Thursday, August 21, 2014


Transmission Domain - The National Institute of Standards and Technology released a common semantic model for the Smart Grid in June 2009 - NIST worked with the appropriate standards development organizations to form a common representation of information models for the smart grid

H. Transmission Planning
Renewable energy resources such as wind in the high plains and concentrated solar in the dessert southwest require multi-billion-dollar investments in extra-high voltage transmission extending across state lines.

G. Flexible Alternating Current Transmission System (FACTS)
A system composed of static equipment used for the AC transmission of electrical energy. It enhances controllability and increase power transfer capability of the network and is generally a power electronics-based device.

F. High Voltage DC Transmission (HVDC)
For long-distance distribution, HVDC systems are less expensive and suffer lower electrical losses than the traditional AC lines.

E. Phase Synchronizer
A utility frequency technology that has the potential to change the economics of power delivery by allowing increased power flow over existing lines up to a line's dynamic limit instead of to its worst case limit.

D. Wide Area Situational Awareness
MONDAY, MARCH 26, 2012
The Great Northeast Blackout could have been avoided by better communication across system operators

C. Transmissions Operations Overview
thursday, july 7, 2011
We are using World War II era analog technology to power a network and devices that are increasingly digitized.

B. Improved Circuit Ratings
monday, july 11, 2011
The thermal expansion in transmission lines is still limited by obsolete, slow electro-mechanical controls that seriously constrain the amount of electricity that each line can carry.

A. Super Grids
Imagine a virtually unlimited supply of electrical power from solar-energy systems and power lines that could transmit this electricity from the deserts of the southwest to the Eastern Seaboard at nearly 100 percent

Transmission Planning

Supplying renewable energy from wind in the High Plains and solar in the Dessert Southwest will require multi-billion-dollar investments in extra-high voltage transmission extending across state lines.

2. Update August 2014 - FERC 1000 authority to require regional transmission planning upheld by Appeals Court

California Wind Resource Map - New transmission is needed to bring wind energy from the deserts and mountains to the population centers

Navigate this Report
Back to Transmission Index
1. Background
2. Update
3. Acronyms/Definitions
4. Business Case
5. Benefits
6. Risks/Issues
7. Success Criteria
8. Next Steps
9. Projects
10. Links

  • Currently, almost 300,000 MW of proposed wind projects, more than 10 times the current installed wind capacity in the U.S., are waiting in line to connect to the grid but are unable to proceed because of adequate grid capacity. ( Renewable resources have the potential to generate a far higher percentage of the electricity in the US than they do today. The lack of adequate electric transmission capacity is a primary obstacle to achieving this goal because many of the best potential renewable energy resources are located in rural areas far from population centers.

  • The full extent of the current shale gas revolution would not be possible without the rapid expansion of natural gas pipelines in the prior 15 years. Over 11,000 miles of interstate gas pipeline were built between 2000 and 2007, while only 668 miles of high voltage transmission was been built in the same time frame.

  • Because of the long distances involved in bringing renewable wind and solar power to urban areas, transmission lines will often not benefit the local states they run through. Transmission Planning has historically been accomplished at the state level. Now there is a growing call to balance overall national needs and get FERC more involved in the planning process.

  • Renewable Portfolio Standards (RPS) in California and other require substantial increases in the generation of electricity from renewable resources. Extensive improvements, however, are needed to California's electric transmission infrastructure to get the electricity generated by new renewable power facilities to consumers. California's Renewables Portfolio Standard (RPS) calls for 20% of electricity to come from renewables in 2010 and 33% by 2020. The 2010 target has not yet been met. According to a June 2009 study by the California PUC, four major new transmission lines were needed at a cost of $4 billion. To meet a 33% RPS by 2020 target, 11 new transmission lines will be needed at a projected cost of $16 billion. Three of these lines are currently under way, but CPUC predicts that even if implementation on all the other lines were to start today, it would take another 14 years to achieve the 33 percent renewable goal. The CPUC is continuing to work on this issue including this May 17, 2011 workshop on Transmission Needed to Meet State Renewable Policy Mandates and Goals

  • Transmission constraints are impeding RPS implementation in large portions of New England, transmission congestion is inhibiting renewable energy use in New York, and import constraints from the Midwest ISO (MISO) are restricting transfers of renewable energy into the PJM Interconnection (PJM).

