Interval data meters provide wholesale and distribution utilities information that can help them operate their systems economically in today’s increasingly competitive electric markets. The Lower Colorado River Authority (LCRA), a wholesale power supplier serving public power and one investor-owned utility in Central Texas, assists 33 of its customers -- and its own internal operations -- with metering and meter data services for major accounts.
De-regulation in Texas does not require public power utilities to participate in the competitive retail market, and to date only one of LCRA’s customers has chosen to do that. Also, legislation prohibits LCRA from owning or operating retail facilities or seving retail customers. Faced with the possibility that any customer’s board may vote to “opt in” to competition and open its consumers to other
generation providers, LCRA has developed a Key Accounts program affording its customers metering, meter services, and daily data collection and Web presentation of meter data. Daily meter reading helps detect failed equipment before it can cause operational or revenue problems. Interval data also provides information that helps LCRA’s managers address power plant and irrigation system operations.
LCRA’s staff and manages interval data from two discrete MV-90 meter reading and data translation systems. First, LCRA has its own MV-90 data translation system for its substation-based wholesale billing meters. Second, it uses Hunt Power, in Arlington, Texas, to read approximately 300 electric meter-recorders daily for its wholesale customers’ key accounts. After retrieving data with its MV-90 system, Hunt Power verifies its accuracy and posts the data to its PowerPriceTM Web site. Each participating consumer and wholesale customer has access to its own secure site showing data current through the early morning of each day. LCRA’s staff, then, has access to interval data for approximately 600 wholesale and another 300 retail meters, to assist internal and external customers with billing, metering, and other operational questions.
Phantom MW
One of the most perplexing of those questions arose not long after the Texas electric market began its competitive retail operations. In setting up the market, Texas’ system control operator, the Electric Reliability Council of Texas (ERCOT) concluded that all generators in the system must be metered to record their generation and consumption. And as with all loads of one megawatt or greater, the power plant meters record data at 15-minute intervals. Both ERCOT and the entities responsible for installing and maintaining the plant recorders read them and net their production against their consumption for each of 96 daily intervals. Plant owners are credited with net generation and billed for net consumption.
During normal maintenance of an LCRA coal-fired plant, staff retrieved data from the plant’s meters during an outage to trace generation shutdown and ensuing operation. Plant meters in ERCOT uniformly record consumption on channel one and production on channel four. At the beginning of the shutdown, data from channel four predictably showed a rapid drop to zero as data for channel one -- power in to the plant – showed a sudden rise to a plateau of about five megawatts (MW).
Six hours into the repairs, channel four began registering about three megawatts steadily. This curve made no sense: How could a dismantled turbine be generating electricity? The load curves perplexed plant managers. After reviewing the data, they called the plant electrician, who investigated the anomaly and found that the ground cables, two for each of three phases in the switchyard, produced electromagnetic fields that the lines’ current transformers sensed as active generation, recorded in the meters as generation. The plant crew moved the cables and the meter channel fell to zero. Only because of the new market did the mystery megawatts matter. ERCOT would see the load and credit LCRA with generation that didn’t occur. The sum was too small to affect the system, but it did show that traditional maintenance had to be changed owing to a new and different set of measurement.
“What the Hey, a Light Bill?”
Billing power plants presented a new challenge, too. Under ERCOT rules, plant metering is the responsibility of the transmission and distribution service provider (TDSP). At LCRA, a transmission affiliate manages substations, where LCRA transfers the ownership of power to its distribution customers. It is there that LCRA measures wholesale power sales for billing. So when the re-regulated market approached, LCRA staff decided to treat power plants as substation billing points subject to a specific power plant price and the associated transmission tariffs. The plant bills are included in the appropriate wholesale customers’ monthly wholesale power bills. The customers recover their costs by billing the plants for the full generation and transmission costs and a nominal distribution charge.
Almost overnight, plant managers saw traditional parasitic loads turned into monthly power bills. They’d never seen a retail power bill, and yet now they had to pay demand, energy, and transmission charges.
