Demand Response Is Now Big Business
While demand response programs can be traced back to the 1970s, the evolution of IT and data management technology has allowed utilities and independent system operators to greatly expand demand response programs in the last 10 years.
By Lyn Corum
This expansion has allowed the parties, including companies offering demand resource products, to create protocols that allow machine-to-machine communication and automate the operation of demand response programs, beginning with the application process as well as the business process downstream.
In an interview prepared for a Federal Energy Regulatory Commission (FERC) national action plan on demand response, Pete Langbein, manager of demand response operations at PJM, which operates the eastern transmission power pool, said revenues in the demand response market operated by PJM have grown a hundredfold. From the 10- to 20-million-dollar range in the 2007 timeframe, today it is close to a billion dollars and represents somewhere between 6% and 8% of the peak load on a capacity basis in PJM’s service territory.
FERC’s Order 745, approved in March 2011, moved demand response up several notches in the regulatory hierarchy. It requires that cost-effective demand response resources be compensated for the service they provide to Regional Transmission Organization (RTO) and Independent System Operator (ISO) energy markets as an alternative to a generation resource.
The FERC order said, “This approach for compensating demand response resources helps to ensure the competitiveness of organized wholesale energy markets and remove barriers to the participation of demand resources....”
The Business of Load Reduction
Demand response is a no-brainer, says Sara McAuley, director of Marketing Communications at EnerNOC, headquartered in Boston, MA. “We pay you to curtail once or twice a year; you don’t have to get budgetary approval, and you get access to our software,” she says.
Once people see their power usage laid out in the software, it opens their eyes to using energy more efficiently, she adds.
EnerNOC is one of at least a half-dozen companies typically known as aggregators who contract with businesses, manufacturers, government offices, and institutions to sell load reduction to utilities throughout the country and independent system operators such as PJM in the eastern states, Electric Reliability Council of Texas (ERCOT) in Texas, and the Midcontinent Independent System Operator Inc. (MISO) in the Midwest.
Geographically, EnerNOC’s largest market can be found in the Mid-Atlantic states in the PJM grid interconnection. McAuley says the company has customers in the Tennessee Valley Authority, Texas, California, and the Pacific Northwest, and smaller markets as well. It also has contracts with Excel Energy and PacifiCorp.
Large energy users, such as manufacturers and light industrial companies, provide the largest demand reduction contribution since they each can afford to drop 1 MW. Smaller customers, such as schools and government buildings, have much smaller loads and reduce on the order of 50 kW to 300 kW at any given time.
Energy Connect, now owned by Johnson Controls headquartered in Milwaukee, WI, likewise provides demand response technologies and solutions to customers across the US, including California utilities, the New York State Independent System Operator, PJM, and ERCOT.
Johnson Controls customers include commercial, local, and state government offices; steel and chemical and other industrial companies; universities; and the agriculture industry.
Comverge, headquartered in Norcross, GA, with offices in Colorado, Pennsylvania, and New Jersey, is most active in PJM and has contracts in ERCOT territory and with California
utilities. Unlike the other two aggregators interviewed, Comverge also contracts with residential customers, for example in Fort Collins, CO.
Jason Cigarran, vice president for corporate marketing and communication at Comverge, says while there are differences in programs between ISOs and utilities, the end result with both is to sign contracts with customers.
Cigarran says the company is very comfortable working with municipal utilities. He explains that the company works with these utilities to design programs that target how many megawatts they want to reduce. It then targets residential customers with air conditioning, and after signing contracts with them, the company installs thermostats inside the home or a controller outside the house. The utility then cycles the air conditioning based on the agreement with homeowners who are paid financial incentives—typically annual fees or a bill credit.
Cigarran says that, on the other hand, large industrial customers prefer to maintain control of their loads and curtail them based on what is already agreed upon when a phone call or signal is received from the utility or Comverge.
|Credit: Great Lakes Cold Storage
The 27,000-square-foot Great Lakes Cold
Storage facility received $30,000 annually
the first two years and participated in
PJM’s demand response program.