  • The deregulation of America’s utilities in the 1990s encouraged companies to transfer power over long distances. The regulatory regime shifted the operations of the electric utility industry, creating larger and more frequent bulk power transfers across a transmission system designed largely for local intrastate service. At the same time, regulatory uncertainty and increased competition led to reduced investment in new transmission lines. While the United States has hundreds of thousands miles of high-voltage transmission lines, only 668 additional miles of interstate transmission were built in the first decade of the 21st Century. As a result, some parts of the system have become increasingly congested.

  • The transmission siting process can be a difficult debate. A mixture of local, state and federal government agencies hold jurisdiction over who can build what, where they can build it, when they can build it and who pays for it. Cost allocation reform is one of the most difficult issues facing transmission service providers and regional market operators. A Dec 2010 FERC decision stating that all parties who benefit from new transmission in the Midwest must share in the cost of building will facilitate construction of new transmission lines. The decision is the culmination of a push over much of the last decade by renewables advocates in the Midwest to get utilities and transmission system planners and operators to think more about wind power but is expected to apply where new wires are built to accommodate other renewable energy resources.

  • There is an important distinction between building new wires and incorporating digital intelligence and communication capabilities into a wires network. They are potentially related, but different, and should be treated as such. The application of digital communication technology in the wires network falls disproportionately in the distribution network , not in the high-voltage transmission network. Transmission Planning is also different from some of the interesting approaches to transmission line control and sensing, including ideas for self-healing autonomous networks.

  • Load is growing at almost double the rate of growth in transmission capacity and most regions have very limited plans to expand generation and transmission facilities. Traditional planning and operations practices, the current delivery infrastructure is not capable of bringing renewable-energy generation online at a capacity that is consistent with the amount of construction needed.

2. Update
  • FERC 1000 authority to require regional transmission planning has been upheld by Appeals Court. On Friday August 15, 2014, a ruling from the U.S. Court of Appeals for the D.C. Circuit affirming a 2011 FERC order is poised to usher in major changes in the way utilities and regulators consider transmission and to open pathways for more renewables to enter the grid.
  • (from ThinkProgress) FERC Order 1000 makes a number of changes to how electricity transmission will be considered in the future. It requires grid investments that affect multiple states and utility jurisdictions to be coordinated — rather than the former system which allowed individual state regulators and utilities to opt in or out of regional efforts. It provides guidance on how to pay for expensive transmission projects and makes the process more flexible to help facilitate growth, especially for renewable efforts. It also eliminates utilities’ first right of refusal, which allowed incumbent utilities to decide first it they wanted to build transmission projects. This will help level the playing field for independent transmission projects.
  • Perhaps most significantly, Order 1000 demands transmission plans account for state-level policies on reducing greenhouse gas emissions and increasing renewable energy production. Currently around 20 states have Renewable Energy Portfolios operating to achieve these goals.
  • Overall the Order is ambitious and aims to accomplish two primary goals: facilitating the coordinated construction of the many new and updated electric transmission lines needed as fossil fuel and renewable energy projects come online in disparate parts of the country, and making it easier for large-scale renewable energy projects to connect to the grid.
  • The EPA’s recent announcement of proposed carbon dioxide regulations for existing power plants, which will be carried out by state-level directives, will likely dovetail well with these new transmission guidelines.

3. Acronyms/Definitions
  1. ACELA - American Clean Energy Leadership Act of 2009 - While this legislation did not pass in part due to the controversy around Cap and Trade, the bills provisions to link the Country with a Reliable Transmission Grid are still relevant. The bill would have
    1. Established the policy that the transmission infrastructure should be guided by the following goals:
      • Support for development of renewable generation
      • Opportunities for reduced emissions
      • Cost savings resulting from reduced congestion, enhanced opportunities for trades, reduced line losses, generation sharing
      • Enhanced fuel diversity
      • Reliability benefits
      • Diversification of risk
      • Enhancement of competition and mitigation of market power
      • Ability to collocate facilities on existing rights-of-way
      • Competing land use priorities
      • The needs of load-serving entities; and
      • The contribution of demand response, energy efficiency and distributed generation.