The plants became a set of new, internal customers, so staff worked to educate operators about billing. Controlling electric use was not new to the plant managers, for starting in the mid-1990s they’d established procedures for shedding internal systems during summer peak hours to reduce their plant consumption and increase output. By subscribing to a power plant indexing service, the managers of LCRA’s coal-fired plants mangers track their plants’ parasitic loads against similar units around the nation and consistently have reduced internal use so that they rank among the lowest consumers of their kind in the country.
Nonetheless, a price signal put a new value on outage operations. The major obstacle for controlling the power bill at LCRA’s Fayette Power Project Unit 3 is that it has a system of emission scrubbers that run after the generator trips. In the first outages after the market opened, demand at the plant was high, largely because the scrubbers, essentially a slurry of limestone, can’t stop. If they did, the slurry would quickly dry into cement. So, after studying outage load curves and their interaction with demand charges, the plant’s operation group identified additional systems it could turn off in the event of a failure. Easiest to identify is the set of water pumps that pull water from the nearby Colorado River uphill to the plant’s cooling pond. Alone, the pumps account for about 3 MW.
As FPP worked to manage its load over two years, the energy the plant uses when it trips has declined gradually by approximately 30 percent, an efficiency improvement that translates into power cost savings for its customers.
Phases Out, Phases In
At the transmission level, too, interval data reveal and help resolve otherwise undetectable events. A perplexing question arose in August 2004 when interval meters at two businesses in Shiner, Texas, continued to record energy use after the substation meter failed. How could manufacturers be receiving power when the substation was down? Only a close look at intervals for all meters resolved that mystery flagged in the middle of monthly billing. At first the imbalance appeared improbable; however, interval data extracted from the Key Account MV-90 system showed that while the demand dropped at the consumers’ meters, load continued to flow for almost an hour after the outage before falling to zero. An hour later, interval data showed normal operations had resumed.
The data trails came to a logical end with the transmission outage report. Two transmission lines feed the Shiner Substation. On that Saturday morning, an LCRA crew shut down the one normally used and switched service to the other line. When the shift occurred, two of three line jumpers failed, leaving Shiner with only single-phase service. The phase that powers the substation meters went out, but the phase for the consumer meters remained. Furthermore, while the city’s few three-phase customers would have been under-powered, as the key account meters showed, single-phase requirements were met. Only when service was switched back to the usual line did the plants’ meters fall to zero, for a lightning arrestor failed at the substation. Forty-five minutes later, the arrestor was removed and power restored.
For billing purposes, LCRA allotted a percentage of the load from the second feeder to Shiner’s monthly generation charges. The experience proved useful because a similar even occurred at another substation two months later. LCRA has learned to use its key account, consumer metering to back up data from substations, which helps billing and system management.
Gin-Soaked
Another benefit of the metering and management of interval data is illustrated by the overnight loss of kWh at a cotton gin in Lockhart, about 40 miles southeast of Austin. The gin runs only in late summer and fall after the cotton harvest. A major account for the city’s utility, it also is one of a few gins remaining in Central Texas, providing a valuable service to the region’s cotton farmers. From the time the first loads of raw cotton arrive in August, the gin’s cutters run almost non-stop, pushing out cleaned cotton fiber while filling the air with a snowy mixture of cotton lint and stem dust. When wet, it congeals into a paste not unlike papier-mâché.
On an October Friday, one of Texas Meter & Device’s technicians completed an annual test of the metering service for the gin. An integral feature of the key account service, annual tests verify the integrity of potential and current transformers (PTs and CTs), phase balance, and the meter’s internal pulse and kWh multipliers. Before leaving a test site, meter technicians call Hunt Power to ensure that the meter is functioning properly. All that took place on Friday, yet starting the next morning Hunt Power pulled no data from the meter.
Curious, LCRA staff went to the gin the next Tuesday and found that a weekend rain had left the PTs under a layer of wet cotton waste that had shorted service across the instruments’ caps. Leads to the current transformers had cooked in two, and several wires were still sizzling. The gin ran, for its service had not been interrupted. The city was delivering un-metered, and therefore, un-billable power. Lockhart’s electric utility crew promptly fixed the service, but LCRA concluded the site needed permanent protection. An LCRA distribution engineer worked with TMD to relocate the PTs, protect them with an insulating blanket, and moved the meter outside the tight enclosure where it had been set.
