SmartGridCity - Boulder

Xcel Energy’s SmartGridCity™ Consortium provides the city of Boulder, Colorado a portfolio of smart grid technologies designed to provide environmental, financial and operational benefits. What can we learn from this project that started with exuberant hype and ended with acrimonious finger pointing?

Navigate this Report
Back to Case Studies Index
1. Background
2. Acronyms/Definitions
3. Business Case
4. Benefits
5. Risks/Issues
6. Participating Companies
7. Links

1.Background

• All told, SmartGridCity included automating three substations, laying 200 miles of fiber-optic cable and installing 4,600 residential and small business transformers and 16,000 smart meters.
• SmartGridCity™ integrated intelligent sensors, distributed communications and analytical control applications from the substation to the customer premise, enabling a host of high value applications. These applications are expected to provide significant utility and customer benefits including improved service reliability, reduced operations and maintenance costs, optimized system losses, reduced capital costs, better managed renewable energy resources, and reduced customer energy demand.
• Boulder, Colorado was the guinea pig because it is the right size (population of approximately 100,000 people), the home to the University of Colorado and also the National Institute of Standards and Technology, which is already involved in the project, and several other federal agencies.
  
• Plans are to spend $100 million to build a "smart-grid city" that will become a test bed for emerging power technologies.
• As of mid July, 15,000 smart meters have been installed in Boulder with another 10,000 planned. A web portal that shows consumers with smart meters their usage in 15 minute increments should be rolled out soon. A key element of the pilot is to understand if and how consumers with smart meters change usage relative to those without such information, as the success of the smart grid is “totally about behavior change.
• Members of the SmartGridCity Consortium include Xcel Energy, Accenture, Current Group, Schweitzer Engineering Laboratories, Ventyx, GridPoint, and OSI Soft. There are several other public and private collaborators including SmartSynch and Landis+Gyr.

2. Acronyms/Definitions

• Analysis Portal - Gives secure access to usage information, billing history and means for interactively helping customers discover how to best use energy taking into consideration both price and environmental impacts.
• Control Portal - Gives customers the opportunity to set energy use preferences for major appliances and a limited number of household outlets.
• Information Portal - Educates customers about how their energy is produced, and offer tips for reducing costs and lowering their carbon footprint.
• Smart Substations - Infrastructure upgrades will create more sophisticated intelligence in the substation, which will allow the utility to better monitor and adapt to customer needs, while making real-time decisions based on current grid conditions.
• Smart Feeders - The feeder distribution system will consist of communication-enabled smart reclosers and switches as well as smart feeder assets to provide power system information and perform automated functions. These assets will allow Xcel Energy to monitor power flow, outages, and overall asset device health.
• Smart Distribution System - Power analyzers will be installed at each distribution transformer and incorporated into smart meters to provide real-time data on power consumption, outages, restorations, and fault locations.
  
  

