A prolonged August heat wave in Texas produced two periods of very high wholesale prices in the Electric Reliability Council of Texas (ERCOT), the wholesale market operator for most of the State. Day-ahead, on-peak wholesale power prices for August 2011 rose far above the range of prices seen during the previous five Augusts (see chart above).
The increase in wholesale prices may appear in retail bills more quickly in Texas than they would in other states, as Texas mandates that most retail customers choose a competitive electricity supplier – thus removing the traditional cost-of-service retail rate regulatory process which often delays the blow of high wholesale prices.
Several signals of market stress in Texas played out in August 2011:
The remainder of this article will elaborate on these points, as well as the level of generating capacity ERCOT holds in reserve against unexpected levels of demand or unexpected outages. The calendar below provides daily data for temperature, load, day-ahead electricity, and natural gas price data for Texas during the end of July and throughout August 2011.
The heat in Texas has been high, sustained, and widespread.
Coincident with the extreme heat was a period of extreme drought. While there have been no reported outages due to drought conditions, ERCOT staff raised it as a concern with their Board at the beginning of the summer. Drought was also noted as a concern in ERCOT in its Summer Reliability Assessment. For more information on drought conditions in the region, see http://droughtmonitor.unl.edu/.
Before August 2011, ERCOT's load record was 65,776 megawatts (MW) (recorded in 2010). In 2011, peak load exceeded that level on 15 days (see red days on the calendar above). ERCOT set a new all-time peak demand record on three consecutive days (August 1-3, 2011), culminating in a new all-time peak of 68,294 MW. This exceeds the prior year's record by 2,518 MW, or an increase of 3.8%. ERCOT likely averted another all-time peak demand record on the next day (August 4) by shedding 1,500 MW of interruptible load (from customers who agreed to emergency interruptions in exchange for a lower rate).
Hourly energy prices in ERCOT's day-ahead and real-time market rose to extremely high levels, reflecting the shortage of operating reserves. These reserves are generating capacity that the system operator holds at the ready to maintain reliability. Reserves are needed to withstand a sudden, unexpected loss of supply. The data below focuses on a single day in ERCOT's North Zone, which includes the Dallas-Fort Worth metro area, but the story is similar throughout ERCOT.
From 7:00 a.m. to 2:00 p.m. CDT, 15-minute real-time prices averaged $45/MWh. The "super peak" prices between 2:00 p.m. and 7:00 p.m. CDT averaged $1,937/MWh (see chart below).
Demand for electricity in summer typically peaks in the late afternoon. This is when the electric power system is under the most stress and may result in an increase in the 15-minute prices set in the real-time market. On five days in August 2011, real-time prices hit the market cap of $3,000 per megawatthour (MWh) (August 3-5 and 23-24), and approached it on several other days.
In February 2011, ERCOT had another supply shortage, resulting in price spikes in the real-time market on the first day and the day-ahead market on the following day. Unlike this August, the experience was short-lived. In August, the sustained extreme heat drove repeated spikes in the real-time market.
The expectation of a continuing supply shortage drove a rare sustained increase in prices in ERCOT's day-ahead market. In ERCOT's North Zone, hourly day-ahead prices for key afternoon hours exceeded $1,000/MWh for nine days (August 4-5, 8-10, 23-26, and 28-29) and reached $2,600/MWh twice (August 9 and 25). Average daily on-peak, day-ahead electricity prices (that is, prices for the 16-hour time block from hours ending 7:00 a.m. to 10:00 p.m. CDT on weekdays, excluding NERC holidays) exceeded $200/MWh on 11 days (August 3-5, 8-10, 23-26, and 29). They rose over $500/MWh on three days (August 5 and 8-9). Day-ahead, on-peak electricity prices during August reached record levels in ERCOT because of the influence of high prices during these super-peak hours averaged together with lower prices during other parts of the standard 16-hour on-peak period.
As a side note, ERCOT implemented a nodal, locational marginal pricing (LMP) market on December 1, 2010. Similar in design to other RTOs, ERCOT added, for the first time, a day-ahead energy market and an ancillary services market. Previously, the day-ahead price indices reflected bilateral trading.
The high prices of power were not the result of high natural gas or other fuel prices. Spot natural gas settlement prices at the Houston Ship Channel reported by the InterContinental Exchange fell from $4.25 per million British thermal unit (MMBtu) in early August to as low as $3.88/MMBtu on August 28. The average price for August 2011 has been only $4.05/MMBtu. At a price of $4.00/MMBtu, a fairly inefficient natural gas-fired combustion turbine with a heat rate of 12,000 Btu/KWh would be profitable at any price over about $50/MWh – less than a tenth some of the peak settlement prices in August.
As the very high prices suggest, scarcity of operating reserves has been a crucial factor through the heat wave. On various days during the month, ERCOT took several levels of emergency actions, including:
ERCOT successfully avoided the next level of action, which would have been rotating blackouts. On August 16, ERCOT executed short-term contracts to bring four generators back from "mothballed" status.
The under-forecast of peak loads combined with barely adequate reserve margin to create tight supply.
A 50/50 forecast in the North American Electric Reliability Corporation's (NERC) 2011 Summer Reliability Assessment (dated 6/30/2011) projected ERCOT's Net Internal Demand as equally likely to be either above or below 63,531 MW.
It also estimated Existing-Certain Capacity Resources and Net Firm Transactions as 73,969 MW. This yields a reserve margin of 13.9% for ERCOT in the summer of 2011. NERC's reference reserve margin level for ERCOT is 13.75%. (It is 15% for other U.S. regions.) This was the tightest supply projection of any NERC U.S. region or sub-region. ERCOT's projected summer 2011 peak demand has been exceeded on 27 days since late July.
ERCOT's limited interconnection with other power grids reduces its ability to seek help in supply shortage emergencies. Also, ERCOT's size limits its weather diversity, which during this heat wave has been very small. In contrast, the Midwest Independent System Operator, which dispatches about 146,000 MW of generating capacity, and the PJM Interconnection, dispatching about 180,000 MW of capacity, usually see significant differences in weather from west to east.
Earlier this year, ERCOT saw a short-lived set of price spikes in response to a cold snap that led to 7,000 MW of generator outages. During this event, up to 4,000 MW of load was shed in controlled rolling blackouts. This event set a new all-time winter peak demand. FERC and NERC conducted a six-month inquiry into the causes of this outage event. Please see the FERC and NERC Release Task Force Report on Southwest Outages (August 16, 2011) [Press Release] [Report] for more information.