (%) |
13.3 |
20.2 |
16.5 |
* ERCOT is expected to peak in August vs. July for East and West interconnects |
|||
SOURCE: NERC |
Available margin capacity/(percent)
| NERC region | July | August | September |
|---|---|---|---|
|
United States |
|||
ECAR |
13.6 |
14.2 |
22.5 |
ERCOT |
17.4 |
15.5 |
23.2 |
FRCC |
15.6 |
14.3 |
18.1 |
MAAC |
15.3 |
19.7 |
27.8 |
MAIN |
16.7 |
18.0 |
31.3 |
MAPP |
13.8 |
15.9 |
23.7 |
NPCC |
13.9 |
17.7 |
25.4 |
SERC |
12.5 |
14.0 |
20.8 |
SPP |
11.4 |
10.8 |
20.6 |
WSCC |
17.4 |
18.5 |
24.3 |
|
Canada |
|||
MAPP |
24.3 |
22.7 |
26.8 |
NPCC |
27.6 |
29.2 |
24.9 |
WSCC |
35.5 |
35.0 |
35.6 |
|
Mexico |
|||
WSWCC-Mexico |
21.3 |
17.0 |
17.8 |
SOURCE: NERC |
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Available capacity margin equals the difference between available resources and net internal demand (total projected demand less interruptible demand and Direct Control Load Management or DCLM), expressed as a percentage of available resources. |
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