Friday, August 17, 2012

High Voltage DC Transmission (HVDC)


For long-distance distribution, HVDC systems are less expensive and suffer lower electrical losses


HVDC Interconnections in Western Europe - red are existing links, green are under construction, and blue are proposed. Many of these transfer power from renewable sources such as hydro and wind.


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Back to Transmission
1. Background
2. Acronyms/Definitions
3. Business Case
4. Benefits
5. Risks/Issues
6. Next Steps
7. Companies
8. Links


1.Background
  • Alternating current is a wave of electrons flowing back and forth through a wire. The properties of AC current allow the voltage to be stepped up dramatically higher by transformers, and the higher the voltage, the less electric power is lost in transmission.
  • Thomas Edison's original DC systems, launched in 1882, lacked the means to transform voltage t and so were limited by the size of the copper wire that carried the current. That forced him into a strategy of many small generators serving sections of cities. It is said "Edison had to build a plant for every five blocks."
  • High voltages cannot be easily used in lighting and motors, and so transmission-level voltage must be reduced to values compatible with end-use equipment. The transformer, which only works with alternating current, is an efficient way to change voltages.
  • The competition between the DC of Thomas Edison and the AC of Nikola Tesla and George Westinghouse was known as the War of Currents, with AC emerging victorious. By the early 1900s, AC dominated the scene, opening the way to ever larger generators, longer transmission lines and the monopolization of much of the industry.
  • The development of high power electronic devices such as mercury arc valves and later semiconductor devices, such as thyristors to regulate voltage put DC back in the picture. Today, banks of electronic switches are used to step up direct current for transmission, then bring it down at the end of the line. With that issue solved, DC's advantages versus AC become important in certain applications.
  • DC lines connect grids and transmit power from one point to another. Since the remainder of the power system uses AC, DC systems require a converter to convert (rectify) power from AC to DC as it goes into the DC power line and to reconvert (invert) it from DC to AC as it reenters the AC system.
  • High voltage is used for transmission to reduce the energy lost in the resistance of the wires. For a given quantity of power transmitted, higher voltage reduces the transmission power loss. Power in a circuit is proportional to the current, but the power lost as heat in the wires is proportional to the square of the current. However, power is also proportional to voltage, so for a given power level, higher voltage can be traded off for lower current. Thus, the higher the voltage, the lower the power loss. Power loss can also be reduced by reducing resistance, commonly achieved by increasing the diameter of the conductor; but larger conductors are heavier and more expensive.
  • For long-distance distribution, HVDC systems are less expensive and suffer lower electrical losses. For shorter distances, the higher cost of DC conversion equipment may be warranted where other benefits of direct current links are useful


2. Acronyms/Definitions
  1. AC - Alternating Current - the movement of electric charge periodically reverses direction. AC is the form in which electric power is delivered to businesses and residences. The usual waveform of an AC power circuit is a sine wave.

  2. Bulk Transmission - A function or voltage classification relating to the higher voltage portion of the transmission system, specifically, lines at or above a voltage level of 115 kV.

  3. DC - Direct Current - the unidirectional flow of electric charge. Direct current is produced by such sources as batteries, thermocouples, solar cells, and commutator-type electric machines of the dynamo type.

  4. Dielectric - An electrical insulator that can be polarized by an applied electric field. When a dielectric is placed in an electric field, electric charges do not flow through the material, as in a conductor, but only slightly shift from their average equilibrium positions causing dielectric polarization. Because of dielectric polarization, positive charges are displaced toward the field and negative charges shift in the opposite direction. This creates an internal electric field which reduces the overall field within the dielectric itself. "Dielectric" is typically used to describe materials with a high polarizability. while "insulator" is more often used when the material is being used to prevent a current flow across it.

  5. GTO – Gate Turn-Off Thyristor - a special type of thyristor, a high-power semiconductor device. GTOs, as opposed to normal thyristors, are fully controllable switches which can be turned on and off by their third lead, the GATE lead. Normal thyristors can only be turned ON and cannot be turned OFF. Thyristors are switched on by a gate signal, but even after the gate signal is de-asserted (removed), the thyristor remains in the On-state until any turn-off condition occurs (which can be the application of a reverse voltage to the terminals, or when the current flowing through (forward current) falls below a certain threshold value known as the "holding current"). Thus, a thyristor behaves like a normal semiconductor diode after it is turned on or "fired".

  6. HTS - High Temp Superconductor wire - Able to carry tremendous amounts of current with no losses (except for a small loss for the cooling systems). The ability to carry higher current values allows you avoid the costs of higher voltages. “High Temperature” is a relative term - 77K liquid nitrogen use temperature is “high” compared to the 5K liquid hydrogen used for conventional “Low Temperature” superconductors. In July 2010, Nexans, a leader in the cable industry, successfully completed a test of the world’s first HVDC high temperature superconductor (HTS) power transmission cable designed for 200 kV.

  7. IGBT - Insulated-gate bipolar transistors - A three-terminal power semiconductor device, noted for high efficiency and fast switching. It switches electric power in many modern appliances: electric cars, variable speed refrigerators, air-conditioners, and even stereo systems with switching amplifiers. Helps to make smaller HVDC systems economical. These may be installed in existing AC grids for their role in stabilizing power flow without the additional short-circuit current that would be produced by an additional AC transmission line.

  8. Mercury Arc Valve - Type of electrical rectifier which converts alternating current into direct current. Rectifiers of this type were used in electric motor power supplies for industry, in electric railways, streetcars and electric locomotives. They also found use in static inverter stations and as rectifiers for high-voltage direct current power transmission. Mercury arc rectifiers were invented by Peter Cooper Hewitt in 1902 and further developed throughout the 1920s and 1930s by researchers in both Europe and North America. Before the advent of solid-state devices, mercury arc rectifiers were one of the more efficient rectifiers. By 1975, high-voltage solid state devices such as the silicon diode and thyristor made the mercury arc rectifier obsolete even in high-voltage DC applications. With two exceptions, all former mercury rectifiers worldwide have been dismantled or replaced by thyristor units.

  9. Power MOSFET - A specific type of Metal Oxide Semiconductor Field-Effect Transistor (MOSFET) designed to handle large amounts of power. Compared to the other power semiconductor devices (IGBT, Thyristor...), its main advantages are high commutation speed and good efficiency at low voltages. It shares with the IGBT an isolated gate that makes it easy to drive.

  10. Resistance – The characteristic of materials to restrict the flow of current in an electric circuit. Resistance is inherent in any electric wire, including those used for the transmission of electric power. Resistance in the wire is responsible for heating the wire as current flows through it and the subsequent power loss due to that heating.

  11. Tie-line – The physical connection (e.g. transmission lines, transformers, switch gear) between two electric systems that permits the transfer of electric energy in one or both directions.