Without daily reads and data verification, the shorted instruments would have gone unnoticed until they started a larger fire or were seen by a meter reader. In addition, normal monthly register reading would have forced the city to estimate un-metered power, always an embarrassment.
Irrigation – Where Electricity and Water Meet
In the summer of 2004 the electric customer service group used interval data to help another internal customer, LCRA’s irrigation operations. LCRA owns and operates three irrigation districts in the region west of Houston called the Coastal Plain. From pump stations on the river, LCRA lifts water into earthen canals where it flows to rice and cotton farmers under contract for service. The districts are separate systems of pumps and canals, each integrated network of canals and ditches. The Lakeside District, centered in Eagle Lake, pumps water from the Colorado at a station called River Plant and delivers it to two lift stations, Prairie and Lake Plant, which pump it to a network of irrigation ditches.
The irrigation sites are in the service area of an investor-owned utility, AEP Texas Central Company (formerly Central Power & Light), a participant in ERCOT’s competitive retail market. LCRA buys generation service from a third party while AEP is the TDSP, responsible for delivering and metering power. Under an agreement with AEP, LCRA has Hunt Power read the nine major pumping loads in the districts and post the data daily to the Web.
To help the crew at Eagle Lake manage its power costs, staff calculated how much energy each of the three pumping stations used to move one acre-foot (ACF) of water. An acre-foot is a common unit of measure, the amount of water needed to cover one acre one foot deep. Other volumes of water are sub-sets of an acre-foot. The first step was simply to determine kWh/ACF by station. Next, using schedules for each pump site’s individual motor operations, kWh/ACF was calculated by motor.
Those results led to further inquiry, for the initial analysis showed that energy use at River Plant shot up when two motors ran and dropped when they didn’t. Modeling their nameplate ratings against operations showed that those motors are inefficient in comparison with the others. When the river’s level fell, those pumps’ efficiency fell even faster. Interval data was critical for the project, for it enabled the analyst to match measured energy against pump operations recorded by their time blocks.
The analytical conclusions supported the informal observations of the Lakeside operators. The result is that they will replace those two pump motors as a part of the refurbishing of another plant.
In each of these cases, interval data made detailed analysis possible, and may have prevented a fire or explosion in Lockhart. With the changing world of re-regulated, competitive markets, keeping up to date with metered data throughout a system assists in managing processes and serving customers.
De-regulation in Texas does not require public power utilities to participate in the competitive retail market, and to date only one of LCRA’s customers has chosen to do that. Also, legislation prohibits LCRA from owning or operating retail facilities or seving retail customers. Faced with the possibility that any customer’s board may vote to “opt in” to competition and open its consumers to other
generation providers, LCRA has developed a Key Accounts program affording its customers metering, meter services, and daily data collection and Web presentation of meter data. Daily meter reading helps detect failed equipment before it can cause operational or revenue problems. Interval data also provides information that helps LCRA’s managers address power plant and irrigation system operations.
LCRA’s staff and manages interval data from two discrete MV-90 meter reading and data translation systems. First, LCRA has its own MV-90 data translation system for its substation-based wholesale billing meters. Second, it uses Hunt Power, in Arlington, Texas, to read approximately 300 electric meter-recorders daily for its wholesale customers’ key accounts. After retrieving data with its MV-90 system, Hunt Power verifies its accuracy and posts the data to its PowerPriceTM Web site. Each participating consumer and wholesale customer has access to its own secure site showing data current through the early morning of each day. LCRA’s staff, then, has access to interval data for approximately 600 wholesale and another 300 retail meters, to assist internal and external customers with billing, metering, and other operational questions.
Phantom MW
One of the most perplexing of those questions arose not long after the Texas electric market began its competitive retail operations. In setting up the market, Texas’ system control operator, the Electric Reliability Council of Texas (ERCOT) concluded that all generators in the system must be metered to record their generation and consumption. And as with all loads of one megawatt or greater, the power plant meters record data at 15-minute intervals. Both ERCOT and the entities responsible for installing and maintaining the plant recorders read them and net their production against their consumption for each of 96 daily intervals. Plant owners are credited with net generation and billed for net consumption.
