OwnerJuly 2015 to presentEl Cerrito

Finding best available technologies for meeting energy needs today and tomorrow: energy efficiency, demand response,, solar, wind, electric vehicles, biofuels and smart grid. It’s all the innovations that make the energy we use more secure, clean, and affordable. The energy world's best hopes lie in what's happening in the digital realm, especially in data analytics.

Wednesday, August 15, 2012

Demand Response (DR)

A temporary change in electricity consumption in response to market or reliability conditions

Demand Response pushes Discretionary Load out of the Utility System's Peak Hours

Navigate this ReportBack to Load Shifting Index
1. Background

2. Types of Demand Response
3. Acronyms/Definitions
4. Business Case
5. Benefits
6. Risks/Issues
7. Success Criteria
8. Companies
9. Links

  • Demand Response is a temporary change in electricity consumption by Demand Resources in response to market or reliability conditions. Demand Resources are loads or aggregation of loads capable of measurably and verifiably providing temporary changes in consumption.
  • Today demand response today is largely invoked when there are imminent brownouts or blackouts and the programs are triggered by reliability trigger of some kind. They are based largely on aging technology.
  • All in all, about 41 gigawatts of power was under demand response management as of December 2008, or about 5.8 percent of nationwide peak power demand, according to a report by the Federal Energy Regulatory Commission (FERC). Still, that's just a fraction of the 38 to 188 gigawatts of demand response capacity that the nation could harness to reduce overall peak energy use by as much as 20 percent, according to a 2009 report from FERC.
  • Today close to 80% of the demand response in California is only available in an emergency. About 1700 megawatts, that's a significant resource, only available in emergencies. Because it is intended for emergencies, the ISO cannot plan around or even consider DR.
  • According to Navigant Research, global Commercial and Industrial DR capacity is expected to grow from 26.8 GW in 2014 to 132.3 GW in 2023.

Direct Load Control and Interruptible Demand by NERC Regions 2006 vs. 2007

2. Types of Demand Response
  1. Ancillary Services DR (My Blog Article) - End-use customers are allowed to bid load curtailments in ISO/RTO markets as operating reserves. Accepted bids are paid the market price for committing to be on standby. In order to participate in ancillary-service markets, end-use customers must be able to adjust load quickly during a DR event.
  2. Emergency DR (My Blog Article) - The emergency demand response option provides incentives to customers for reducing load during reliability triggered events. These events may also be called in response to high wholesale electricity prices. End-use customer participation in this option is most often voluntary. Upon notification, customers can choose not to curtail and in turn not receive any payment. Usually on-site generators are allowed to participate and supply power during curtailment periods.
  3. Capacity Market DR (My Blog Article) - Typically offered by wholesale market providers such as ISOs and RTOs. Participants commit to provide pre-specified load reductions when system contingencies arise. In return, they receive a fixed incentive payment in the form of capacity credits and are paid to be on call even though actual load curtailments may not occur. Enrolled loads represent a firm resource and can be counted toward Installed Capacity (ICAP) requirements.

Automated Demand Response can be implemented in several different ways. Smart controls can reside with 1. Utility in Direct Control, 2. Consumer with Price Response or 3. down to the Smart Appliance

3. Acronyms/Definitions
  1. Demand Response Aggregator- A company joining two or more customers, other than municipalities and political subdivision corporations, into a single purchasing unit to negotiate the purchase of electricity from retail electric providers. Aggregators may not sell or take title to electricity.
  2. Dispatchability of DR Options - The ability to provide a DR-inducing signal within a limited timeframe. Some argue that dispatchability is a requirement of a DR option. Time-of-use (TOU) rates are sometimes considered a demand-response option. TOU rates are non-dispatchable and produce a consistent reduction in peak demand.
  3. FERC - The Federal Energy Regulatory Commission - The United States federal agency with jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas pricing, and oil pipeline rates. FERC also reviews and authorizes liquefied natural gas (LNG) terminals, interstate natural gas pipelines and non-federal hydropower projects

    The Energy Independence and Security Act of 2007 requires FERC to conduct a national assessment of demand response potential, develop a national action plan on demand response, and with the Department of Energy develop a proposal to implement the national action plan. So far the Commission has accomplished the following:
  4. » 2010 National Action Plan » 2009 National Assessment
  1. Incentive-based Options pay customers to reduce load during events called by the program sponsor. These events can be triggered by an emergency on the grid or by high electricity prices. Incentive-based options include:
    • Direct load control (DLC)
    • Interruptible/Curtailable rates
    • Emergency DR option
    • Capacity market DR
    • Ancillary services
  2. Reliability Triggered Options are called in response to emergency conditions on the grid (e.g., outages). These options typically provide short notification time due to unpredictable nature of emergencies
  3. Price Triggered Options are called in anticipation of high market prices