3. Business Case

1. Phase I: March 2008 - August 2008
• Included full-system automation, monitoring and smart meters for the first group of SmartGridCity customers. Involves upgrades to two substations, five feeders and nearly 15,000 meters (representing both residential, commercial and light industrial customers) in Boulder.
• Web portal provided consumers with insight into their energy use and information for better home energy management.
• Some customers could choose to have in-home automation tools, allowing increased control over home energy use and costs.
2. Phase II: September 2008 - December 2009 - Xcel Energy, along with its partners, will have a field crew of up to 115 people dedicated to the deployment and build out of SmartGridCity. By the end of Phase II deployment, Xcel Energy expects the approximate size of the SmartGridCity™ customer base to grow to 50,000 residential, business and light industrial customers. Eligible customers can opt to participate at any level they choose.
• Complete the installation of a distribution and communication network for remaining areas within Boulder (an additional two substations, 20 feeders and smart meters for an additional 35,000 premises). The city would be outfitted with infrastructure to support renewable energy sources such as wind and solar.
• Expanded in-home automation installations. Xcel plans to install in-home control devices in the smart-grid city to automate home energy use in 1,200 homes. As of November 2010, it was on standby until security issues can be worked out. But, as Greentechgrid put it, at the cost of $2,173 per location, it’s hard to imagine that any results from the pilot will sway public opinion, unless home automation includes a free 3D television.
• Enable Web portal access to all SmartGridCity customers.
• Begin initial integration of plug-in hybrid electric vehicles, solar and wind co-generation sources onto the grid in Boulder. The city will feature plug-in hybrid-electric vehicles that charge and discharge to the grid.
3. Dynamic Pricing Pilot
• In fall 2009, Xcel Energy filed for an electricity pilot pricing program with the Colorado Public Utilities Commission (CPUC) to coincide with implementation of SmartGridCity™ in Boulder, Colo. The pilot will include no more than 2,000 customers and is designed to provide customers with better price signals so they can make informed decisions about their energy use. The program is expected to produce reductions in consumption during on-peak periods or to shift some consumption to off-peak periods. Residential customers in Boulder who have a smart meter can choose to participate in the pilot, which will run until Dec. 31, 2011.
• In February 2011, a flier sent to thousands of randomly selected Boulder residents by Xcel Energy appears to force the recipients to sign up for a pilot pricing program, causing outrage among some customers.  The SmartGridCity pilot pricing program charges participants, who must have smart meters, more than they are paying now during periods of peak electricity demand -- from 2 to 8 p.m. -- and slightly less than they are paying now during the rest of the day.
  
  Phase one of the pilot plan began in Fall 2010 with 1,249 volunteers. But phase two of the plan, scheduled to begin in 2011 seeks 5,000 randomly selected volunteers.
  
  In February thousands of Xcel customers in Boulder began receiving letters from the utility that say, in bold, "You have been selected as one of the participants for this mandatory program. Your response is required to select your top two choices by March 1st." The outside of the flier says, "Your response is required" inside a red box.    In fact, customers who do not respond to the mailing at all will continue to be charged the standard rate, according to paperwork filed by Xcel at the Public Utilities Commission in December. And customers who do respond can choose from four pricing options, one of which would make no change to the way they are now charged for electricity.
  
  But the fact that this information cannot be found anywhere on the flier -- which also invites customers to attend one of five informational meetings next week -- angered some recipients.
  
• Some Boulder residents, including City Councilman Matt Appelbaum, say the design of the pricing pilot is flawed and that Xcel hasn't given customers the tools they need to actually track their own energy use and, therefore, figure out how to shift use away from peak hours. Appelbaum said two of the most important tools that are now lacking are the ability for a customer to see his or her energy use in real time and the ability for a customer to program use -- potentially turning on some appliances in the middle of the night instead of during peak hours. Now, a customer with a smart meter can only view yesterday's energy use at 15-minute intervals.
  
• Xcel said in a filing with the CPUC that they expect residents who sign up for the time-of-use pricing categories in the pilot to save customers between $37 and $47 per year. But that might not be enough of an incentive.



Xcel's Smart House Concept

4. Regulatory Rate Case - In December 2009 the Colorado PUC approved an $11 million rate hike to cover additional costs (among other things) but told Xcel it now needed to go through the process of filing a ordered the utility to file a “Certificate of Public Convenience and Necessity” and it needed to prove why it needed to increase rates. The rate increase and the details of the request for CPCN, are what has been leaking out all these ugly details and media coverage of the mismanagement in this smart grid saga.
   
   In November 2010, the Colorado Public Utility Commission recommended to allow Xcel Energy to recoup nearly $45 million in costs across across 1.4 million ratepayers, not just Boulder. The total cost is estimated at $100 million plus. The decision by Administrative Law Judge G. Harris Adams found that the investment is “prudent” and that there is benefit for ratepayers “directly through the technology deployment and learning process occurring within the pilot.”
   
   The decision was favorable to the utility, as it approves a figure that is three times higher than Xcel’s original estimates on cost recovery, and which has already been opposed by Colorado’s Office of Consumer Counsel and two of the state's largest industrial electricity consumers.
   