During normal maintenance of an LCRA coal-fired plant, staff retrieved data from the plant’s meters during an outage to trace generation shutdown and ensuing operation. Plant meters in ERCOT uniformly record consumption on channel one and production on channel four. At the beginning of the shutdown, data from channel four predictably showed a rapid drop to zero as data for channel one -- power in to the plant – showed a sudden rise to a plateau of about five megawatts (MW).
Six hours into the repairs, channel four began registering about three megawatts steadily. This curve made no sense: How could a dismantled turbine be generating electricity? The load curves perplexed plant managers. After reviewing the data, they called the plant electrician, who investigated the anomaly and found that the ground cables, two for each of three phases in the switchyard, produced electromagnetic fields that the lines’ current transformers sensed as active generation, recorded in the meters as generation. The plant crew moved the cables and the meter channel fell to zero. Only because of the new market did the mystery megawatts matter. ERCOT would see the load and credit LCRA with generation that didn’t occur. The sum was too small to affect the system, but it did show that traditional maintenance had to be changed owing to a new and different set of measurement.
“What the Hey, a Light Bill?”
Billing power plants presented a new challenge, too. Under ERCOT rules, plant metering is the responsibility of the transmission and distribution service provider (TDSP). At LCRA, a transmission affiliate manages substations, where LCRA transfers the ownership of power to its distribution customers. It is there that LCRA measures wholesale power sales for billing. So when the re-regulated market approached, LCRA staff decided to treat power plants as substation billing points subject to a specific power plant price and the associated transmission tariffs. The plant bills are included in the appropriate wholesale customers’ monthly wholesale power bills. The customers recover their costs by billing the plants for the full generation and transmission costs and a nominal distribution charge.
Almost overnight, plant managers saw traditional parasitic loads turned into monthly power bills. They’d never seen a retail power bill, and yet now they had to pay demand, energy, and transmission charges.
The plants became a set of new, internal customers, so staff worked to educate operators about billing. Controlling electric use was not new to the plant managers, for starting in the mid-1990s they’d established procedures for shedding internal systems during summer peak hours to reduce their plant consumption and increase output. By subscribing to a power plant indexing service, the managers of LCRA’s coal-fired plants mangers track their plants’ parasitic loads against similar units around the nation and consistently have reduced internal use so that they rank among the lowest consumers of their kind in the country.
Nonetheless, a price signal put a new value on outage operations. The major obstacle for controlling the power bill at LCRA’s Fayette Power Project Unit 3 is that it has a system of emission scrubbers that run after the generator trips. In the first outages after the market opened, demand at the plant was high, largely because the scrubbers, essentially a slurry of limestone, can’t stop. If they did, the slurry would quickly dry into cement. So, after studying outage load curves and their interaction with demand charges, the plant’s operation group identified additional systems it could turn off in the event of a failure. Easiest to identify is the set of water pumps that pull water from the nearby Colorado River uphill to the plant’s cooling pond. Alone, the pumps account for about 3 MW.
As FPP worked to manage its load over two years, the energy the plant uses when it trips has declined gradually by approximately 30 percent, an efficiency improvement that translates into power cost savings for its customers.
Phases Out, Phases In
At the transmission level, too, interval data reveal and help resolve otherwise undetectable events. A perplexing question arose in August 2004 when interval meters at two businesses in Shiner, Texas, continued to record energy use after the substation meter failed. How could manufacturers be receiving power when the substation was down? Only a close look at intervals for all meters resolved that mystery flagged in the middle of monthly billing. At first the imbalance appeared improbable; however, interval data extracted from the Key Account MV-90 system showed that while the demand dropped at the consumers’ meters, load continued to flow for almost an hour after the outage before falling to zero. An hour later, interval data showed normal operations had resumed.
The data trails came to a logical end with the transmission outage report. Two transmission lines feed the Shiner Substation. On that Saturday morning, an LCRA crew shut down the one normally used and switched service to the other line. When the shift occurred, two of three line jumpers failed, leaving Shiner with only single-phase service. The phase that powers the substation meters went out, but the phase for the consumer meters remained. Furthermore, while the city’s few three-phase customers would have been under-powered, as the key account meters showed, single-phase requirements were met. Only when service was switched back to the usual line did the plants’ meters fall to zero, for a lightning arrestor failed at the substation. Forty-five minutes later, the arrestor was removed and power restored.