4. Business Case
  • A Smart Grid is a key enabler in achieving demand response / load management; with the goal of peak reduction.
  • The extensive use of demand response could potentially cut the peak power demand in the United States by up to 20% in the next decade, according to a 2009 report from the Federal Energy Regulatory Commission (FERC). This study estimates the potential growth of DR in the United States from 2009 to 2019. Four different scenarios are considered (from least to most potential) – Business-as-Usual (BAU), Expanded BAU, Achievable Participation and Full Participation. Demand response gives utilities the ability to cut large commercial and industrial loads and to control other customer's use of air conditioning, refrigeration, and other large electrical appliances. For instance, demand response could cause your air conditioner to delay its next cycle or to cycle less often in times of high demand, usually in exchange for a credit on your power bill. More sophisticated means of demand response include the use of smart meters and "dynamic" utility pricing that varies with demand, so that customers are motivated to reduce or delay their electrical use during times of peak demand.
    Demand Response Potential

  • Looking ahead to 2019, the FERC report projects a 38-gigawatt (GW) reduction in peak load under business as usual, equal to 4% of the projected peak load; an 82-GW peak load reduction under expanded business-as-usual, equal to 9% of peak load; a 138-GW peak load reduction under the achievable participation scenario, equal to 14% of peak load; and a 188-GW peak load reduction under the full participation scenario, which yields a 20% reduction in peak load. The full participation scenario results in essentially no growth in U.S. peak power demand over the next decade. In this scenario, much of the load savings is achieved through dynamic pricing, combined with smart devices.
  • There are three necessary components for demand response.
    1. Advanced Metering Infrastructure - You clearly have to have advanced metering so that, so that usage can be measured on at least an hourly basis. This includes: Digital meters, Two-way communications enables programmable communicating thermostat control and in home displays
    2. Price and Event Communication - Information is necessary for customers to take action and the rates provide the motivation to respond. Enabling technology allows residential and small commercial/industrial customers to respond to price easily.
    3. Larger customers with energy management systems linked to pricing signal over the internet or through other communication channels
  • DR Options
    • Signal to the end-use customer: incentive-based or price-based
    • Trigger for the DR event: reliability vs. price
    • Program implementation: wholesale vs. retail
    • Response requirement: mandatory vs. voluntary
    • Dispatchability: dispatchable vs. non-dispatchable
    • Notification: day-ahead vs. day-of notification
    • Control: utility-controlled vs. customer-controlled
    • Type of incentive payment: fixed vs. market-based

5. Benefits
  • Save Costs– The Galvin Institute estimates that widespread national use of demand response would save U.S. consumers at least $30 billion a year. For example, Chicago’s Community Energy Cooperative initiated a demand response program that saved the residential consumers an average of 19% on their electricity bills in 2003. Reducing spikes in demand will cut the need for peakers small power plants such as pumped storage systems that exist solely to deal with such spikes.
  • Improve Reliability - Voluntary price response can reduce the probability of emergency events occurring. Even day-ahead notice of an event can, even if enough people respond even a small amount, reduce the probability of needing an emergency response that next day. Respond to temporary grid anomalies
  • Increase Consumer Choice - Introduce new markets for aggregators, micro-grid operators, distributed generation, vendors, and consumers; Engage the consumer by allowing market participation and consumption/billing choices.
  • Manage Demand - Control peak power conditions and limit or remove brownout/blackout instances; Flatten consumption curves and shift consumption times; Maximize use of available power and increase system efficiencies through time-of-use (TOU) and dynamic pricing models.

6. Risks/Issues
  • Industry Structure Will Change - Demand response companies could face pressure from providers of technology that lets utilities turn down peak power use by themselves. Or those demand response aggregators could take over that market.