   The CPUC rendered its verbal decision on cost recovery on Jan 5,  2011 and its written decision on Feb 8, 2011  overruling the Administrative Law Judge and whacked 38% from the $13 million a year the utility charges customers to pay for the SmartGridCity pilot project. That means Xcel can include about two-thirds of the $44.5 million total cost of the project in its rate base, according to a Denver Post news article. Xcel won't be able to get its hands on the rest, about $16.6 million, until it can demonstrate the project's benefits to consumers.
   
   When an Xcel executive told the CPUC in these hearings that the utility would never have begun the project if a cost cap was imposed,  Commissioner Tarpey retorted that the message he was hearing from Xcel was "yeah, we really want to do it, but not with our money."
   
   The CPUC had allowed Xcel to retroactively file a certificate of public need and convenience, or CPCN, for its high-end estimate of costs, so the utility has been recovering costs from ratepayers since January 2010.  In 2011, that charge on ratepayers' bills was reduced to reflect cost recovery of $27.9 million—the amount that Colorado's Office of Consumer Counsel (OCC) had pegged as reasonable.
   
   On Feb 28, 2011, Xcel filed a 19-page application for an RRR (rehearing, reargument and reconsideration of the CPUC's decision)  Xcel's logic was that the CPUC looked back over the project's evolution to justify withholding part of the requested cost recovery, while not looking forward to pending results on the project's various value propositions—including how SmartGridCity innovations might be applied elsewhere in Xcel's multi-state service territory.
   
   A month later, the CPUC simply said "no" to the RRR request.  "Public Service (aka Xcel) has the opportunity to be granted recovery of the remaining investment costs in a future adjudicated proceeding, if indeed Public Service shows it is warranted," the commissioners wrote.
   
   On Jun 27, 2011, the CPUC again rejected Xcel's latest effort to claw back more cost recovery on its SmartGridCity project.  The CPUC also decided that Colorado's regulated utilities should file periodic plans relating to smart grid generally and, specifically, that applications should be filed for smart meter proposals. And the CPUC wants details: the number of meters, quantified impacts on resulting energy usage, peak load, demand side management participation, cost/benefit analyses, a detailed consumer outreach/education plan with a completed customer segmentation study and an impact assessment on low-income or other vulnerable groups.
   
   Further, the CPUC found that one of smart meters' primary benefits is as a platform for dynamic pricing and that "system-wide smart meter implementation concurrently with system-wide changes in rate design is likely to elicit negative customer reactions" regardless of customer outreach and education. That conclusion was informed by the CPUC's discovery that "the residential customer class is far from homogeneous in terms of usage, attitudes, values and interest level" in their energy service needs.
   
   The commission goes on to suggest that any smart meter rollouts in Colorado be opt-in and target the most receptive residential customers first, which limits its system benefits but aids long-term acceptance; and that customer segmentation (using third-party help if necessary) should be applied to achieve this; that a default rate be offered in the near-term.  The idea is that Dynamic pricing can't be forced on customers, and spending a lot of money on interval meters makes no sense without some form of time-based pricing.  Now at least Colorado has a framework for evaluating smart grid projects and the regulated utilities under its oversight know their obligations.
   
5. Xcel has said that its actual data collection, commenced in Fall 2010 will be complete in 2011 and we await its report on the project's value propositions. Certainly Xcel will seek to demonstrate statewide ratepayer value, as $16.6 million rides on it.
6. On May 21, 2013 the Colorado Public Utilities Commission ruled that Xcel Energy will not be able to collect the $16.6 million balance it says it is owed for work performed on the SmartGridCity project in Boulder. The ruling is in line with an earlier decision by an administrative law judge that the utility should not be allowed to collect the remaining $16.6 million in costs it incurred in the project because it had not met established criteria demonstrating customer benefits, according to a story in the Boulder County Business Report.
   
   The PUC in early 2011 allowed Xcel to recover $27.9 million in program costs from customer rates, but withheld the remaining $16.6 million until the utility could demonstrate benefits to customers, and provide a comprehensive plan.
7. The SmartGridCity project began in 2008 with a lot of optimism, but along the way Xcel had to deal with unanticipated difficulties and issues that bumped the total project cost to $44.5 million, well above the initial numbers. There has been enough dissatisfaction among Boulder residents and officials with the project that the city council is expected to vote in April 2013 on splitting from Xcel and developing its own municipal utility.