Choosing Standby or Economic Response
There are a broad range of demand response programs across utilities and ISOs, and, while parameters differ, all offer payments for energy, capacity,
or economic response. Rich Quattrini, director of Strategic Development in the Integrated Demand Resources group at Johnson Controls, says there are standby programs offering either or both capacity and energy payments, and economic load response programs. Economic response occurs when electricity prices are high and customers are exposed to an hourly price signal. Johnson Controls monitors hourly markets for its customers and automatically engages customers when there is enough value to make a reduction worth their while, says Quattrini.
On the other hand, an event may be called when peak demand reaches a critical level, and customers are asked to curtail load to back down the need for generation. In this latter example, companies may be paid capacity payments to stand by for notification of an emergency. As long as a customer demonstrates they can reduce load, they are paid the standby payment regardless of whether they are called upon to reduce load. They will receive an energy payment only if they do curtail load. Some programs, however, do not offer capacity payments to stand by.
Air conditioning and other processes, such as fountains and elevators, are typical kinds of loads commercial and institutional facilities will choose to reduce, says Quattrini. Also, some lighting is included. For example, office buildings may choose to raise thermostats two to four degrees when asked to reduce loads. They may also choose to reduce daytime lighting in unoccupied areas or parking garages.
Given the type of program, customers may be given a full day’s notice of a planned curtailment, and some sites have to respond on a sub-second schedule. As EnerNOC’s McAuley explains, the former schedule is for companies who want to control their curtailments, and for the latter, curtailment is fully automated. In between, a site may choose a two-hour notice. McAuley says the day-ahead notification plans are more popular. However, the more demanding the plan, the more money the customer can be paid.
The types of loads may also depend on how the building campus is configured, Johnson Control’s Quattrini says. For example, a complex may choose to reduce its load 20% for one-hour events, but only 10% for a six-hour event. Or, a customer may choose to have the reduction strategy be fully automated—for example, automatically raising air-conditioning temperatures a few degrees or adjusting temperatures on chillers when an event occurs.
A steel or chemical company, on the other hand, might be able cut more load by shutting down a process line. A steel company may choose to reschedule steel melting production to later hours when electricity is cheap. A cement plant may be able to stop crushing rocks and reduce its load nearly 100%. Similarly, recycling operations may choose to put operations on hold during demand response events.
After signing contracts with customers, aggregators meet with customers to help design a demand response plan with them. Since EnerNOC has experience with offices, data centers, prisons, even a plastics extractor, it is easy to walk through what a new customer will experience, McAuley says.
An energy technician then installs a small gateway device on the company meter. The server allows software to communicate with the meter and the customer to view power usage. EnerNOC can also write a program for the company’s energy management system to talk with the server in order to automate the energy reduction plan, if the customer chooses that option.
The aggregators monitor their customers’ performances as loads are curtailed. “We have the tools to flag the customer who is not hitting his marks,” says EnerNOC’s McAuley, “and we can ask ‘what’s going on?’ They may answer, ‘I planned to reduce but have a big job I have to finish.’ Once the event is over, another message goes to the customers saying service can be restored.”
The advantage of our aggregating loads, says McAuley, is while one customer may fall short, another may reduce more power than it committed. “We manage customer loads like [we would manage] a portfolio,” she says.
Demand response customers across the country are paid wildly different rates, but all three aggregators agree that the PJM market in the Mid-Atlantic territory provides the most lucrative incentives. “PJM is the more forward-thinking in terms of variety of load reduction,” says Johnson Control’s Quattrini.
Comverge’s Cigarran states that “PJM has the most resources, and it gets large curtailments [by customers],” because of this lucrative pricing.
PJM holds three-year, forward-looking auctions at which aggregators bid into the market. Capacity payments are very lucrative. In January 2014, during the cold snap labeled the Polar Vortex, it was paying $226 per megawatt. Energy payments are the real-time clearing price for energy that both generators and demand response customers receive.
End use customers can earn anywhere from $20,000 per megawatt per year to $180,000 per megawatt per year, with an average of $40,000 to $60,000 across markets, EnerNOC’s McAuley says. Alberta, Canada, customers earn in the high end, she says, because of the additional layer of technology where they participate in sub-second schedules. Lights are automatically lowered, and air-conditioning temperatures are automatically raised a degree or two when the utility or grid operator needs to flatten load.