    The longer-term promise of two-way communicating smart meters to could replace demand response systems from aggregators like EnerNOC and Comverge with hardware and software the utilities can own and operate on their own. And if two-way networks that allow customers – particularly homeowners – to play a part in deciding when their air conditioners power down become more widespread, that could pose a serious threat to demand response aggregators middleman role.
  • Unproven Benefits - The Demand Response cost savings that are included in advanced metering rate cases are still mostly theoretical. We don’t know for sure if demand response will be critical to making Smart Grid cost effective. Customers are being paid cash for lowering peak usage against a baseline that, of course, by definition is unobserved. So it has to be estimated and there you have a lot of statistical methodology questions.
  • Dispatchability - Smart meter-enabled systems for turning down customers' power use may spread in the coming years and decades, but that they could continue to suffer from the potential for customers to opt out. That would make their negawatts a bit less like the firm generation resources like coal-fired power plants, and more like solar power – a fair-weather resource, so to speak, that can be relied on only when the sun is shining, or in this case, when those CFO-less and CIO-less homes are willing to agree to turn down their power use.
  • Complex Information Exchange - Demand Response is characterized by interactions between the actors that must traverse many domains in order to function. Information is exchanged between devices of varied complexity, ownership, and access rights.
  • High Cost - Current Cost to install DR is too high. First cost and on-going operations/maintenance cost make few DR programs economic.
    • DR Hardware $100 to $200 per Appliance 100% Un-needed/un-wanted
    • Installation $150 to $200 Includes Labor, Permit, & Project Management
    • Marketing $50 to $100 Cause it’s a Hard [Utility] Sell
    • $500 per installed DR point
    • Benefit: 0.6kW (WH); 1.0 (A/C); 2.0 (Elec. Ht)
    • $/kW= $833 (ugh); $500 (marginal); $250 (ok) respectively
  • Hard Consumer Sell - The value proposition of demand response to customers may be nebulous. A bonded electrician drills; installs ugly equipment; cleans up (usually) and the customer saves And YOU save $2 to $5 per month (but like the drippy faucet, it adds up) As a result:
    • 80% Can’t follow offer, or fail to see value proposition
    • 60% Say No when installation described
    • 10% Change mind, say No when electrician arrives
    • Target device in 10% of homes doesn’t meet code
    • 5% of spouses not on enrollment call cancel service within 1 month
    • Bottom line: only 6% of target audience get an install
  • Communications. Demand response creates new communications needs. At a minimum it will be necessary to communicate real-time prices and/or interruption signals. But the Internet creates the possibility of a much richer dialogue between end-users and the system operator. In addition to prices, the kinds of information that may be communicated include total end-user loads, end-user loads available for interruption, billing information, and forecast of weather and prices. A variety of issues need to be addressed including communication protocols, security and reliability.
  • Controls - A key to more successful demand response programs, especially in buildings, will be the availability of control systems that can respond automatically to price and interruption signals. Existing control systems for buildings have a number of deficiencies and R&D efforts are required to overcome these deficiencies.
  • Institutional issues - Some observers argue that the most important impediments to successful demand response programs are institutional (as opposed to technical). While there are a few successful RTP programs in the US, there have also been a number of failures.
  • Use of Backup Diesel Generators for DR - On May 22, 2012, the EPA signed proposed amendments to the  National Emission Standards for Hazardous Air Pollutants for stationary reciprocating internal combustion engines (NESHAP RICE). The proposed rule changes do not become effective until EPA issues a final regulation including any final changes.

    Opponents including the Sierra Club want to see backup diesel generators restricted to true emergencies, where they have always been exempt from pollution controls.

    The EPA’s proposed rule restricts operation for emergency DR to the lesser of program requirements (which is 60 hours in PJM) and 100 hours per year. The EPA has always allowed up to 100 hours per year for non-emergency use, which includes testing and maintenance, and a subset of those hours for emergency DR. The EPA is  proposing more flexible as to how those hours can be used in order to maintain last line of defense emergency resources to help prevent blackouts. It’s important to keep in mind that these generators – at hospitals, wastewater treatment plants, and other mission critical facilities – must run periodically for testing and maintenance, and existing permitting rules limit such operation to 100 hours per year. DR event hours can and are used as substitutes for normal testing and maintenance.

    Also, EPA is proposing to tighten the trigger for when emergency DR events can be called (i.e., at NERC EEA Level 2 - Issued when a Control Area “foresees or has implemented procedures up to but excluding interruption of firm load commitments” and voltage reductions only); thus, emergency DR is very rarely called. The last, and only time, emergency engines have been used by ISO New England for emergency DR, for example, was on August 2, 2006 for a total of 3.75 hours. If emergency DR was not available that day, the grid most likely would have failed; and if that happened, every generator, whether properly permitted or not, would have operated for hours or days before the electric grid was restored.

7. Success Criteria
  • Simple, stable program rules
  • Enhance customer program choices
  • Educate customers about economic and environmental benefits of DR
  • Develop segment-based marketing tools to promote Energy Efficiency, Demand Response & Solar programs
  • Encourage installation of enabling technology

8. Companies
  1. Comverge (NSDQ: COMV) East Hanover, NJ - With over 500 U.S. utility clients and 4.5 million devices installed, Comverge "smart megawatts" technology is widespread and in use across the nation. Their "pay-for-performance" programs provide capacity that can reduce emissions, eliminate line losses, increase reliability, and defer generation and transmission acquisition.