4. Benefits Xcel Energy believes the results will be a greatly improved delivery system that optimizes the impact on the environment, ensures the most efficient delivery, and maximizes reliability. Xcel -Smart Grid Benefits White Paper

1. Peak Demand Reductions - Significant decreases in residential peak demand energy consumption achieved by providing real-time price and environmental signals in conjunction with advanced in-home technologies. Empowering customers with tools and energy management information will enhance Xcel Energy’s ability to manage costs by managing demand. Information about on-peak and off-peak usage with emphasis on energy cost and the reduction of emissions will encourage customers to use energy in a more price responsive, environmentally sustainable way, including the options of using distributed energy resources such as PHEVs, solar, wind turbine, vertical wind turbine, batteries, geothermal, biomass, fuel cells, micro turbine (10k RPM spinning device with harmonics) and stored energy systems.
2. Carbon Footprint Reduction - A result of lowered residential peak demand and energy consumption, improved distribution losses and increased conservation options. . A decrease in electricity usage by 2.5 percent could cut Xcel Energy’s CO2 emissions by over one million tons annually.
3. Capital Savings - Expected deferral of capital spend for distribution and transmission projects based on improved load estimates and reduction in peak load from enhanced demand management.
4. Operating Savings - Potential utility cost savings from remote and automated disconnects/ reconnects, elimination of unneeded field trips and reduced customer outage and high-bill calls through home automation.
5. Reduce Customer Minutes Out - By reducing customer minutes out through fault switching, automatic outage notifications proactive asset replacement, Xcel Energy expects to improve SAIDI by 10 percent. Transformer overloading outages were reduced by 25 percent in Boulder in 2009 due to the monitoring equipment installed as part of the project.
6. Improved Reliability - Phase I results released in early September 2009 showed customer complaints about voltage fluctuations had dropped to ero from about 60 a couple of years earlier and there weren't any unplanned transformer failures compared with six in 2007.
   
   Customers calling to complain about power quality dropped to just over 1 percent in 2009, down from more than 8 percent of total complaint calls in 2007.
   
   Preventing customer outages is a critical factor affecting customer satisfaction. A smart grid will proactively identify devices approaching imminent failure. It will also more quickly identify current outages, nested outages, and the locations that need to be attended to most quickly to remedy those outages. The use of advanced metering applications will eliminate costly "okay on arrival" situations by being able to determine if a customer is out. Providing crews with access to this information while they are in the field will vastly improve outage restoration performance by having faster, prioritized responses. Xcel Energy’s smart grid will use the following methods to reduce customer minutes out.
• System reconfiguration using intelligent automated switches coordinated with substation intelligence
• Remote identification of faults
• Remote, real-time identification of outage size and location
• Remote control and aggregation of demand response and distributed energy resources
• Remote outage and restoration detection
7. Customer Empowerment - Real-time pricing programs help manage demand by raising the retail price when our energy cost is high and lowering the retail price when our costs are low. However, these programs have previously been unpopular with customers because they have been complex and inconvenient. A system that automates customer energy consumption based on customer-selected preferences against both price and environmental signals would alleviate both the complexity and inconvenience. A system that enables customers to optimize energy consumption based on emissions reductions would encourage customers to leverage low emissions generation from renewable sources.
8. Reduced Billing and Customer Service Related Costs - Advanced metering applications will enable automated meter reads, assist with revenue assurance, and improve call center performance. Xcel Energy anticipates this could lead to:
• Reduced costs associated with improved meter reading efficiency – representing 50% in potential operational savings over manually and interval read meters.
• Reduced O&M impacts associated with call center –representing $1 million in annual operational savings
• Recovery of lost revenue and reduced costs associated with theft investigation – representing up to $10 to $20 million in annual savings and recovery
• Remote Disconnects/Reconnects – representing up to $5 to $10 million in annual savings from not sending a technician.
9. Reduced System Losses - A decrease in distribution losses by 20 percent could cut Xcel Energy’s CO2 emissions by 500,000 tons annually - Transmission and Distribution losses, caused by impedances in conductors and compounded by inefficient grid operation, are currently between 4 percent and 8 percent. By reducing these losses, utilities can lower power generation outputs and thus reduce emissions. A smart grid enables calculation and minimization of line losses by redistributing power flow and balancing current to maintain optimal balance between voltage, frequency, and reactive power. A decrease in distribution losses by 20 percent could cut Xcel Energy’s CO2 emissions by 500,000 tons annually. The smart grid will use the following methods to reduce system losses via:
• Remote operation of capacitor banks to reduce the current needed to provide reactive power
• Remote sensing of customer power factor at distribution transformer
• Distribution automation to provide load balancing
• Control and aggregation of distributed generation/distributed energy resources
10. Asset Optimization - Xcel Energy posits the operational savings resulting from reduced capital investment in distribution and substation system infrastructure—up to $1,200,000 in annual savings. - The smart grid will provide awareness of the health, reliability, and functional constraints of the system. Data collection and communication will create a system capable of making automated decisions that will preserve and optimize asset utilization by:
• Avoiding failures by proactively replacing cables, substation equipment and distribution transformers
• Dynamically rating transformers to help defer capital investments
• Extending generation asset life that avoids capital investments for generation capacity requirements.
  