A manufacturing plant could have a standby agreement with EnerNOC and receive a $50,000 capacity payment annually, and be called on to reduce load once or twice a year. When called on to reduce load, the manufacturer will earn an additional energy payment, depending on how well he responds. Energy prices vary widely and depend on what type of market the customer is participating in—a grid operator or a utility. For example, while Texas offers energy payments only, customers in that state may expect to see about $40,000 annually.
McAuley says these prices are what the customer receives from EnerNOC and are 40% to 60% of the payment EnerNOC receives from the grid operator or utility.
Cutting HVAC Automatically
Kilroy Realty has 15 commercial office buildings under contract with EnerNOC—in the San Francisco Bay area, in the greater Los Angeles area, and in the Ventura area north of Los Angeles.
Sara Neff, vice president of sustainability at Kilroy Realty, says only HVAC equipment is curtailed when a load reduction signal is received from EnerNOC. By increasing HVAC temperatures two or three degrees, fan speeds are reduced, hot water pumps are shut down, and chillers ramp down, she says.
“You really cannot impact the occupant—tenant comfort is most important,” says Neff. Since the size of the buildings makes the payments so small, “We do demand response to help the grid improve reliability.”
Furthermore, a demand response program can shave a building’s peak demand and reduce demand charges, which make up 40% of electricity bills.
On average, Kilroy receives payments of $2,000 per building per year. A 150,000-square-foot building can reduce about 230 kW, she says, and a 300,000- square-foot building can reduce about 430 kW on average. The company expects about 12 load reduction events a year. Last summer they had nine.
A Kilroy-owned building in Long Beach has an energy management system dedicated to demand response, allowing staged reductions on different floors to occur for specified times. Or a more aggressive reduction may be accomplished by rolling through the floors, shutting down one floor at a time, minimizing the frequency with which any space is impacted. This success will be replicated in a Kilroy-owned building in El Segundo, Neff says.
To accomplish this type of sophisticated control, Kilroy asks Enerliance, a nine-year-old Irvine software company that specializes in central plant performance optimization, to design software and install the hardware that created the enhanced air-conditioning reduction system.
Enerliance president Ray Pustinger says HVAC equipment in commercial buildings has traditionally been off limits for curtailment, even though it uses 35% to 40% of the building’s electrical load. The reason was, “People weren’t willing to sacrifice comfort,” he says.
However, because commercial buildings are an excellent candidate for demand response, Enerliance developed software to dynamically control all HVAC equipment—pumps, drives, fans, etc.
“Our software gives the building operator the opportunity to curtail precisely. If I curtail 150 kilowatts, people will be very upset, but if I curtail 80 kilowatts they will never complain,” says Pustinger.
Within a building, Pustinger explains, Enerliance software can control the temperatures on every floor by selecting equipment to be curtailed to fit the commitment determined earlier. As soon as EnerNOC or a utility sends its signal to the building to curtail, the software takes over and sends its signals to the equipment at the designated start time. If a building typically uses 1,000 kW, for example, and it agrees under contract to shed 100 kW when called on, the software assesses the last 10 days of electrical usage, to determine what equipment should be shut down to maintain the curtailment goal of 100 kW.
The software also watches the return air temperatures. In a high rise, for example, floor 3 may accept a one-degree temperature increase without increasing occupant discomfort. Once the temperature deviates from that one-degree rise, the software will turn equipment back on, and increase the temperature on another floor to maintain the 100-kW curtailment goal.
Pustinger says the company’s software controls 30 MW of demand reduction in just over 300 buildings, representing 49 million square feet. He has worked with the Green building Council to create a Leadership in Energy & Environmental Design (LEED) credit for demand response.
Cutting Demand a Smart Choice
Great Lakes Cold Storage has been in business for 36 years, storing products for large food manufacturers. It owns two facilities—one in Solon in Southern Ohio near Cleveland, and a second facility near Pittsburgh, PA. Both have demand response contracts with EnerNOC.