  12. Thyristor - (Tutorial) A solid-state semiconductor device with four layers of alternating N and P-type material. They act as bistable switches, conducting when their gate receives a current pulse, and continue to conduct while they are forward biased (that is, while the voltage across the device is not reversed)

    Since modern thyristors can switch power on the scale of megawatts, thyristor valves have become the heart of high-voltage direct current (HVDC) conversion either to or from alternating current. In the realm of this and other very high power applications, both electronically switched (ETT) and light switched (LTT) thyristors are still the primary choice. The valves are arranged in stacks usually suspended from the ceiling of a transmission building called a valve hall. Thyristors are arranged into a Graetz bridge circuit and to avoid harmonics are connected in series to form a 12 pulse converter. Each thyristor is cooled with deionized water, and the entire arrangement becomes one of multiple identical modules forming a layer in a multilayer valve stack called a quadruple valve. Three such stacks are typically hung from the ceiling of the valve building of a long distance transmission facility
    Two of three thyristor valve stacks used for long distance transmission of power from Manitoba Hydro dams

  13. Underground Power Lines -Useful in cities and in areas where views and vistas have significant social value. Air cools overhead electric lines, but engineers have had to find other ways to cool underground lines. They typically use an oil system that employs pumps to circulate the oil. Because these cooling systems are expensive and because it is costly to dig trenches for the lines, it is more expensive to bury power lines underground than to string them above ground. Although underground lines are away from weather, vegetation and vehicles, they also are more difficult to access, it is more difficult to pinpoint the location of a fault, and their cooling systems can fail.

  14. Voltage Drop - The reduction in voltage in the passive elements (not containing sources) of an electrical circuit. Voltage drops across conductors, contacts, connectors and source internal resistances are undesired as they reduce the supplied voltage. Power lines carry electricity over long distances, but the electrical energy gradually dissipates into the air in the form of heat. In addition, much as water flowing through a pipe gradually loses pressure, electricity gradually drops in voltage when it is transmitted over long distances. Voltage drops can be cured by devices called capacitors, but at a cost of more energy lost. The United States as a whole loses nearly 10 percent of all the power it generates to these technical limitations. So, although it is technically possible to generate power in the Dakotas with wind turbines to supply the large parts of the nation’s electrical needs, it is not practicable to deliver that power over such a long distance using the existing AC transmission system.

  15. VSC - Voltage Source Converter - (Thank you to Peter Vaessen for this definition. VSC HVDC is based upon transistor technology and was developed in the 1990′s. The switching element is the Insulated Gate Bipolar Thyristor (IGBT), which can be switched on and off by applying a suitable voltage to the gate (steering electrode). Because of the more switching operations, and the nature of the semiconductor devices itself, the converter losses are generally higher than those of HVDC classic converters.

    VSC HVDC is commonly used with underground or submarine cables with a transfer capacity in the range of 10 – 1000 MW, and is suitable to serve as a connection to a wind farm or supply a remote load. VSC HVDC technology has very fast steer and control functionality and is suitable for meshed networks. It is characterised by compactness of the converter stations, due to the reduced need for AC harmonic filters and reactive power compensation. Power flow reversal in VSC systems is achieved by reversal of the current, whereas in HVDC classic systems the voltage polarity has to change. An important consequence of this voltage source behavior is the ability to use cheaper and easier to install XLPE cables, instead of the mass-impregnated cables that are needed for HVDC classic.

    Currently, only twelve VSC HVDC projects are in service. A few examples include: Estlink, which connects Estonia to Finland (350 MW), and BorWin1, connecting an offshore wind farm to Northern Germany (400 MW). Both are equipped with ±150 kV submarine cables, and the Trans Bay project in California (400 MW) that consists of 90 km ±200 kV submarine cable.

    Most projects have submarine cable, but some projects include long lengths of underground cable, such as Murraylink (220 MW, 177 km underground cable), and Nord E.On 1 (400 MW, 75km underground cable).

    The 500 MW East-West interconnector between Ireland and Great Britain, operating at ±200 kV, is scheduled to go into service in 2012. A 2000 MW 65 km cable interconnector ±320kV as part of the Trans European Network—between Spain and France—is scheduled for commissioning in 2013, and will represent the highest power rating for a VSC HVDC system installed at this time.




Direct Current Contributes about 2% of the total high voltage transmission lines in the United States

3. Business Case
  • Despite its cost, HVDC lines can cost-effectively connect low-cost power plants to higher cost regions of the country. A HVDC line might carry 1,000 MW to 3,000 MW. For example, wind and coal resources in the Great Plains could be shipped via HVDC lines to load centers to the east or west. HVDC lines now connect low-cost hydroelectric resources in northern Canada to U.S. markets.
  • HVDC has the ability to transmit large amounts of power over long distances with lower capital costs and with lower losses than AC. Depending on voltage level and construction details, losses are quoted as about 3% per 1,000 km. High-voltage direct current transmission allows efficient use of energy sources remote from load centers.
  • Examples of DC systems used to connect power grids include the DC lines that allow power to flow from the Western Interconnection to the Eastern Interconnection. The AC/DC/AC connection acts like an air lock between two systems that have no AC connections—power flows can be controlled precisely between the systems up to the limits of the converter station. DC has not been used to deliver power to customers because of the cost of the AC/DC converters. A converter station costs in the range of $50 million, and a DC line requires a converter station at each end to connect to the AC grid. This is far more expensive than the transformers that step AC transmission voltages down to typical voltages that consumers use.
  • In Itaipu, Brazil, HVDC was chosen to supply 50Hz power into a 60 Hz system; and to economically transmit large amount of hydro power (6300 MW) over large distances (800 km)
  • In Leyte-Luzon Project in Philippines, HVDC was chosen to enable supply of bulk geothermal power across an island interconnection, and to improve stability to the Manila AC network
  • In Rihand-Delhi Project in India, HVDC was chosen to transmit bulk (thermal) power (1500 MW) to Delhi, to ensure: minimum losses, least amount right-of-way, and better stability and control.
  • In Garabi, an independent transmission project (ITP) transferring power from Argentina to Brazil, HVDC back-to-back system was chosen to ensure supply of 50 Hz bulk (1000MW) power to a 60 Hz system under a 20-year power supply contract.
  • In Gotland, Sweden, HVDC was chosen to connect a newly developed wind power site to the main city of Visby, in consideration of the environmental sensitivity of the project area (an archaeological and tourist area) and improve power quality.
  • In Queensland, Australia, HVDC was chosen in an ITP to interconnect two independent grids (of New South Wales and Queensland) to: enable electricity trading between the two systems (including change of direction of power flow); ensure very low environmental impact and reduce construction time.


4. Benefits
  • Greater Capacity- HVDC can carry more power per conductor, because for a given power rating the constant voltage in a DC line is lower than the peak voltage in an AC line. DC does not have the 1.4 factor for the peaks that go with sine waves, so there is that advantage regarding the working voltage versus the peak voltage allowable. In AC power, the root mean square (RMS) voltage measurement is considered the standard, but RMS is only about 71% of the peak voltage. The peak voltage of AC determines the actual insulation thickness and conductor spacing. Because DC operates at a constant maximum voltage without RMS, this allows existing transmission line corridors with equally sized conductors and insulation to carry 29% more power into an area of high power consumption than AC, which can lower costs.
  • Easier Interconnection - AC transmission lines can only interconnect synchronized AC networks that oscillate at the same frequency and in phase. Many areas that wish to share power have unsynchronized networks. The power grids of the UK, Northern Europe and continental Europe are not united into a single synchronized network. Japan has 50 Hz and 60 Hz networks. Continental North America, while operating at 60 Hz throughout, is divided into regions which are unsynchronized: East, West, Texas, Quebec, and Alaska. Brazil and Paraguay, which share the enormous Itapúa hydroelectric plant, operate on 60 Hz and 50 Hz respectively. However, HVDC systems make it possible to interconnect unsynchronized AC networks, and also add the possibility of controlling AC voltage and reactive power flow. A generator connected to a long AC transmission line may become unstable and fall out of synchronization with a distant AC power system. An HVDC transmission link may make it economically feasible to use remote generation sites.