  

5. Risks/Issues

• Approval Process
• Xcel didn’t file a Certificate of Public Convenience and Necessity (CPCN) before the project started in 2008 because they didn’t think they needed to for what they deemed a research project. In its pre-filed testimony, Public Service contended that SmartGridCity does not require a CPCN because it is an investment in the distribution system. Ms. Karen Hyde testified that “SmartGridCity is a distribution project and does not include any transmission or generating capacity. Under Rule 3207, construction or expansion of the distribution system is deemed to be in the ordinary course of business and does not require a CPCN.” In addition, Mr. Randy Huston testified that “to the extent the project ties to any particular portion of our system, it is distribution related…much of our SmartGridCity project consists of software, which is general plant, not generation or transmission plant.
• Without a CPCN there was no opportunity for the PUC or other interested parties to consider capping costs to protect ratepayers
• A traditional cost-benefit analysis wasn’t performed prior commencing the project
• Xcel asked the PUC in 2009 to OK a rate increase to recoup some of its project costs. That’s when the commission decided Xcel needed a CPCN to prove the project is prudent and in the public interest
• There was no process in place to address and redress all the commonplace issues that occur in such a project because the project is outside the normal regulatory process mainstream. Without a method to gracefully handle the issues, all the usual suspects (nay-sayers, utility "watchdogs," etc) have plenty to complain about.
  
  
• Poor Project Management - From understanding the requirements and due diligence to building an accurate business case with reliable cost/benefit analyses, the expectation setting was diametrically opposed to the actual delivery. Accurate expectation setting, quality project management and reliable cost/benefit/schedule estimations could have avoided this pain.
  
  
• Unclear Project Goals - The controllable loads weren't in place for it to be a test of demand response. A distribution automation test wouldn't require smart meters in 43% of homes. Was it just an automated meter exercise? Utilities have been quietly doing that for years. Were most of the cost overruns related to laying the fiber cable? Did they have ulterior motives for not using existing communication infrastructure? Was it a PR exercise? Was it an attempt to head off the political controversy that has exploded anyway over whether Boulder should renew Xcel's franchise? In addition to other possible goals it undoubtedly was a research project whose costs got out of hand. This highlights the importance of having clearly stated goals from the outset.
  