The 247,000-square-foot Ohio facility has been participating in demand response calls for three years and received payments in excess of $30,000 annually for the first two years. EnerNOC sells the load reduction to PJM. It has been able to reduce its average monthly electric bill from $55,000 to $32,000 per month.
The Ohio facility has three 350-hp compressors and two 250-hp compressors to cool the 200,000 square feet of freezer space. Tom Johnson, director of operations at Great Lakes, says during typical events they can reduce power almost 70% by shutting down the compressors, disconnecting battery chargers for their forklift trucks, closing doors to maintain temperatures in the freezers, and shutting off room lights.
Most of the time, demand response events will occur between 3 and 5 p.m. when a smaller staff is on duty, so reducing lights and shutting off rooms is easy Johnson says. Office space takes up 50,000 square feet, so with each room closed and lights off, a significant amount of power can be saved, he says. During winter months, Great Lakes will be given two to three days notice to reduce power. During summer months, they will get one hour to 90 minutes notice, on average.
Johnson says in this third year, “we’re getting smarter about reducing energy use,” so load reduction has been less, cutting back payments. For example, he says that on January 6, 2014, outside temperatures reached -14°F. Refrigeration was shut down, since it wasn’t needed. In addition, real time demand data was used to optimize defrost times and refrigeration operation, identify phantom loads, and isolate non-essential loads and equipment.
“The value of knowing what you’re doing is hard to quantify,” says Johnson.
Demand Response Program Sampling
Independent system operators and utilities in different parts of the country operate demand response programs that allow customers to participate either with or without contracting with an aggregator. Here is a small sampling of ISO and utility programs with detailed descriptions. California’s Pacific Gas and Electric (PG&E), Southern California Edison, and San Diego Gas and Electric all have numerous programs with fine points too varied for the scope of this article.
The Electric Reliability Council of Texas (ERCOT) manages 85% of the state’s high-voltage bulk electricity grid and offers three demand response programs: load resources, under-frequency load shed, and emergency response.
Large industrial customers such as petrochemical and air separator companies, pipelines, and oil field services participate in load resources, says Paul Wattles, a senior analyst for market design and development at ERCOT. End users sign contracts with Qualified Scheduling Entities, or QSEs (the Texas equivalent of aggregators), which offer the load reduction to ERCOT. Wattles says there are now 125 QSEs that manage demand response for ERCOT.
Load Resources provides ancillary or operating reserves. Customers must have devices called “underfrequency relays” installed at their breaker to be able to shed load instantaneously and automatically when the grid system lacks enough generation. The load reduction in this case reduces demand on the grid. The most recent event occurred on January 6, 2014, when Texas experienced extremely cold weather.
QSEs bid their customers’ load reduction commitments into the day-ahead market and they bid daily.
“We buy up to 2,800 MW of all resources, both generation and load resources,” says Wattles. Load resources are capped at 50% or 1,400 MW. All resources are paid the same clearing price set by the 2,800 MW. Prices average between $10 per megawatt, and $15 per megawatt.
Wattles says there are fewer summer events, but they can happen any time of the year. He says the average is three per year. Under-frequency load shedding events in moderate weather are more common.
Emergencies occur when all available generation is operating but the grid is gradually running short of supplies. In this case load resource customers are to respond with 10-minute or 30-minute instructions and are paid the day-ahead ancillary services clearing price.
Emergency Response Services are another demand response product but are bought and used differently. ERCOT buys 700 MW three times a year through the market for four-month contracts. Participants include commercial and medium size businesses such as supermarkets, data centers, and office buildings and can choose to receive instructions either 10 minutes or 30 minutes before curtailing power.
Wattles says all QSEs have 100-kW minimum load reduction requirements and their contract amounts range between 500 kW and 100 MW.
|Credit: Kilroy Realty
An EMS dedicated to demand response allows for staged reductions on different floors.
PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 eastern states and the District of Columbia. It also operates a competitive wholesale electricity market.
Customers must participate through curtailment service providers (CSPs), which may be companies that focus on their demand response businesses (aggregators), a local electricity utility, or an energy service company or other type of company that offers these services. A list of CSPs can be found on PJM’s website.