    In April 2007, Comverge (COMV) became one of the first publicly traded companies that could be described as a pure-play smart grid company. On Monday, March 26m, 2012, Comverge ended that experiment on the public markets with a sale to H.I.G. Capital for $49 millionon, a fraction of the market value it commanded just 18 months ago.

    As a provider of demand response services, it allows utilities to cut power use in homes at peak demand times using one-way pager networks, and has installed in-home energy displays, smart thermostats and digital controls in projects with more than 500 utility customers. In a nod to the emerging dominance of smart meters and broadband connections as pathways to the home, Com verge has also launched software aimed at giving utilities a platform to monitor and control systems based on both modes of communication.

    Now that Comverge has solved its immediate debt financing and cash crisis, it has a year or so to prove it can achieve a key milestone and turn cash-flow positive on an annual basis. By 2013, the Norcross, Ga.-based company wants to show a first-ever annual profit.

    Analysts agree that Comverge's 2011 fiscal year results released in March contain impressive growth in its commercial and industrial customer base, although its residential business has languished. It's also launching new projects like the creation of a demand response market for South Africa utility Eskom.

    Still, Comverge's sale to H.I.G. highlights a key problem the company may have faced in maintaining a balance sheet strong enough to play in its chosen market. Demand response aggregators have to bid on contracts in key markets like that of mid-Atlantic grid operator PJM and others.

    Comverge needed money just to participate in those auctions, and Monday's news of an immediate $12 million in debt financing should tide over those concerns. But beyond its short-term problems, the company has struggled for years to keep up with its rivals in the demand response space - namely, big U.S. rival EnerNOC (ENOC), which went public one month after Comverge.

    Comverge had 4,564 megawatts under management at the end of 2011, compared to the more than 7,000 megawatts under managementEnerNOC had racked up as of late last year. The two had been virtually tied on market share up until 2009 or so, when EnerNOC began pulling away.

    In 2010, CEO Blake Young was hired to restructure the company and bring it up to speed. But first, he had to manage a crisis, when the company was forced to recall communications modules inside the radio-controlled home thermostats it had deployed with Texas utility TXU, over fire hazard concerns.

    That ended up affecting most of the company's utility customer base, Young said in the company's March 16th conference call. While the company has grown residential business by 21 percent in 2010 and 14 percent in 2011, the end of a contract with NV Energy was enough to push residential megawatts under management from 1,287 to 1,134 in the fourth quarter.

    In the meantime, Comverge has been growing its share of commercial and industrial customers, and added 800 megawatts overall last year. But it's also facing tough competition from the likes of EnerNOC, Constellation Energy, Honeywell, Johnson Controls, ViridityEnergy and ConEd Solutions, to name a few big C&I demand response contenders. Still, analysts covering the company pointed to strong fourth-quarter C&I revenues of $10.2 million, double those from the same quarter a year ago, as a sign that the company was far from out of the game.

  2. Cooper Power Systems – Waukesha, WI - the largest provider of utility Demand Response equipment and software in the United States.  Engineers and manufactures medium- and high-voltage electrical equipment, components, and systems that deliver reliable electric power to homes, industries, businesses, and institutions worldwide. Through their Energy Automation Solutions group, which includes Cannon Technologies and Cybectec Inc. they are also a leader in providing software, communications and integration solutions that enable customers to increase productivity, improve system reliability, and reduce costs.

    On May 21, 2012,  Eaton Corp., the power and control systems giant, announced Monday that it would acquire Cooper Industries, catapulting the 90-year-old Eaton into a new class of smart grid competition.

    Terms of the transaction announced Monday set a value of $72 per share of Cooper stock in cash and shares in the new company, for an equity value of $11.8 billion, one of the biggest M&A deals of the year so far. Eaton has secured a $6.75 billion bridge financing commitment from Morgan Stanley and Citibank to finance the cash portion of the acquisition.

    The combined companies had a collective $21.5 billion in 2011 revenues,  The deal, to close in the second half of 2012, will create a company headquartered in Ireland and tentatively titled “Eaton Global Corporation Plc

  3. EnerNOC (NASDAQ: ENOC) Boston MA - A leading demand response and energy management solutions provider for commercial, institutional, and industrial customers, as well as electric power grid operators and utilities. With its 3.15 gigawatts, EnerNoc remains among the largest demand response providers in the United States. Jan 2008 acquired MDEnergy for $7.9 million.