  
• Poor Municipal Relations - The city of Boulder has been unhappy with Exel for years and has been contemplating municipalizing their system during much of that time. The city of Boulder had no idea SmartGridCity was coming until the day before the announcement! There was no prior planning or collaboration. Maybe SmartGridCity was a bone that Exel was throwing at Boulder in an effort to dissuade further discussions about parting ways with them.  In Fall 2010, Boulder voted to not renew Xcel's franchise to serve the city and it is exploring alternatives such as becoming a municipal utility
  
  
• Expensive Fiber Optics - According to Xcel, it was the cost of building the fiber optic network that serves as the backbone of SmartGridCity’s communications, a task that was given to consortium partner Current Group, that was the main culprits responsible for the ballooning cost. Not only did the utility need far more underground fiber than it originally anticipated, it also faced other unexpected costs, such as using diamond-tipped drill bits to tear through granite and bringing in cranes and dump trucks to remove boulders, the utility reported in a May 2009 document. The lesson learned is don't blast through rock to run fibre optics. Let other people do that. Use existing fibre, wireless and your own power lines (broadband over power line outside, ITU G.hn / IEEE P1901 inside) to get as many bits back and forth on the last mile as you can, wholesale. Don't reserve megabits of data connection for some vague future use, lease it off immediately for a share of the revenue from ISPs, voice and TV providers who can't penetrate the last mile without your help. Set up closets for them everywhere so the average home sees many times more data, voice and TV providers than they have ever seen before - something you get credit for.
  
  
• Investment Risk - One of the questions with such a large, long-term project is: where will the money come from? SmartGridCity has an at-risk funding model. Without this model, the culture of the industry is that money can’t be spent without the confidence that that money is going to produce value, and hence focus is limited to things that will work for sure. Because only exploring things that are certain to work are explored, the opportunity to give a different view of the model is bypassed.
  
  The investment did not go through the normal regulated process which allowed the study the margin to fail. Xcel has taken the risk, along with its partners, to fund Boulder in the validation of value that will come back to the customer, ultimately, in the system.
  
  Because the cost of Boulder was more than Xcel Energy was willing to put at risk, the company solicited partners for at-kind investment. The result of this is that the majority of the project is funded by Xcel Energy’s partners: Current Group, Accenture, GridPoint, Ventyx, OSIsoft and Schweitzer Engineering Laboratories. The expectation is that pieces of the program will demonstrate themselves and be eligible for that recovery.
  
  
• Cost Overruns - Rumor was that the initial budget for SmartGridCity was $100M but it ended up costing them $200M. According to a February 6 story in the Boulder Daily Camera newspaper, SmartGridCity has seen capital costs balloon from an initially projected $15.3 million to a new estimate of $42.1 million, and that doesn’t include operations and maintenance. "The company had to install far more underground fiber than initially projected, substantially increasing the cost ..." Xcel officials wrote in a document filed with the utilities commission last May. "We also ran into unexpected construction conditions such as having to drill through granite with diamond-tipped drill bits and remove large boulders with cranes and dump trucks ... ."
  
  The whole affair brings into question whether smart grid services alone can justify the cost of building out a fiber optic network. While many utilities have fiber optic networks installed, they’re usually limited to major transmission lines and end at big substations, rarely venturing out into neighborhood distribution grids.
  
  
• Potential for Partner Conflict - With so many companies involved, there could be a possibility for conflict. However, no one company has a full solution – so the need to bring this various expertise together is key.
  
  
• Data Privacy (See my Smart Meter Data Management and Security Blog Article)
  
  
• Interoperability - Lack of standards for smart meter technology (See my Standards for Standards Blog Article)
  
  

6. Participating Companies

1. Xcel Energy, Minneapolis, MN (NYSE: XEL) - A major U.S. electricity and natural gas company with regulated operations in eight Western and Midwestern states. Xcel Energy provides a comprehensive portfolio of energy-related products and services to 3.3 million electricity customers and 1.8 million natural gas customers through its regulated operating companies.
2. Accenture , Much of the work will be done in Bangalore, India -(NYSE:ACN) – A global management consulting, technology services and outsourcing company; it collaborates with clients to help them become high-performance businesses. Accenture’s role with SmartGridCity is to project manage the integration and management of data flow, including automating processes, transmission and distribution of electricity.
• To develop the smart grid, Accenture will integrate diagnostic software, intelligent distribution assets and outage management systems into Xcel Energy’s existing IT infrastructure and will be building a lab-like environment for testing power outages, reliability and potential impacts to the smart grid.
• Accenture is helping define additional requirements for SmartGridCity and is specifically responsible for integrating data flows and grid system analytics that will enhance Xcel Energy’s ability to deliver electricity and serve its customers.
• The patent-pending Accenture Intelligent Network Data Enterprise solution set comprises a number of assets and methods, including comprehensive reference architecture, open standards-based data transport and storage architecture assets, end user transactional analytics, and a process and blueprint for smart grid development.
  