    TresAmigas, has an ambitious plan to link America’s three vast interconnections –- east, west, and Texas –- via a 5-gigawatt, HVDC power line installed at a superstation just outside of Clovis, New Mexico.
  • System Reliability - Because HVDC allows power transmission between unsynchronized AC distribution systems, it can help increase system stability, by preventing cascading failures from propagating from one part of a wider power transmission grid to another. Changes in load that would cause portions of an AC network to become unsynchronized and separate would not similarly affect a DC link, and the power flow through the DC link would tend to stabilize the AC network. The magnitude and direction of power flow through a DC link can be directly commanded, and changed as needed to support the AC networks at either end of the DC link.
  • Less Interference - DC lines, have a lot less interference in them which makes it easier to run them in existing right of ways such as a railroad corridor. DC lines don’t present any of the electromagnetic field concerns that often cause concern for abutters and the towers can be built smaller.
  • Undersea/Underground Capability - Wind farms located off-shore may use HVDC systems to collect power from multiple unsynchronized generators for transmission to the shore by an underwater cable. DC has long been used for underwater electric transmission. Long undersea cables have a high capacitance. While this has minimal effect for DC transmission, the current required to charge and discharge the capacitance of the cable causes additional I2R power losses when the cable is carrying AC. In addition, AC power is lost to dielectric losses. For a relatively small increase in cost compared with overhead lines, it is possible to lay HVDC transmission lines under ground or underwater, thus minimizing their visual impact and speeding up planning applications
  • Improved Air Quality - HVDC transmission lines, by contrast with HVAC lines, produce hardly any electro smog.
  • Control - Pepco Holdings Inc. in Washington, D.C., chose direct current for a major part of a proposed line that would run from northern Virginia under the Chesapeake Bay and into the Delmarva Peninsula. The lower part of the Delmarva peninsula is a kind of cul-de-sac for electricity flow. Adding a new AC line into the area might not alleviate power shortages in the rural southern area because of the difficulty in controlling where the more willful AC current flows. Once the line was connected to the existing grid, the greater demand for power to the north could shift flows in that direction, leaving the southern part still short of power. Using DC permits Pepco to channel power precisely to the point in the AC grid where it is most needed.
  • Cost - HVDC lines can can carry more power over long distances than a comparable AC link. According to ABB, a 2,000-kilometer-long HVDC line rated at 80 kilovolts loses about 5 percent of the electricity it carries to hear, while an equivalent AC line would lose about 10 percent.


5. Risks/Issues
  • Conversion - The required static inverters are expensive and have limited overload capacity. At smaller transmission distances the losses in the static inverters may be bigger than in an AC transmission line. The cost of the inverters may not be offset by reductions in line construction cost and lower line loss.
  • Switching - In contrast to AC systems, realizing multi-terminal systems is complex, as is expanding existing schemes to multi-terminal systems. High voltage DC circuit breakers are difficult to build because some mechanism must be included in the circuit breaker to force current to zero, otherwise arcing and contact wear would be too great to allow reliable switching. Multi-terminal lines are rare.
  • Control - Controlling power flow in a multi-terminal DC system requires good communication between all the terminals; power flow must be actively regulated by the control system instead of by the inherent properties of the transmission line.
  • Spare Part Expense which may be used exclusively in one system as HVDC systems
  • are less standardized than AC systems and the used technology changes fast.
  • Lack of Local Benefit - DC lines have no benefit for those it passes because the facility is at one end of the line and the power is going to the other with a huge tower, high voltage lines and no real benefit accruing to those who live along/under the lines. The DC construction would amount an “extension cord,” and makes it clear to transmission project abutters that their burden is explicitly to someone’s else’s benefit.




6. Next Steps


  • The Tres Amigas SuperStation focuses on uniting North America’s two major power grids (the Eastern Interconnection and the Western Interconnection) and one minor grid (the Texas Interconnection) to enable faster adoption of renewable energy and increase the reliability of the U.S. grid.

    Tres Amigas’ development strategy emphasizes a phased approach to growth, building the Superstation overtime using 750 MW VSC block increments. The phases are designed to add VSCs as needed, dictated by customer demand, as follows:



    The Tres Amigas SuperStation will tie the grids together via three 5 GW superconductive high-voltage direct current power transmission lines, which permit a controlled flow of energy while also functionally isolating the independent AC frequencies of each side. The design is scalable to 30 GW.
    Tres Amigas Development Plan



    Tres Amigas uses high-temperature superconductor (HTS) wire. The Tres Amigas super station will be located on a 22-square-mile plot of land near Clovis, New Mexico. Early estimates of the cost put the project budget at around $600 million.

    In April 2011, Alstom Grid won the contract, worth at least 150 million Euros, to deliver the High Voltage Direct Current (HVDC) converter to the Tres Amigas Superstation. The 750 megawatt/345 kilovolt converter will play at central role at Tres Amigas.

    The Tres Amigas SuperStation will act as a power market hub, enabling the buying and selling of electricity among three of North America's largest interconnections, which is not possible today. Construction, overseen by CH2M Hill begins in 2012 and ideally it will become operational in 2014.

    Tres Amigas, LLC will unite the nation's electric grid. Utilizing the latest advances in power grid technology, Tres Amigas is focused on providing the first common interconnection of America's three power grids to help the country achieve its renewable energy goals and facilitate the smooth, reliable and efficient transfer of green power from region to region
In March, 2010, Tres Amigas obtained all of the necessary FERC approvals to sell transmission service at negotiated, or market-based, rates. FERC approvals apply to all phases of the development plan. Occidental has appealed the FERC approval in DC Circuit court, but should be resolved shortly.

FERC declined to disclaim jurisdiction over prospective transmission facilities to interconnect Tres Amigas and the Electric Reliability Council of Texas ("ERCOT"), stating it did not have the information necessary to grant the request. The Commission went on to state that upon receipt of a valid application (210/211 process), the Commission could issue orders to allow Tres Amigas to proceed and interconnect with ERCOT without conferring FERC jurisdiction over ERCOT utilities.

Tres Amigas is developing an OATT filing which is expected to filed during the second quarter. As part of the filing, Tres Amigas will provide an ancillary services plan, and seek market-based rates for those services.

Tres Amigas is negotiating with anchor tenant prospects and has ongoing discussions with local wind generators, gas producers, CAES developers, and trading companies. We are also working on plans related to ‘open season’ auctions.