    2. Required FERC to coordinate development of an interconnection-wide plan that achieves the policy goals, from plans developed by current planning entities; FERC must promulgate a rule to embody the policy goals and develop a schedule to implement
      those policies within one year of enactment.
    3. Transmission planning entities to develop regional plans and submit them to FERC within 24 months. The Commission will encourage joint submissions and submission of interconnection-wide plans. FERC may require modification of submitted plans to ensure conformance to planning principles and to reconcile inconsistencies.
    4. FERC to periodically evaluate whether projects in the interconnection-wide plan are being developed, and if not take actions, in accordance with other provisions of law, to address identified obstacles.
    5. Make recommendations to Congress for further actions or authority needed to ensure development of timely projects.
    6. Update the plan every three years.
    7. Allow States one year from time of filing of a proposal to site a high priority national transmission project.
    8. Give FERC jurisdiction over siting when states have either been unable to site the facility or have denied the application. Jurisdiction is over facilities 345 kilovolts and above that are included in the transmission plan. FERC must establish, by rule, appropriate methodologies for allocation of costs of high priority national transmission projects.
    9. Give the Department of the Interior lead agency status for development of records of decision on public lands.

  2. Avoidance Areas - Areas within Candidate Study Areas and/or Renewable Energy Zones where development of renewable energy resources should not occur because of purpose, policy, or other restrictions related to environmental, land use or other issues.

  3. Busbar Cost - The per megawatt-hour revenue that a project would have to earn in order to break even on all development and operating costs, other than network transmission. Busbar cost includes any collector lines bringing power from dispersed generators to a central interconnection point on the transmission system. The busbar is the point at which the aggregate output of multiple units is metered, and is the point at which the units become subject to power-control area dispatch instructions.

  4. CSA - Candidate Study Area - An initial modification of National Renewable Energy Lab base resource maps including any criteria identified by the work groups for Zone Identification and Technical Analysis and Environment and Lands. The Candidate Study Areas incorporate filters to identify a minimum threshold of developable resources, as well as state/province specific criteria. Identifying CSAs is an interim step the WREZ work groups will take in the process of developing proposed Renewable Energy Zones.

  5. Collector Line/System - A single or group of transmission lines that links one generator or a group of generators to the bulk power grid. Small generators will likely be dispersed throughout a REZ. The collector feeder lines from the generators will all converge at the centroid that connects to the bulk transmission grid.

  6. CTPG - The California Transmission Planning Group - An industry lead forum for conducting joint transmission planning and coordination in transmission activities to meet the needs of California consistent with FERC Order 890. CTPG is developing a California state-wide transmission plan to meet the state's 33% by 2020 renewable portfolio standard (RPS) goal and is using the Renewable Energy Transmission Initiative (RETI) conceptual plan as a starting point. CTPG issued its Draft Final 2010 California Transmission Planning Group Statewide Transmission Plan in February 2011.

  7. DRECP - Desert Renewable Energy Conservation Plan - Ordered by California Governor Executive Order in 2008 for the Mojave and Colorado deserts. When complete it will provide binding, long-term endangered species permit assurances and facilitate renewable energy project review and approval processes. To oversee the implementation of the DRECP, a Renewable Energy Action Team (REAT) was formed consisting of the California Natural Resources Agency, California Energy Commission, California Department of Fish and Game, Bureau of Land Management, and the U.S. Fish and Wildlife Service. Memoranda of Understanding (MOUs) were signed by the participating agencies. Others joining the team include the California Public Utilities Commission, California Independent System Operator, National Parks Service, and the Department of Defense.

  8. Exclusion Areas - Areas within Candidate Study Areas and/or Renewable Energy Zones where development is already precluded by statute or regulation (federal, provincial, state or local).

  9. Federal Lands Managers - Transmission facilities sometimes pass through federally owned lands; if they do, federal agencies, such as the Department of Interior or the Department of Defense, become involved in the siting process. These federal agencies play a significant role in the transmission siting process because they control such massive swathes of land in the country, particularly in the western United States. Yet, their main mission has little to do with transmission lines. A state siting authority cannot preempt a federal land manager.