3. Current Group, Germantown, MD – Offers broadband internet over powerlines. John Malone's Liberty Media is a large investor in Current. Current also provides sensing, monitoring and other communications technologies over power lines. SmartGridCity will be utilizing the fully integrated CURRENT OpenGrid™ Smart Grid solution that combines advanced sensing technology, two-way high-speed communications, 24/7 monitoring and enterprise analysis software and related services to provide location-specific, real-time data about the status of the electric grid. The solution also provides consumers information and control over their energy usage and enables the widespread deployment of renewable energy sources. Current Group, has provided the infrastructure and applications to enable Xcel Energy’s vision, including:
• A robust, two-way, low latency communications network that incorporates fiber optics, 3G cellular wireless, MV/LV broadband over power lines and DSL to provide connectivity throughout the distribution system to approximately 45,000 premises in Boulder, Colorado
• Intelligent voltage and current sensors located at distribution transformers that provide the edge analytics for the distribution system
• OpenGrid™, CURRENT’s standards-based open software platform, manages the communications network and provides standard interfaces to utility devices and utility back office systems with a robust relational and spatial database to enable high valued analytical and control applications
• Automated Metering
• Integration with a number of Demand Response technologies
• Analytical and control applications including:
• Incipient Transformer Failure Detection
• Transient Voltage Disturbance Analysis
• Voltage Imbalance Analysis
• Transformer Overload Detection
• Remote URD Fault Indication
• Outage & Restoration Detection
• Integrated Volt/VAR Control
• Instant Meter Reading
• Daily Meter Collection
4. Schweitzer Engineering Laboratories, Pullman, WA – SEL’s work in SmartGridCity will focus on the “smart substation” effort with sensing, control, communications, analytics, and automation solutions. SEL Invented the world’s first digital distance relay 25 years ago, improving how the power system provides electric power. SEL also provides solutions for Xcel Energy's Merriam Park "smart substation" project in Minneapolis, Minn. Founded in 1984, SEL introduced the world's first digital protective relay, revolutionizing the electric power industry by fault location and other features for a fraction of the cost of earlier systems.
5. Ventyx, Atlanta, GA - The world’s largest software provider to the utility industry, with more than 900 customers around the world. with approximately 1,200 employees in more than 20 locations worldwide. Ventyx will support SmartGridCity by providing:
• Work management solutions for deploying smart grid technologies
  
• MRO management for work and service requests triggered by the smart grid; and
  
• Planning and analytics for price and load forecasts and decision support for connecting customer actions to trading and investment decisions in real time.
  