Tres Amigas is negotiating IA’s with PNM and SPS/SPP. These studies are nearing completion with exchanged drafts. The company expects to file with FERC in third quarter 2012.

Tres Amigas will miss its target July 2012 groundbreaking because of delays in lining up industrial revenue bonds.  Industrial revenue bonds are issued and sold by the county to exempt companies from most of the property taxes on land, buildings and equipment for improvements to a facility.  The county will receive payments in lieu of taxes for the duration of the bond.

To date, the developers have raised $25 million against the $500 million cost of the first phase. Negotiations for the additional funds are going well, but Tres Amigas needs Public Service Company of New Mexico and the eastern grid’s Southern Power Pool to sign agreements to interconnect with their transmission lines before closing the financing.

Tres Amigas is now seeking $500 million in investment bank funding and private equity to begin construction.  Those efforts are advanced, but negotiations won’t conclude until Tres Amigas secures a commitment from Curry County for $1.9 billion in industrial revenue bonds. It also needs Public Service Company of New Mexico and the eastern grid’s Southern Power Pool to sign agreements to allow Tres Amigas to interconnect with their transmission lines before closing on financial deals.

The Curry County Commission is expected to authorize the IRBs in August.  Assuming the bonds cover 100 percent of eligible taxes for 20 years, they could help Tres Amigas avoid about $160 million in tax payments.

Meanwhile, PNM already approved an interconnect lph said. agreement with Tres Amigas in July. A separate agreement with SPP is expected in August.  With the IRBs and interconnect agreements done, Tres Amigas thinks it can raise the $500 million for the first phase.  The company estimates that will take eight to ten weeks, followed by ground breaking in late October or early November 2012.


7. Companies
  1. ABB - Won an approximately $1 billion order from Dutch-German transmission grid operator TenneT to build the world’s largest offshore HVDC (high-voltage direct current) system. The system, planned to go operational in 2015, will connect Germany’s offshore North Sea wind farms to its mainland grid. Germany intends to double its present 27 gigawatts of wind capacity -- eight percent of its electricity requirements -- by 2020. Much of the new capacity will have to be offshore because so many of the available land sites have been used.

    The 400-megawatt Gode Wind II wind farm is the third German offshore project that ABB has been tapped to connect to the grid. The company will design, engineer, supply and install a 900-megawatt-carrying-capacity HVDC land and sea cable system, the offshore platform, and the offshore and onshore converter stations.

    The highly efficient 320-kilovolt HVDC lines, which limit electrical losses to less than 1 percent per converter station, will take the power generated at Gode Wind II and other wind farms to an offshore HVDC converter station. From there, the electricity will be transferred via 135 kilometers of underwater and underground cables to an onshore HVDC station at Dörpen on the German coast, and from there will travel to the mainland grid.

  2. Tres Amigas LLC - Santa Fe, New Mexico, moving HQ to downtown Albuquerque - See Discussion in 6. Next Steps above.  The management team is negotiating leases on two buildings now and will announce their locations in the next few weeks. Remodeling those facilities and installing command-and-control equipment would be part of phase-one construction to get the centers up and running before the first phase of Tres Amigas comes online.

    Apart from managing the Superstation, the control centers would oversee the buying and selling of electricity between power generators and utilities, converting New Mexico into a national hub for clean electricity trading, much like a stock exchange for electric markets. Financial firms and brokers could establish operations nearby to manage trade deals, similar to the Chicago Mercantile Exchange.

8. Links

Thursday, August 16, 2012

Community Choice Aggregation

Procures renewable sources of electricity and partners with a utility to distribute energy to local communities, You get all the advantages of cleaner, greener, healthier energy consumption AND all of the advantages of the established, experienced energy provider.


Navigate this Report
Back to Markets and Pricing Index
1. Background

2. Acronyms/Definitions
  • In the past, one utility provided the all components of energy service: generation, transmission, distribution and retail. Legislatures and the public utility commissions (PUC) of many states have created competition for electricity and natural gas supply. This allows consumers to choose their energy supplier, while the delivery of the energy is still regulated and is the responsibility of the local utility company.
  • The electric power industry is commonly split up into four processes
    1. Electricity Generation - The process of generating electric energy from other forms of energy.
    2. Electric power transmission or "high voltage electric transmission" is the bulk transfer of electrical energy, from generating power plants to substations located near population centers. Historically, transmission and distribution lines were owned by the same company, but over the last decade or so many countries have liberalized the electricity market in ways that have led to the separation of the electricity transmission business from the distribution business.
    3. Electricity distribution - The final physical stage in the delivery of electricity to end users, the Wooden Pole System”
    4. Electricity Retailing
  • 2002 the California Legislature passed AB 117, California Community Choice Aggregation adding Section 366.2, among others, to the Public Utilities Code. The law gives local governments the ability to combine electricity loads within their communities and act on behalf of those customers to buy or choose electricity for them.

2. Acronyms/Definitions
  1. California State Bill 790 (SB790 - Leno) California Public Utilities Commission (CPUC) recently found that utility opposition to CCA has forced CCA efforts in some communities to be abandoned. The introduced California State Bill 790 (SB 790) ensures that CCA remains a viable option for local governments as intended by the original Assembly Bill 117 and by the voters who opposed Proposition 16 in 2010. CCA has been extremely difficult to implement for local governments, in large part due to the ability of incumbent utilities to actively block CCA start-up efforts. Existing law requires utilities to cooperate fully with communities seeking to establish a CCA. SB790 would clarify ambiguous language in the original Assembly Bill 117 to improve cooperation between local governments and investor owned utilities.

    Additionally, the introduced Assembly Bill SB790 would direct Public Purpose energy efficiency funds from PG&E to the CCA. Public Purpose funds account for 3 percent of the City-wide PG&E bills, which amounts to millions of dollars each year. These Public Purpose funds are currently distributed across the state and consumed partly by PG&E overhead costs and ineffective programs. Cities have very little input as to how Public Purpose funds are spent in their jurisdictions. The CCA would allow the City to develop more effective Public Purpose funded energy programs for the community and create more job opportunities for residents.

  2. California Senate Bill 843 - SB 843 - Community-Based Renewable Energy Self-Generation Program - establishes a new program allowing investor-owned utility (IOU) customers to purchase an interest in a "community
    renewable energy facility" and receive a bill credit for the generation component of the customer's electrical service.

    SB 843 establishes a new program to allow any IOU customer to pursue off-site renewable energy. Based on the successful model established between PG & E, the City of Davis and the PVUSA solar facility, this bill allows all participating customers to receive a credit on their electricity bills for the clean power they purchase at an off-site renewable energy facility. Allowing customers to opt into larger energy facilities and pool their resources will reduce the price they pay for clean energy, and access to this renewable energy will be increased.

    The author indicates that "?only a small percentage of California homes and businesses are appropriate sites for renewable energy. Many customers are interested in using solar energy, but the arrangement at their home or business is not a good match for installing solar. For example, some customer sites - both businesses and residences are overly shaded or not oriented in the proper direction; in many cases customers are renters who do not own the property at which they live.

    The bill allows for Californians to access an optimally located renewable energy facility, shared by multiple customers, rather than being limited to renewable energy options on their own property.