For billing purposes, LCRA allotted a percentage of the load from the second feeder to Shiner’s monthly generation charges. The experience proved useful because a similar even occurred at another substation two months later. LCRA has learned to use its key account, consumer metering to back up data from substations, which helps billing and system management.
Gin-Soaked
Another benefit of the metering and management of interval data is illustrated by the overnight loss of kWh at a cotton gin in Lockhart, about 40 miles southeast of Austin. The gin runs only in late summer and fall after the cotton harvest. A major account for the city’s utility, it also is one of a few gins remaining in Central Texas, providing a valuable service to the region’s cotton farmers. From the time the first loads of raw cotton arrive in August, the gin’s cutters run almost non-stop, pushing out cleaned cotton fiber while filling the air with a snowy mixture of cotton lint and stem dust. When wet, it congeals into a paste not unlike papier-mâché.
On an October Friday, one of Texas Meter & Device’s technicians completed an annual test of the metering service for the gin. An integral feature of the key account service, annual tests verify the integrity of potential and current transformers (PTs and CTs), phase balance, and the meter’s internal pulse and kWh multipliers. Before leaving a test site, meter technicians call Hunt Power to ensure that the meter is functioning properly. All that took place on Friday, yet starting the next morning Hunt Power pulled no data from the meter.
Curious, LCRA staff went to the gin the next Tuesday and found that a weekend rain had left the PTs under a layer of wet cotton waste that had shorted service across the instruments’ caps. Leads to the current transformers had cooked in two, and several wires were still sizzling. The gin ran, for its service had not been interrupted. The city was delivering un-metered, and therefore, un-billable power. Lockhart’s electric utility crew promptly fixed the service, but LCRA concluded the site needed permanent protection. An LCRA distribution engineer worked with TMD to relocate the PTs, protect them with an insulating blanket, and moved the meter outside the tight enclosure where it had been set.
Without daily reads and data verification, the shorted instruments would have gone unnoticed until they started a larger fire or were seen by a meter reader. In addition, normal monthly register reading would have forced the city to estimate un-metered power, always an embarrassment.
Irrigation – Where Electricity and Water Meet
In the summer of 2004 the electric customer service group used interval data to help another internal customer, LCRA’s irrigation operations. LCRA owns and operates three irrigation districts in the region west of Houston called the Coastal Plain. From pump stations on the river, LCRA lifts water into earthen canals where it flows to rice and cotton farmers under contract for service. The districts are separate systems of pumps and canals, each integrated network of canals and ditches. The Lakeside District, centered in Eagle Lake, pumps water from the Colorado at a station called River Plant and delivers it to two lift stations, Prairie and Lake Plant, which pump it to a network of irrigation ditches.
The irrigation sites are in the service area of an investor-owned utility, AEP Texas Central Company (formerly Central Power & Light), a participant in ERCOT’s competitive retail market. LCRA buys generation service from a third party while AEP is the TDSP, responsible for delivering and metering power. Under an agreement with AEP, LCRA has Hunt Power read the nine major pumping loads in the districts and post the data daily to the Web.
To help the crew at Eagle Lake manage its power costs, staff calculated how much energy each of the three pumping stations used to move one acre-foot (ACF) of water. An acre-foot is a common unit of measure, the amount of water needed to cover one acre one foot deep. Other volumes of water are sub-sets of an acre-foot. The first step was simply to determine kWh/ACF by station. Next, using schedules for each pump site’s individual motor operations, kWh/ACF was calculated by motor.
Those results led to further inquiry, for the initial analysis showed that energy use at River Plant shot up when two motors ran and dropped when they didn’t. Modeling their nameplate ratings against operations showed that those motors are inefficient in comparison with the others. When the river’s level fell, those pumps’ efficiency fell even faster. Interval data was critical for the project, for it enabled the analyst to match measured energy against pump operations recorded by their time blocks.
The analytical conclusions supported the informal observations of the Lakeside operators. The result is that they will replace those two pump motors as a part of the refurbishing of another plant.
In each of these cases, interval data made detailed analysis possible, and may have prevented a fire or explosion in Lockhart. With the changing world of re-regulated, competitive markets, keeping up to date with metered data throughout a system assists in managing processes and serving customers.