Demand response customers can participate in either or both economic and emergency programs (also referred to as Load Management Resources or Interruptible Load Resources).
Emergency programs require participants to reduce load or only consume electricity up to a certain level when PJM needs assistance to maintain reliability under supply shortage or planned emergency operations conditions. Penalties may be applied for non-compliance.
CSPs bid prices for their customers’ curtailment loads in a yearly auction run three years in advance of when the procurement is needed. Generators bid into the same market. Roy Dotter, a PJM spokesman, explained that if a general auction does not produce enough resources the price goes up to satisfy the need. Auctions are held every May, and contracts start on June 1 and end on May 31 of the following year.
PJM divides its service territory into 21 zones and CSPs bid customer loads into the zone in which they reside. Prices vary from zone to zone and are the same for both generation and demand response. For example in the 2013 auction in which 12,408 MW of demand response was procured, capacity prices varied from $59 to $219 per megawatt, depending on zone, to be paid in the 2016/17 year.
Three products are available for the customer and the CSP to choose from. First, the resource is available for up to 10 weekdays from June through September where each request may last up to six hours. Second, the resource is available for all days from May through October where each request may last up to 10 hours. And third, the resource is available for all days from June through May of the following year where each request may last up to 10 hours.
PJM needs these resources to avoid brownouts and/or rolling blackouts within its service territory so it considers them similar to generation and expects them to perform at the time they are called on.
Payment is driven by the capacity market and the load reduction commitment. Customers receive capacity payments on a monthly basis in return for agreeing to be available during expected emergency conditions for commitments made for one year.
Customers may also participate on a voluntary basis and be compensated based on the amount of energy reduced during the emergency. In this case, they do not receive capacity payments.
Economic demand response allows customers to reduce load in the energy market when the wholesale price is higher than the published monthly PJM net benefits price. An economic demand response resource may also provide ancillary services once the customer is qualified by PJM. There are three markets: synchronized reserves in which the customer can reduce electricity consumption within 10 minutes; day ahead scheduling reserves in which the customer must reduce electricity consumption within 30 minutes; and regulation in which it has the ability to follow PJM’s regulation and frequency response signal.
Most of the activity occurs in the emergency program since getting a stream of revenue for standing by is extremely attractive to the participating customers, Dotter says.
He says customers in the emergency program can also participate in the economic program but not at the same time. However, one facility with multiple meters could, at the same time, dedicate some meters to one program and the remaining meters to the other.
The Midcontinent Independent System Operator Inc. (MISO) manages the regional grid across all or parts of 15 states and the Canadian province of Manitoba. It operates a day-ahead and real-time market into which generators and demand response customers may bid to provide power or services.
MISO’s demand response programs offer four markets. There is a day-ahead real time energy market, a regulation market, a capacity market over the next planning year, and a synchronized non-spinning market identical to the energy market.
Demand response customers in capacity markets receive regular payments based on market prices. Customers in energy markets are paid only when asked to curtail load.
Demand response customers who want to bid into the market must register as a market participant and this requires several steps including getting permission from the regulator in which the customer resides, according to Michael Robinson a consulting advisor at MISO. Steps are listed on MISO’s website.
Aggregators of retail customers may sell demand response resources into MISO’s energy markets, but must also register as market participants once sanctioned by states in MISO’s service territory.
Robinson says MISO hasn’t had to call on demand response for emergencies because the agency is long on capacity. The summer 2013 resource assessment analysis on the MISO website bears this out. No energy emergency occurred in the 2013 summer peak hours so no demand response resources were called out. Nor did MISO experience any major reliability issues during the summer of 2013. The highest peak load on July 18, 2013 was 95,777 MW while accessible capacity was 99, 431 MW. Average day-ahead and real-time local marginal prices were $31.75 per megawatt-hour and $31.19 per megawatt-hour.
In 2011, MISO experienced a systemwide summer peak load of 103,975 MW in one of the hottest seasons on record. Again demand response resources were not needed. During winter months going back to 2010, MISO enjoyed high reserve margins and did not need to call on demand response resources.
Author’s Bio: Lyn Corum is a technical writer specializing in energy topics.