    Southern California Edison (SCE) opposes the bill for numerous reasons. According to SCE, "the core transaction in the program is essentially a wholesale sale of electricity
    at an administratively determined price, under a mandatory purchase obligation, with payment made in the form of a retail bill credit to participants in the program. Viewed in this
    manner, the program conflicts with federal law?SB 843 also raises the specter of unregulated entities participating in the retail energy market.

    As of August 16, 2012, this bill has passed the California Senate (38-0) and Asm Utilities and Commerce Committe: (10-2) and was under consideration by the Assembly Appropriations Committee

    Specifically, this bill:

    1. Limits a community renewable energy facility to 20 megawatts (MW) capacity and requires the facility to be located in the service territory of an IOU with more than 100,000 customers and be an eligible renewable facility pursuant to the state's Renewable Portfolio Standard (RPS) program.

    2. Limits the statewide capacity of community renewable energy facilities to 2,000 MW, and requires the Public Utilities Commission (PUC), when statewide capacity reaches 1,500 MW to determine whether the 2,000 MW limit is necessary or can be raised or eliminated based on the commission's determination of the impacts on IOU ratepayers.

    3. Requires the PUC to establish a facility rate, as specified, for each community renewable energy facility and, by December 31, 2014, to determine a methodology for calculating an "added value," as specified, of the community renewable energy facility, in order to determine the participant's bill credit, which shall be applied to the generation component of the participant's electricity service charges from their IOU. (Once the added value is determined, the higher of the facility rate or added value shall be used to determine the participant's bill credit.)

    4. Requires the PUC to reevaluate the added value methodology every three years in order to maintain the program goals, including indifference of ratepayers not benefiting from the program.

    5. Limits the interest of non-public entities participating in a community renewable generation facility to 2 MW of generating capacity.

    6. Stipulates that interconnection process and cost allocation for facilities under this program are to be determined under rules established by the PUC.


  3. California Assembly Bill  117 - The passage of AB 117 came in response to the 2000 energy crisis and the ensuing bankruptcy of Pacific Gas and Electric Company, which darkened much of the state and sucked billions of dollars from the economy into the coffers of Texas energy corporations. AB 117 was a strategic shift in a decades-old campaign to wrest economic power away from giant corporate utilities like PG&E and Southern California Edison and the big energy companies that supply them with electricity. AB 117 eliminated the need to own the energy grid and enabled  Community Choice Aggregation, or CCA. a new model of energy provisioning.  
  4. California Assembly Bill 976 (AB 976 - Hall) - Would prohibit a community choice aggregator (CCA) from procuring electricity or energy services from any entity that provided any analysis, advice, consultation or other services to the CCA prior to it providing the 30-day notice to the incumbent utility of commencement of service to customers. This bill would create a new barrier to the formation of any Community Choice Aggregation (CCA) programs.

  5. CCA - Community Choice Aggregation - Allows cities and counties to pool their citizens’ purchasing power to buy electricity.

  6. CRS - Cost Responsibility Surcharge - The CRS is a charge the utilities will assess on CCA customers in order to prevent the shifting of generation-related costs onto remaining utility customers that might result from transfer of electric service to a CCA. The CRS includes costs incurred by the California Department of Water Resources for contracts entered into during the 2000-2001 energy crisis as well as costs incurred by the utilities for generation and power purchase contracts. AB 117 directed the CPUC to establish the CRS before it authorizes implementation of CCA, and the CPUC designated this phase of the proceeding to determine the methodology and issues surrounding the calculation of the CRS.

  7. ESP - Energy Service Providers -

  8. H Bond Authority - San Francisco ordinance (Charter Section 9.107.8, Ammiano), which combined the power purchasing authority of CCA with a revenue bond authority to finance the new green power infrastructure, worth approximately $1 Billion.

  9. IPP – Independent Power Producer – Produce and sell electricity on the wholesale market at market-based rates, and do not have franchised service territories. Most are designated as exempt wholesale generators, which relieves them of many of the regulatory requirements applicable to traditional utilities subject to FERC regulation. Allowed fair access to transmission system by FERC Orders 888 and 889).

  10. MASH - Multifamily Affordable Solar Housing - Solar PPAs are now being successfully utilized in the California Solar Initiative's MASH program.

  11. PPA - Power Purchase Agreement- A legal contract between an electricity generator (provider) and a power purchaser (host). The power purchaser purchases energy, and sometimes also capacity and/or ancillary services, from the electricity generator. One of the key benefits of the PPA is that by clearly defining the output of the generating assets (such as a solar electric system) and the credit of its associated revenue streams, a PPA can be used by the PPA provider to raise non-recourse financing from a bank or other financing counterparty.

  12. Propostion 16 - A defeated California Initiative. PG&E qualified Proposition 16 for the June 2010 ballot. Titled the “The Taxpayers Right to Vote Act" , the measure requires local governments to obtain the approval of 2/3 of voters before providing electricity to new customers or expanding service to new territories if any public funds or bonds are involved. The measure would make it very difficult for local communities to switch from PG&E and other investor-owned utilities (IOUs) to municipal-owned utilities (MUNIs) To date, PG&E has been the sole contributor to the Yes on Prop. 16 political action committee (PAC)—contributing a total of $19 million to support the measure as of March 9, 2010.

  13. PUHCA – Public Utility Holding Company Act. This first major federal regulation of the electric power industry signed in 1935 by President Roosevelt. PUHCA limits the geographical scope of utility holding companies and the corporate structure of the holding companies. The act of created vertically integrated utilities (owning both power plants and power lines) in monopoly service areas. The Federal Power Act gave the Federal Power Commission jurisdiction over wholesale power sales and over transmission of electric power. States retain jurisdiction over siting of generation and transmission and over distribution rates. This combination of federal and state regulation of the industry remained in much the same form for close to a half century.

  14. PURPA - 1978 Public Utility Regulatory Policies Act - Passed at a time when the nation was focused on what appeared to be a steady stream of oil price increases and a great deal of concern about energy imports from politically unstable countries. PURPA was ground-breaking because, for the first time, it required that utilities buy power from companies that were not utilities. PURPA created a new industry of nonutility power generators. It was important to transmission policy because it required that the nonutility generators be given access to the transmission system in order to deliver their power onto the grid.

  15. RPS - Renewable energy Portfolio Standards - A regulation that requires the increased production of energy from renewable energy sources, such as wind, solar, biomass, and geothermal. The RPS mechanism places an obligation on electricity supply companies to produce a specified fraction of their electricity from renewable energy sources. Certified renewable energy generators earn certificates for every unit of electricity they produce and can sell these along with their electricity to supply companies. Supply companies then pass the certificates to some form of regulatory body to demonstrate their compliance with their regulatory obligations.

  16. SPPA - Solar Power Purchase Agreement - Depends heavily on the existence of the solar investment tax credit, which was extended for eight years under the Emergency Economic Stabilization Act of 2008. The SPPA relies on financing partners with a tax appetite who can benefit from the federal tax credit. Typically, the investor and the solar services provider create a special purpose entity that owns the solar equipment. The solar services provider finances, designs, installs, monitors, and maintains the project. As a result, solar installations are easier for customers to afford because they do not have to pay upfront costs for equipment and installation. Instead, customers pay only for the electricity the system generates.

