Of the generating units currently in “mothball” status, meaning their owners have stopped production, with the Electric Reliability Council of Texas’ (ERCOT) approval, more than 900 MW of capacity is expected to return to service by summer 2013.
Another 1,130 MW of currently mothballed capacity is included in summer capacity totals because owners already committed to return those units to return for the summer 2013 peak season, ERCOT noted in a Dec. 10 statement. Under existing market rules, ERCOT may deploy other available mothballed resources if needed in an emergency situation.
A new long-term outlook released Dec. 10 by ERCOT indicates that the future outlook is improving, but the amount of electricity available for extreme temperatures or other emergencies may be below preferred targets by next summer.
“The projected reserve margin for summer 2013 has dropped slightly since May, but we are seeing healthier reserve margins in future years,” said ERCOT CEO Trip Doggett. “Although peak demand is expected to grow less quickly than previous economic predictions indicated, we should continue to encourage new generation and develop more demand response options to reduce our electric use during periods of highest use — the hottest hours of the hottest days of summer.”
The Capacity, Demand and Reserves (CDR) report anticipates the grid operator for most of the state will have 74,633 MW of power to serve anticipated peak electric use, or “load,” of 65,952 MW next summer.
The difference between expected power generation and peak demand reflects a reserve margin of 13.2% in summer 2013, slightly below ERCOT’s target. The ERCOT Board of Directors in 2010 selected a target reserve margin of 13.75% for the amount of electric generation capacity that exceeds the forecast peak demand on the grid, based on historical averages and other factors. Although this reserve margin is not required by ERCOT or the Public Utility Commission of Texas (PUC), ERCOT uses the target for reliability assessment purposes.
By 2014, projected reserves drop to 10.9%, below the target but an improvement from the prior CDR report released in May. The margin continues to decrease in future years, dropping to 2.8% by 2022, also an improvement compared to previous projections.
Warren Lasher, ERCOT’s director of System Planning, said that this outlook includes existing resources and additions that have already received required air permits and interconnection agreements with transmission providers. Resource owners typically do not complete the criteria required for CDR inclusion more than a few years before a resource is available for use in the ERCOT grid.
“While several entities have announced plans for new generation that is likely to come on-line in future years, those projects have not yet acquired the level of certainty required to be included in this report,” said Lasher. “The long-term outlook will change over time as new projects move forward.”
Electric use, the “load forecast” in the CDR, is based on a 15-year average weather profile, combined with economic factors such as per capita income, population, gross domestic product and various employment measures. For this CDR, ERCOT used a more conservative economic forecast than it used in the most recent report, due to slower economic growth seen in recent years.
ERCOT’s economic outlook is based on the “Low Economic Growth” forecast released in November by Moody’s Analytics. That forecast expects non-farm employment in the ERCOT region to grow by more than 2.5% in the next few years, a higher growth rate than has occurred in recent years but lower than other Moody’s forecast scenarios.
“Every economic scenario we evaluated included a significant increase in the 2014 to 2016 timeframe,” said Lasher. “When the next CDR comes out in May, we may need to adjust that outlook based on the economic trends at that time.”
Since the previous CDR from, projects totaling 2,360 MW have been removed from the long-term outlook due to changes in project status. Another 2,305 MW have been added, including 1,309 in new wind power projects, which are counted at 8.7% of their maximum capacity based on historical output.
The CDR anticipates 961 MW of new non-wind generation by summer 2013: 925 MW from Sandy Creek 1, a new coal-fired unit in McLennan County; and 36 MW from the NoTrees Battery, a new storage facility in Winkler County.
Some of the units included in the 2015 summer outlook could be available in time for the summer 2014 peak demand but are not included in the 2014 projections. New units being developed by Panda Power Funds in Grayson and Bell counties are expected to add 1,681 MW by summer 2015 and another 780 MW by summer 2016. Also by summer 2015, the Lower Colorado River Authority expects to begin operating a new 570-MW combined-cycle plant in Llano County, for a net addition of 216 MW when it retires an existing plant at the same site.
The Texas Clean Energy Project is slated to bring 240 MW of new coal-fired generation to the mix by summer 2016, and a new 1,380-MW gas-fired project could begin operations in Harris County later that year.
Monticello Units 1-2 in mothballs, but expected back by next summer
Since the May CDR, the following units entered mothball status:
- Monticello Units 1-2, coal, 1,130 MW, expected to return prior to summer 2013;
- Sam Bertron Units 1-4 and T2, gas, 765 MW; and
- AES Deepwater, petroleum coke, 138 MW.
The removed projects are:
- Coleto Creek 2, coal, 660 MW, cancelled;
- Las Brisas, petroleum coke, 1,240 MW, air permit revoked;
- RRE Solar, solar, 60 MW, suspended; and
- Baker Ranch, wind, 400 MW, cancelled.
The added facilities are:
- NoTrees Battery, storage, 36 MW;
- Ferguson Replacement, gas, 570 MW;
- Texas Clean Energy, coal, 240 MW;
- Goldthwaite Wind Energy, wind, 150 MW;
- Midway Wind Farms, wind, 161 MW;
- Moore Wind 1, wind, 149 MW;
- Conway Windfarm, wind, 600 MW;
- DC-R Tie, other, 150 MW; and
- Mesquite Creek Wind, wind, 249 MW.
The Lower Colorado River Authority has publicly announced that its Ferguson gas plant (354 MW) will be deactivated when the new Ferguson combined-cycle unit becomes operational in 2014, the CDR report noted. In addition, CPS Energy has publicly announced its plans to deactivate the two coal-fired J. T. Deely units (845 MW) by the end of 2018.
In August, a unit of Energy Future Holdings filed notice with ERCOT that it intended to suspend operations at two of the three units at the lignite-fired Monticello facility due to persistently low wholesale power prices and other market conditions. “Pending ERCOT approval, beginning December 1, 2012 we intend to suspend operations for approximately six months and not greater than seven months, with both units expected to return to service during the peak demand months in the summer of 2013,” said the company’s Oct. 30 Form 10-Q quarterly report. “Our mines will continue year round operations and there will be no reduction in our full-time work force as a result of this action.”
Monticello is an 1,880-MW plant fired mostly by lignite from the company’s nearby Thermo and Winfield mines, with some Powder River Basin (PRB) coal railed in to supplement the lignite.
In 2011, AES Deepwater was idled to mitigate operating risks caused by high fuel costs and other competitive pressures. Although the Deepwater unit was restarted during the second quarter of 2012 to capture potential summer price volatility, it shut down again early in the fourth quarter of 2012. “We currently plan to operate the unit again to capture the 2013 potential summer price volatility, although the long-term economic viability of the business is uncertain,” said the Nov. 7 Form 10-Q financial report of parent AES (NYSE: AES).