• Energy analytics
6. GridPoint, Arlington VA - A pioneer of an innovative smart grid platform that aligns the interests of electric utilities, consumers and the environment through an intelligent network of distributed energy resources that controls load, stores energy and produces power. GridPoint, Inc. received $15 million of VC funding in 2008 for their management of distributed storage, renewable generation, and load, bringing the firm’s total funding to over $100 million.
• SmartGridCity will use Gridpoint’s SmartGrid Platform™ to apply information technology to the electric grid to provide an intelligent network of distributed energy resources that controls load, stores energy and produces power. The platform enables Xcel Energy to evaluate technology and system capabilities such as advanced demand management, supply management, solar photovoltaic integration, PHEV smart charging, online energy management, instant backup power, performance monitoring and customer support.
• The platform applies information technology to the electric grid to enable distributed energy resources to perform the same as central-station generation. During peak periods, utilities efficiently balance supply and demand by discharging stored power from distributed generation assets or reducing customers’ non-essential loads through demand response programs.
• For consumers, the platform provides protection from power outages, increases energy efficiency through online energy management and integrates renewable energy, paving the way for the commercial success of solar and wind energy sources.
7. OSI Soft, San Leandro, CA - A privately-held company founded in 1980. Their PI System software provides the infrastructure for collection and management of time series data required to monitor and implement the SmartGridCity concept. A global base of more than 14,000 installations across energy, utilities, manufacturing, life sciences, data centers and process industries relies upon the OSIsoft PI System for similar data-collection and management functions to manage assets, mitigate risks, improve processes, drive innovation, make business decisions in real time, and identify competitive business and market opportunities.
8. SmartSynch, Jackson, MS - A global leader in public wireless smart metering technology. Will provide smart metering, energy management, demand response and carbon monitoring solutions to commercial and industrial (C&I) customers for the SmartGridCity initiative. The SmartSynch solution will be deployed on the University of Colorado campus in Boulder, and on municipal buildings and select commercial and industrial buildings throughout the city. The C&I solutions, provided by SmartSynch via the AT&T Wireless network, will enable Xcel Energy to partner with its commercial and industrial customers in new ways by:
• Mapping their energy usage trends to optimize consumption
• Providing demand response programs offering incentives for business owners who curtail their facility’s energy use during times of peak demand
• Helping them capture tax incentives by reducing their carbon footprint
• Supporting large-scale intermittent renewable generation initiatives (e.g., solar panels)
• Facilitating real-time notifications of power outages to Xcel Energy dispatch teams to ensure on-site power quality
9. Landis+Gyr - Zug, Switzerland –The largest global player in electricity metering with one of the broadest portfolios of products and services is privately held. It has a preeminent position in advanced or “smart metering systems” Over 5,000 employees, 600 full-time professionals dedicated to R&D, and operations in 30 countries across five continents.
   
   Supplied ~15,000 smart meters, which will be installed by August 2008. In June, crews will begin installing them, at approximately 2,500 meters each week. The new smart meters provide detailed usage history and automated meter reading. The meter installation will be at no charge to the customer.
   
   

7. Links

1. IBM’s Smarter Cities Challenge Boulder Report - June 2011 - "Current SGC infrastructure provides significant value to Boulder. The deployment of a high-bandwidth communication medium, thousands of sensors, smart transformers, and smarter meters has transformed Boulder’s electrical grid. SGC allows for effective 2-way communications, sensing and monitoring performance, remote control and automation and 24-hour delay reporting. To consume and utilize the exponential increase in data that SGC produces, Xcel Energy has also had to transform its grid operations, back office infrastructure and applications.
   
   These enhancements to the electrical grid infrastructure provide significant value, improving transmission and distribution reliability and stability. These advances can also reduce utility operating costs.
   
   However, the SGC project has yet to provide direct, visible customer value. When the project was initiated, SGC was advertised as providing customers with significant benefits including in-home real-time information access. This is now being piloted on a limited basis. This mismatch in expectations has been a source of friction between the utility, the City and its citizens."
   
   
2. Green Tech Media - Xcel Sought Millions from Start-Ups For SmartGridCity - Pay $5 million and be in the pilot, said the utility. No thanks, said prospective partners. January, 2010
3. EnergyBiz Magazine - Beyond Boulder - Implications of Grid Experiment - Gargi Chakrabargy - November/December 2009
   
4. Smart Grid City Web Site
5. City of Boulder – Customer Products and Solutions (pdf) – Levels 1 through 6
6. Excel - Smart Grid White Paper (pdf)
7. Excel - SmartGridCity News
8. Next Generation Power & Energy Magazine– SmartGridCity

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.

Navigate this Report
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

• List of HVDC Projects
• List of high voltage underground and submarine cables
  
• ABB - HVDC and HVDC Light are highly efficient alternatives for transmitting bulk power and for special purpose applications
• High Voltage Direct Current (HVDC)Transmission Systems
  Technology Review Paper
  

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

3. Business Case

4. Benefits

5. Risks/Issues

6. Case Studies

7. Companies/Organizations

8. Links

1.Background

• 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. 
   
   
   
4. 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
   
   
5. 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.
   
   
6. 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.
   
   
7. 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.
   
   
8. 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)