  10. FERC – Federal Energy Regulatory Commission - Regulates interstate electricity transmission. Section 216 of the Federal Power Act (FPA), which was added in 2005, gives FERC jurisdiction in certain circumstances to issue permits for the construction or modification of electric transmission facilities in areas designated as national interest corridors by the Secretary of Energy.

  11. FERC Order 890 - Issued in 2007 among other things requires public utility transmission providers to participate in open transmission planning processes at the local and regional level. Each transmission provider must file a new Attachment K as part of its open access transmission tariff that describes its transmission planning process and how its process meets the following nine transmission planning principles: 1) Coordination 2) Openness 3) Transparency 4) Information Exchange 5) Comparability 6) Dispute Resolution 7) Regional Participation 8) Congestion Studies 9) Cost allocation

  12. FERC Order 1000 - A Final Rule issued in July 2011 that reforms the Commission’s electric transmission planning and cost allocation requirements for public utility transmission providers. The rule builds on the reforms of Order No. 890 and corrects remaining deficiencies with respect to transmission planning processes and cost allocation methods. The bottom line is it will force larger-scale plans to be produced everywhere.

    Simply put, FERC is proposing to include "public policy" into the list of criteria regulators can consider when allocating "just and reasonable" costs associated with new transmission. The rule also encourages a more regional approach. Who benefits has been the guiding standard for decades. A group of Senators opposed to the NOPR have submitted legislation that would essentially head off the new rules at the pass.

  13. Load Center - Major cities or metropolitan areas with large concentrated populations. Load centers consume large amounts of electricity.

  14. LSE - Load-Serving Entity - The broad term to describe entities that delivers electricity to end-users and wholesale customers, typically utility companies.

  15. MVP - Multi Value Project - A Dec 2010 FERC decision defines MVPs as wires having a regional impact and wide-ranging public benefit.

  16. National Electric Transmission Congestion Study - As required by EPACT05, DOE issued the first Study in August 2006. Additional studies are required every three years. The study identified two areas of critical congestion: Southern California and the eastern coastal area from metropolitan New York to Northern Virginia. This congestion study included detailed information on the transmission congestion in the western United States but did not provide comparable detail on congestion in the eastern United States. In determining whether to designate national interest electric transmission corridors, DOE is required to identify transmission congestion that adversely affects consumers. However, EPACT05 does not define “congestion that adversely affects consumers,” nor does it require empirical analysis of the specific adverse effects of transmission congestion.

  17. Source: U.S. Department of Energy, National Electric Transmission Congestion Study (2006), p. 33.
  18. National Interest Electric Transmission Corridor - As a result of EPACT05, DOE designated two corridors on October 2, 2007: The Mid-Atlantic Area National Interest Electric Transmission Corridor and the Southwest Area National Interest Electric Transmission Corridor based on the 2006 congestion study. This designation allows FERC, under certain circumstances to authorize “the construction or modification of electric transmission facilities.” A permit holder would still need to obtain rights-of-way from property owners. If the permit holder is not able to successfully negotiate with each affected property owner, then FERC would entitle a permit holder to acquire the rights-of-way by exercising the right of eminent domain.

    A National Corridor designation itself does not preempt State authority or any State actions, including action to approve or order the implementation of non-transmission solutions to congestion and constraint problems..

  19. NEPA - National Environmental Policy Act

  20. NREZ – National Renewable Energy Zones - Proscribed in pending S.539, each NREZ would have the potential to generate in excess of 1 gigawatt of electricity from renewable energy and have an insufficient level of electric transmission capacity to achieve this potential.

  21. QRA - Qualified Resource Area - Those lands with the greatest energy density within a contiguous area for each respective state. A QRA excludes any lands with statutory or regulatory development limitations and limitations related to topography, ground cover, or urban settlement.

  22. RETI - Renewable Energy Transmission Initiative - An initiative lead by the California Energy Commission to help identify the transmission projects needed to accommodate these renewable energy goals, support future energy policy, and facilitate transmission corridor designation and transmission and generation siting and permitting. Phases 1 and 2 of the RETI project resulted in the identification and refinement of Competitive Renewable Energy Zones (CREZs) that hold the greatest potential for cost-effective and environmentally responsible renewable development. Due to time constraints, several modifications to the RETI analysis were not included in the final Phase 2A report. The final Phase 2B Report, issued in May 2010, documents key changes made in the economic model, technology assumptions, competitive renewable energy zones, and out of-state (OOS) resources. Click here for the RETI Reports page.