  17. Utility Cooperative - A type of cooperative that is tasked with the delivery of a public utility such as electricity, water or telecommunications to its members. Profits are either reinvested for infrastructure or distributed to members in the form of "patronage" or "capital credits", which are essentially dividends paid on a member's investment into the cooperative.

    Each customer is a member and owner of the business with an equal say as every other member of the cooperative, unlike investor-owned utilities where the amount of say is governed by the number of shares held.

    Many such cooperatives exist in the rural United States, and were created by the New Deal to bring electric power and telephone service to rural areas, when the nearest investor-owned utility would not provide service, believing there would be insufficient revenue to justify the capital expenditures required. Many electric cooperatives have banded together to form their own wholesale power cooperatives, often called G & Ts, for generation and transmission, to supply their member-owners with electricity.

    Many utility cooperatives strive to bring the best service at the lowest possible cost, but often the high cost of maintaining the infrastructure needed to cover large, rural areas without the support of large cities as a rich customer base causes prices to be high. However, a few such co-ops have managed to tap into urban markets (due to growth into previously rural territory served by the co-ops) and have proven to be very cost-effective.

3. Business Case
  • Former Federal Energy Regulatory Commission member Nora Brownell says CCAs are "the only great exceptions to the failure of electric deregulation in the U.S." With every CCA yet formed still in operation and charging ratepayers less per kilowatt hour than their Investor-Owned-Utilities, CCAs have proven to be reliable and capable of delivering greener power at competitive prices. Ohio’s Office of the Consumer’s Council has said that CCA is “the greatest success story” in Ohio’s competitive market, and new legislation to re-regulate utility rates in Ohio will preserve CCA even if other forms of competition are eliminated. In Massachusetts, the success of the Cape Light Compact has led to the formation of new CCAs used in towns such as Marlborough, Massachusetts.
  • Community Choice Aggregation (CCA) is a system enabled by California Assembly Bill 117 (2002) that allows local governments to procure electric energy for residents and businesses within a community. CCA’s enabling legislation requires that investor-owned utilities such as Pacific Gas & Electric (PG&E) cooperate with local governments and provide electricity delivery over its existing distribution system and provide consumer metering, billing, collection and all traditional retail customer services (i.e., call centers, outage restoration, extension of new service).
  • A local government is not required to manage electric transmission or distribution services or develop infrastructure for CCA. PG&E must provide delivery services to CCA customers under the same terms and conditions as provided to other of its customers. It is important to distinguish CCA from municipal utilities and from investor owned utilities as each of these entities provides different services, has different responsibilities, and operates under different regulatory frameworks. Local governments that implement CCA programs do not become a municipal utility which owns and operates transmission and distribution systems. A critical distinguishing factor is that the City would not own the electric distribution system within the City. Rather, it would own or procure electric power from the wholesale markets through power purchase agreements and distribute electric power through PG&E’s existing infrastructure.
    CCA is a Hybrid Approach
  • Since 1997, CCA Laws have been passed by New Jersey, Ohio, Massachusetts, California, and Rhode Island.
  • The first CCA to form was the Cape Light Compact, which includes all of Cape Cod and nearby islands, which have power, gas and energy efficiency services for over fiveyears
  • The largest CCA to form so far was the Northeast Ohio Public Energy Council (NOPEC), which serves 650,000 customers with gas and electricity, switching them from utility coal and nuclear power to a gas and renewables portfolio with a guaranteed 5% discount below utility prices.

4. Benefits
  • Reduce Cost of Renewable Energy - Cut the cost of renewable energy projects like wind farms and solar panels by 50 percent or more.
  • Local Control - Shift political power away from large energy corporations and into the hands of local governments, residents, and small businesses. CCA shifts financial power away from corporate utilities and the California Public Utilities Commission (which many activists characterize as suffering from "regulatory capture" by the companies it is tasked with overseeing) and places the power of the purse in the hands of local officials. With this ability comes the potential for reinvesting in conservation and efficiency programs, creating new local jobs, and lowering consumers' energy bills.
  • Reliability - Take advantage of cutting-edge energy efficiency and demand response technologies to ease the burden on public utilities and improve system reliability and environmental performance.
  • Green and Local Jobs - Provide private sector incentives for the creation of local clean energy jobs and keep energy dollars circulating in the local economy. Attract investment and new, "green collar" manufacturing jobs;
  • Customer Choice - Light Green, Deep Green or PG&E. Competition in business
  • Cost Competitiveness - Cost at or below PG&E
  • Cost Stability - Predetermined supply costs
  • Support Communities RPS Goals
    • San Francisco with 51% RPS Goal includes 775,000 residents
    • Fresno County and 13 cities with accelerated 20% by 2010 RPS Goal includes over 1 million residents
    • Oakland-Emeryville-Berkeley CCA municipalities with 50% RPS Goal include 600,000 residents
    • Marin County and CCA municipalities with 50% RPS Goal include 247,289 residents
    • Chula Vista and neighboring municipalities in San Diego County with 40% RPS Goal includes 250,000 residents
    • LA County and CCA municipalities in LA County with 40% RPS Goal includes over 1 million residents
    • San Luis Obispo and Ventura CCA counties with 40% RPS Goal: over 1 million residents
    • Solano County CCA municipalities with 40% RPS Goal: 117,000 residents
  • Focus on Customer Needs - Rates set to tailor local needs


5. Risks/Issues
  • Non-Cooperation from Utilities - On May 3 2010 the California Public Utilities Commission's (CPUC) Executive Director notified PG&E that certain recent actions by the utility in Marin County, Calif., related to CCA have violated tariffs and rules and directed PG&E to immediately cease such actions.

    On April 9, 2010, the CPUC confirmed Marin Energy Authority (MEA) as a community choice aggregator in California. The CPUC has heard from members of the public and MEA that although PG&E has a statutory obligation to cooperate with community choice aggregators, instead the utility has been attempting to thwart MEA's efforts to launch the new CCA.

    After evaluating PG&E's actions, the CPUC's Executive Director sent a letter to the company, outlining actions that PG&E must immediately cease, including telephoning customers to ask them to opt out and then transferring the call that PG&E initiated to a PG&E customer service representative. The CPUC said that customers electing to opt-out of MEA service must do so only by the methods included in the customer notification provided by MEA - by the customer calling a phone number or visiting a website. PG&E cannot obtain an opt-out by using an opt-out form PG&E includes in a newspaper advertisement or by visiting a customer's residence and asking the customer to provide an oral or written opt-out during the visit.
    In addition, PG&E may no longer send mailers that have the appearance of an official opt-out notice to its customers in Marin County for the purpose of encouraging these customers to opt out of the CCA program established by MEA. These mailers are likely to create unnecessary customer confusion and therefore violate the statutory requirement that PG&E cooperate fully with any community choice aggregators.