    In 2011, EnerNOC bought Australia and New Zealand demand response provider Energy Response for $27.9 million, added 150 megawatts of automated demand response for Alberta, Canada’s grid operator, launched fast demand response in Texas and the U.K., and continued work on a DOE-funded wind power-balancing project with the Bonneville Power Administration.

    EnerNOC also reported a fiscal year 2011 loss of $13.4 million, or $0.52 per basic and diluted share, compared to a profit of $9.6 million, or $0.37 per share, in the previous fiscal year. Also Tuesday, the company announced that CFO Timothy Weller will leave in March to pursue other professional opportunities. It’s the second C-suite departure since last February, when COO Darren Brady left the company.

    But the biggest news came from the Federal Energy Regulatory Commission regarding a long-standing dispute EnerNOC has with grid operator PJM about how it claims revenues from its demand response programs. In February 2011, PJM accused EnerNOC of “double-counting” its customers' participation in certain demand response programs.

    FERC initially sided with EnerNOC in a March ruling that ordered PJM to keep its existing market rules. But in November, FERC approved PJM’s proposal to change its demand response performance measures in a way that could hurt EnerNOC’s revenues. That did nothing to help EnerNOC’s battered share price, though FERC also ordered PJM to minimize the impact on existing demand response participants.

    Late last Friday, however, FERC issued an order “substantially accepting PJM’s compliance filing, which resulted in the immediate implementation of PJM's proposed market rule changes regarding capacity compliance measurement and verification,” EnerNOC reported Tuesday. That means that EnerNOC will now have to start bidding at auction to cover megawatts that PJM considers “double-counted,” starting as early as Monday of this week.

    PJM has historically accounted for a majority of EnerNOC’s revenues. While the company has been expanding in the U.K., Australia and in other regions of North America, FERC’s decision could have a negative impact on the company’s revenues through 2012 and 2013, analysts say. Wedbush Securities reiterated its $5-per-share target for EnerNOC stock on Tuesday, citing the impact that FERC’s new ruling could have on PJM revenues.

    Not all observers saw FERC’s ruling as all bad. Piper Jaffray maintained its $13 target price on EnerNOC stock, saying it removes an “overhang” that’s been driving company shares to multi-year lows throughout 2011. EnerNOC shares traded in the $40-to-$50 range throughout 2008 and had hovered in the $25-to-$30 range throughout 2010, but have since fallen to languish in the $10 range for the past five months.

    EnerNOC projected 2012 revenue to be in the range of $240 million to $280 million, with GAAP net loss in the range of $1.00 to $1.60 per basic and diluted share. For 2013, EnerNOC projected revenue in the $350 million to $400 million range, with the potential for anything from a net loss of $0.25 per basic and diluted share to a net income of $0.50 per diluted share.

  4. GridPoint, Arlington, VA. - A leader in smart grid software, enables utilities to efficiently balance supply and demand, improve grid reliability and empowers consumers with choices such as sources of energy and price. The company has received $220 million of VC financing to-date from a several investors including Goldman Sachs. Plans for an IPO are probably being contemplated as Goldman recently underwrote the IPO of A123 Systems which has a similar corporate profile.

8. Links
  1. FERC - 2009 ASSESSMENT OF DEMAND RESPONSE AND ADVANCED METERING - This report fulfills a requirement of the Energy Policy Act of 2005 (EPAct 2005) section 1252(e)(3)1 that the Federal Energy Regulatory Commission (FERC or Commission) prepare and publish an annual report, by appropriate region, that assesses electricity demand response resources.
  2. Demand Response and Smart Metering Policy Actions Since the Energy Policy Act of 2005: A Summary for State Officials (National Council on Electricity Policy, Fall 2008) (PDF 980KB)
  3. FERC Report: Demand Response Could Cut U.S. Peak Power Demand by 20% - The FERC report also includes a state-by-state breakdown of four scenarios, providing a guide for legislators and utility commissioners as they evaluate their policy options for demand response. See the FERC overviewand the full report
  4. - This website was created so people can come discuss and learn about energy demand side management.
  5. Research Into Action, Inc., - 2008 Process Evaluation of California Statewide Aggregator Demand Response Programs - This process evaluation is Volume 3 of a three-part project focused on aggregator-driven demand response programs operating in California in 2008. This evaluation investigated three demand response programs operating in the territories of California's three IOUs: PG&E, SCE, and SDG&E.The three demand response programs include:

    1. CBP - Capacity Bidding Program - a statewide program operating in the territories of all three IOUs.
    2. AMP - Aggregator Managed Portfolio - offered by PG&E.
    3. DRC - Demand Response Resource Contracts - offered by SCE.

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