  23. REZ - Renewable Energy Zone - Areas with high concentrations of developable renewable energy resources that can meet regional energy demand. Non-REZ resources serve sub-regional or in-state demand. They primarily serve load in the same locality, state or utility service area. They do not need to be concentrated in one place in order to be developed, as development is unambiguously within the regulatory purview of the state where the resource is located. Finally, the ability of any state to develop them is largely unaffected by policies in neighboring states.

  24. Supply Curve - A representation of the amount of renewable energy capacity that is economically developable from an area, and the cost at which increments of the total can be developed. The curve depicts projects and potential projects in ascending order according to their busbar costs. A Renewable Energy Zone supply curve includes and identifies all economically developable renewable energy technology categories contained in the REZ.

  25. TAC - Transmission Access Charge - Within RTO/ISO markets, most of which have multi-state footprints. The developer transmission owner (IOU or independent Transco) can choose whether or not to recover project costs through the ISO’s TAC. If the owner elects TAC recovery, then project costs are allocated among all load serving entities who are ISO market participants in proportion to the amount of load they serve.The financial transmission rights created by the specific project must be released and made available to all market participants through FERC-approved allocation and/or auction processes. If the owner elects not to recover project costs through TAC (“merchant transmission”), then the owner can obtain a long-term allocation of transmission rights from the ISO that reflects the incremental value of the capacity added by the project to the RTO/ISO controlled grid. This hybrid RTO/ISO cost recovery mechanism seems to be working in practice.

  26. Transmission Segment - A transmission segment defines a discrete distance from two points along a transmission path. Transmission segments were identified in the WREZ project to calculate the distances from Renewable Energy Zones to load centers.

  27. WECC - Western Electricity Coordinating Council - An organization that promotes and regulates electric reliability across the Western Interconnection. WECC also conducts transmission planning and supports Western power markets. In 2005, peak summer demand for electricity in the Western Electricity Coordinating Council area was 149,147 MW.

  28. Western Interconnection - A synchronized electric grid that spans 1.8 million square miles from the Canadian provinces of British Columbia and Alberta, to the northern part of Baja California, Mexico. In addition to the Western Interconnection, there are the Eastern Interconnection and the Electrical Reliability Council of Texas (ERCOT) in the United States.

  29. WGWC - Western Governors’ Wildlife Council – Established by The Western Governors’ Association to coordinate and oversee implementation of the WGA Wildlife Corridors report endorsed by the Governors in June 2008. Each WGA member Governor appoints a representative to the WGWC. The mission of the WGWC is to identify key wildlife corridors and crucial habitats in the West and coordinate implementation of needed policy options and tools to conserve those landscapes.

  30. WREZ - Western Renewable Energy Zones – An initiative launched by The Western Governors' Association and U.S. Department of Energy in May 2008. The WREZ seeks to identify those areas in the West with vast renewable resources to expedite the development and delivery of renewable energy to where it is needed. Renewable energy resources are being analyzed within 11 states, two Canadian provinces, and areas in Mexico that are part of the Western Interconnection.

4. Business Case
  • A truly national clean-energy smart grid must consist of two distinct components: an interstate sustainable transmission grid that will transport clean utility-scale renewable energy long distances to market, and a digital “smart distribution grid” to deliver this electricity efficiently to local consumers. The absence of a national grid that seamlessly integrates these two components is one of the biggest impediments to large-scale deployment of low-carbon electricity.

  • Federal and State Governments need to implement policies that enhance the quantity of electric transmission capacity available to take full advantage of the renewable energy resources available to generate electricity, and to more fully integrate renewable energy into the energy policies of the United States.

  • The question of transmission planning predominantly is still on the economic value of the construction of additional transmission infrastructure. There are two methodologies to fund this investment:
    1. Socialization of the costs of transmission requires the utility, and by extension its ratepayers, pay for all the new lines and upgrades to the transmission system.
    2. Participant Funding Process requires the developer to pay for all the upgrades in exchange for valuable transmission rights or credits for future transmission service
  • Failure to answer the question of who pays for what investment could stop new investment in transmission in its tracks. Ultimately, electricity customers pay for all the investments in transmission in some way.