    PG&E was directed to meet with the CPUC's Energy Division to identify the specific customers who have opted out of MEA service in the manners specified above and develop a way of informing these customers that their opt-outs are invalid.
  • Some CCA-related Matters are Still Pending Before the CPUC
    • Final methodology for calculating amount of the CCA bond required by AB 117 - ALJ is considering a June 2009 Settlement filed by IOUs and certain CCA interests
    • Draft Energy Division Resolution (April 8 Agenda) –Revises “opt-out” tariff language and clarifies rules regarding certain IOU activities vis-a-vis CCAs
    • City and County of San Francisco Petition to Modify Decision 05-12-041 – Filed January, 2010

6. Case Studies
  1. CleanPowerSF - San Francisco adopted a CCA Ordinance in 2004, creating a CCA program to build 360 Megawatts (MW) of solar, green distributed generation, wind generation, and energy efficiency and demand response to serve San Francisco ratepayers. Specifically, the ordinance combined the power purchasing authority of CCA with a revenue bond authority also developed by Fenn to expand the power of CCA. In 2007 the City adopted a detailed CCA Plan also written primarily by Fenn (Ordinance 447-07, Ammiano and Mirkarimi), which established a 51% Renewable Portfolio Standard by 2017 for San Francisco.

    As a community choice aggregation program, CleanPowerSF would only replace the
    energy generation component of PG&E service, which is about typically 20% or $15.00
    of a $75.00 residential gas and electric bill. PG&E would still continue to provide all
    other components of electric service, like responding to power outages, on-going
    maintenance of electrical distribution lines, meter reading and billing, and would still
    provide and charge for gas service. The CPUC approved San Francisco's implemenation plan in May 2010. In Nov 2010, the SFPUC received four bids in response to its CleanPowerSF Request for Proposals from Constellation Energy Commodities Group, Shell
    Energy North America, Power Choice Inc and Noble Americas Energy Solutions
    (formerly Sempra Energy Solutions). Once the scoring phase of the RFP concludes, the SFPUC will then enter into contract negotiations with the winning respondent to begin setting-up San Francisco’s clean energy program. Implementation is planned for late 2011.

  2. Groundswell - Washington, DC - Groundswell knits together a group of community institutions and assesses their aggregate energy needs. It then collects bids from energy suppliers who can offer competitive rates and often hire from within the local community.

    The latest purchase, which closed in March 2012, counted 103 groups from across Maryland and the District — more than twice the number that participated in the previous round. The Georgetown Presbyterian Church, Cesar Chavez Public Charter Schools for Public Policy and the NAACP were among the groups that took part.

    The nonprofit’s second purchase agreement saved 38 organizations a total of $215,000 on their annual energy bills, an average cost reduction of 12 percent



  3. Marin Energy Authority (MEA) - A Joint Powers Authority formed in 2008 comprised of local governments in Marin County: Belvedere, Fairfax, Mill Valley, San Anselmo, San Rafael, Sausalito, Tiburon and the County of Marin. MEA operates the Marin Clean Energy (MCE) program, which is a CCA now serving electric service customers in Marin County. Since the passage of Assembly Bill 117 in 2002, the MEA has formed the only CCA program in California.

    On February 2, 2010, CPUC certified its implemenation plan and MEA completed Phase I of its
    implementation in May 2010 to include 9,600 customers (mix of residential, municipal and commercial users) and will incrementally expand to provide electricity to all electric service customers in MEA jurisdiction by May of 2012.

    MEA provides electric service customers with a choice of electric service providers. Electric service customers may choose to buy electricity from PG&E or from MEA. MEA currently offers two options for their electric service customers: Light Green and Deep Green. Light Green has a 27 percent renewable energy content and was designed to mirror PG&E's rates. Electric service customers have the choice to upgrade to the Deep Green option which is 100 percent renewable energy and costs an additional 7 percent or about $5-10 per month.

    MEA is an “opt-out” program, which means customers are automatically enrolled in the program unless they specifically choose to continue with PG&E. All electric service customers receive four notifications from MEA prior to being automatically opted in to the MEA program. Electric service customers have the choice to purchase power from the MEA or PG&E. Electric service customers may choose to opt out at anytime and switch to PG&E.

    Since PG&E manages the customer service functions of the electric service, PG&E’s
    senior, low-income and disabled programs, as well as tiered pricing structures are still
    available to the electric service customers. Electric service customers continue to
    receive a PG&E bill; however the generation charges are returned to MEA by PG&E

  4. San Joaquin Valley Power Authority (www.communitychoice.info.) - On April 30, 2007, the CPUC authorized its first Community Choice Aggregation (CCA) application. The application was submitted by the Kings River Conservation District on behalf of San Joaquin Valley Power Authority (SJVPA). made up of Kings County and 8 local cities - Clovis, Dinuba, Hanford, Kerman, Kingsburg, Parlier, Reedley, and Sanger - to engage in regional energy planning and bring energy choice to local residents and businesses in the central San Joaquin Valley. The Authority prepared a Community Choice Implementation Plan and received certification by the California Public Utilities Commission on April 30, 2007. The Authority will set electrical generation rates for customers within its service area and will purchase power from the Kings River Conservation District. Conservative estimates on rates show a 5 percent savings on generation costs. In June 2009: the SJVPA Board temporarily suspended implementation activities.

  5. NOPEC - Northern Ohio Public Energy Council has been serving Ohio customers since September 2001. In December 2009, NOPEC entered into an agreement with FirstEnergy Solutions Corp. (FES), a subsidiary of FirstEnergy Corp. (NYSE: FE), making FES the generation supplier for customers in the 126 Northeast Ohio communities served by NOPEC. The agreement extends from January 1, 2011, through December 31, 2019. In addition, FES and Gexa Energy - NOPEC's current generation supplier - have signed a letter of intent that is expected to make FES the supplier for NOPEC communities in 2010.

    Through its innovative Powering Our Communities program, FES will make a onetime grant of $12 million, which will be administered by NOPEC for energy-related programs throughout its communities. The program will also provide residents and small businesses of those communities with guaranteed long-term electric generation savings that are expected to total an estimated $19 million a year, based on current generation prices. In addition to these savings, NOPEC will use funds it has available to offer its communities additional discounts.

    NOPEC's board chairman Joe Migliorini said, "We've once again been able to leverage our group buying power to obtain the most advantageous deal for our customers and member communities.

  6. Fulton, Illinois, In May 2011 the city of Fulton signed a three year agreement to buy its power from FirstEnergy Solutions. Fulton is the first city to take advantage of Illinois’ municipal aggregation laws and selected its own supplier. Customers may opt out of the aggregation program and shop for a different supplier or accept the standard rate offered by the utility. Residential customers will have a fixed price of 6.23 cents per kWh and small business will pay 6.04 cents per kWh with the agreement. These prices are approximately 20% less than ComEd’s current average generation rate. ComEd will continue to read meters, send monthly billing statements and maintain service for participants in the municipal aggregation program.

  7. Massachusetts’ Cape Light Compact - First enrolled customers in March 2002. The 1997 Massachusetts Restructuring Act enabled towns and cities to establish municipal aggregators like Cape Light Compact, that could:
    • Purchase power on behalf of all customers in the municipality
    • Implement the energy efficiency programs instead of the local electric utility
    • Administer rate-payer funded surcharge. This charge appears on monthly electric bills as the “Energy Conservation” charge and is one of the funding sources for Cape Light Compact’s Energy Efficiency Programs, which are available to every resident and business on Cape Cod and Martha’s Vineyard regardless of which electric supplier the ratepayer chooses.

    The compact serves 200,000 consumers from all 21 towns on Cape Cod and Martha’s Vineyard and offers comprehensive approach to energy services:
      • Competitive electricity rates with a green energy option
      • Effective consumer advocacy
      • Proven energy efficiency programs
      • Energy education
    • CCA Feasibility Studies
      • City of Berkeley - The Final Base Case Feasibility Study for the City of Berkeley was completed in April 2005. The analysis indicated the City is likely to obtain cost savings equal to over $5 million per year or approximately 6% of customers’ electricity bills on average over the study period. The analysis showed that a 50% renewable energy target can be achieved with no rate increases for customers if the City is willing to finance renewable resource development to supply the CCA program.
      • City of Emeryville - The Final Base Case Feasibility Study for the City of Emeryville was completed in March 2005. The analysis indicated the City is likely to obtain cost savings equal to over $3.7 million per year or approximately 10% of customers’ electricity bills on average over the study period. The analysis shows that a 50% renewable energy target can be achieved with no rate increases for customers if the City is willing to finance renewable resource development to supply the CCA program.

      • City of Oakland - The Final Base Case Feasibility Study for the City of Oakland was completed in April 2005. The analysis indicated the City is likely to obtain cost savings equal to over $17.9 million per year or approximately 5% of customers’ electricity bills on average over the study period. The analysis shows that a 50% renewable energy target can be achieved with no rate increases for customers if the City is willing to finance renewable resource development to supply the CCA program.

      • City of Pleasanton - The analysis indicated the City is likely to obtain cost savings equal to approximately $6.6 million per year or approximately 5% of customers’ electricity bills on average over the study period. The analysis shows that a 50% renewable energy target can be achieved with no rate increases for customers if the City is willing to finance renewable resource development to supply the CCA program. The City of Pleasanton is currently evaluating whether to move forward in developing a potential CCA.
      • City of Richmond - The analysis indicated the City is likely to obtain cost savings equal to over $6.6 million per year or approximately 7% of customers’ electricity bills on average over the study period. The analysis shows that a 50% renewable energy target can be achieved with no rate increases for customers if the City is willing to finance renewable resource development to supply the CCA program.

7. Companies/Organizations
  1. Constellation Commodity Energy, Bidder of CleanPowerSF contract and the largest wholesale energy company in North America. Subsidiary of Constellation Energy, Baltimore, MD, a Fortune 200 company with 2006 revenues of $19.3 billion, is the nation's largest competitive supplier of electricity to large commercial and industrial customers and the nation's largest wholesale power seller. Constellation Energy also manages fuels and energy services on behalf of energy intensive industries and utilities. It owns a diversified fleet of 78 generating units located throughout the United States, totaling approximately 8,700 megawatts of generating capacity. The company delivers electricity and natural gas through the Baltimore Gas and Electric Company (BGE), its regulated utility in Central Maryland.

  2. Local Power Inc. - San Francisco, CA - An Energy Service Bureau helping cities adopt, implement and manage Community Choice Aggregation (CCA) energy networks. LPI's founders created Community Choice Aggregation (CCA), Solar Bonds and other major tools for green cities.

    Founded by Paul Fenn, who had served as Senator Montigny's Energy Advisor, formed Local Power (local.org and localpower.com), drafted new CCA legislation for California. In a campaign organized by Local Power, the City and County of San Francisco led Oakland, Berkeley, Marin County, and a group of Los Angeles municipalities in adopting resolutions asking for a state CCA law in response to the failure of California's deregulated electricity market. Fenn's bill was sponsored by then Assembly Member Carole Migden (D-San Francisco) in 2001, and the bill became law (AB117) in September, 2002.
  3. LEAN Energy US,  Local Energy Aggregation Network - San Rafael, CA - Helps local governments transition from corporate utilities to CCAs

  4. Noble America Energy Solutions - San Diego, CA - In Nov 2010, RBS Sempra Commodities (Joint venture between Royal Bank of Scotland and Sempra) completed the sale of its Sempra Energy Solutions business to Noble Americas Gas and Power Corp a subsidiary of Noble Group Hong Kong/Stamford, CT is a market leader in managing the global supply chain of agricultural, industrial and energy products. Our “hands on” approach to business has seen us grow to become a world leader in supply chain management in just 20 years. Their risk-management products are structured to meet the unique needs of each customer. One of four bidders for CleanPowerSF's supplier contract.

  5. One Block Off the Grid - San Francisco - just announced a $5 million round A of venture capital from New Enterprise Associates. OBOG is an online start-up which acts as a consumer solar advocate that engineers group discounts for solar purchases. The firm has helped to initiate almost 600 residential solar installations across the U.S. since the company's founding in 2008.

    The start-up goes into a geographical region, and launches a formal RFP campaign to identify a reliable solar installer with a track record of quality work, strong warranties and fair pricing. 1BOG then partners with that installer, obtains a group discount, and provides a pre-negotiated price to their customers.

  6. Power Choice Inc. - One of four bidders for CleanPowerSF's supplier contract. Formed in 2009 to serve the emerging needs of newly formed Community Choice Aggregation (CCA) and Direct Access programs, in California and elsewhere in the US. Their website is currently a single splash screen.

    Power Choice brings together an alliance of best-in-class energy services companies with several decades of experience in California and around the world. Currently, consortium members serve and manage an electrical power load greater than that of all California-based investor-owned utilities combined.

  7. SENA - Shell Energy North America, Houston, TX - Supplier to MCE and bidder to CleanPowerSF.

8. Links
  1. California Public Utility Commission - Community Choice Aggregation Home Page
  2. California Energy Commission - PIER Program Area: Renewable Energy Technologies- Community Choice Aggregation Pilot Project - In this pilot project, 12 California local governments evaluated the feasibility of implementing community choice aggregation programs through which a minimum renewable energy mix of 40 percent would be achieved, at least doubling the Renewables Portfolio Standard. Three groups of cities/counties went on to develop business plans through this program detailing how community choice aggregation programs for their regions would be organized, governed, funded, and operated to provide at least 50 percent renewable energy to participating customers.
  3. What is Community Choice Aggregation? Fact Sheet by Local Government Commission
  4. Local Government Coaltion - Final Report on California Public Utilities Commission Process to Implement Community Choice Aggregation -
  5. CCA Regulatory Updates - Noble Solutions
  6. CleanPowerSF on Twitter
  7. Marin Clean Energy Presentation to Richmond City CouncilVideo of Meeting May 23, 2011 Richmond City Council Resolution Staff Report June 2 MEA Meeting Marin IJ
  8. http://localpowerrevolution.blogspot.com/
  9. http://www.lgc.org/cca/
  10. CPUC Rejects SDG&E's Network Use Charge - The scoping memo and ruling (PDF)

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

1.Background
  • 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.

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. EnergyDSM.com - 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.