  • The Federal Government is taking a more active role in transmission planning. Order No. 890 of the Federal Energy Regulatory Commission – Reforms FERC’s decade-old open-access transmission regulatory framework that will ensure transmission service is provided on a nondiscriminatory and just and reasonable basis, as well as provide for more effective regulation and transparency in the operation of the transmission grid. The final rule is designed to:
    • Strengthen the pro forma open-access transmission tariff, or OATT, to ensure that it achieves its original purpose of remedying undue discrimination
    • Provide greater specificity to reduce opportunities for undue discrimination and facilitate the Commission’s enforcement
    • Increase transparency in the rules applicable to planning and use of the transmission system.

  • FERC Order 1000 - A Final Rule issued in July 2011 reforms the Commission’s electric transmission planning and cost allocation requirements for public utility transmission providers. The rule builds on the reforms of Order No. 890 and corrects remaining deficiencies with respect to transmission planning processes and cost allocation methods.  Simply put, FERC is proposing to include "public policy" into the list of criteria regulators can consider when allocating "just and reasonable" costs associated with new transmission. The rule also encourages a more regional approach. Who benefits has been the guiding standard for decades.  The bottom line is it will force larger-scale plans to be produced everywhere. (FERC Order 1000 Explained - AOL Energy/FERC)

    FERC Planning Regions - This map generally depicts the borders of regional transmission planning processes through which transmission providers have complied with Order No. 890. Those borders may not be depicted precisely for several reasons (e.g., not all transmission providers complying with Order No. 890 have a defined service territory). Additionally, transmission planning regions could alter because transmission providers may choose to change region

    A group of Senators opposed to the NOPR have submitted legislation that would essentially head off the new rules at the pass. Hearings have also been requested before the Senate Energy and Natural Resources Committee, but it is unlikely that panel will hold any until the final rule is released. The beneficiary is a major sticking point. Are they limited by proximity? If so, how far?

    • Planning Reforms - The rule establishes three requirements for transmission planning:
      1. Each public utility transmission provider must participate in a regional transmission planning process that satisfies the transmission planning principles of Order No. 890 and produces a regional transmission plan.
      2. Local and regional transmission planning processes must consider transmission needs driven by public policy requirements established by state or federal laws or regulations. Each public utility transmission provider must establish procedures to identify transmission needs driven by public policy requirements and evaluate proposed solutions to those transmission needs.
      3. Public utility transmission providers in each pair of neighboring transmission planning regions must coordinate to determine if there are more efficient or cost-effective solutions to their mutual transmission needs.

    • Cost Allocation Reforms - The rule establishes three requirements for transmission cost allocation:
      1. Each public utility transmission provider must participate in a regional transmission planning process that has a regional cost allocation method for new transmission facilities selected in the regional transmission plan for purposes of cost allocation. The method must satisfy six regional cost allocation principles.
      2. Public utility transmission providers in neighboring transmission planning regions must have a common interregional cost allocation method for new interregional transmission facilities that the regions determine to be efficient or cost-effective. The method must satisfy six similar interregional cost allocation principles.
      3. Participant-funding of new transmission facilities is permitted, but is not allowed as the regional or interregional cost allocation method.

    • Nonincumbent Developer Reforms - Public utility transmission providers must remove from Commission-approved tariffs and agreements a federal right of first refusal for a transmission facility selected in a regional transmission plan for purposes of cost allocation, subject to four limitations:
        • This does not apply to a transmission facility that is not selected in a regional transmission plan for purposes of cost allocation.
        • This allows, but does not require, public utility transmission providers in a transmission planning region to use competitive bidding to solicit transmission projects or project developers.
        • Nothing in this requirement affects state or local laws or regulations regarding the construction of transmission facilities, including but not limited to authority over siting or permitting of transmission facilities. 
        • The rule recognizes that incumbent transmission providers may rely on regional transmission facilities to satisfy their reliability needs or service obligations. The rule requires each public utility transmission provider to amend its tariff to require reevaluation of the regional transmission plan to determine if delays in the development of a transmission facility require evaluation of alternative solutions, including those proposed by the incumbent, to ensure incumbent transmission providers can meet reliability needs or service obligations.

Former Federal Energy Regulatory Commission chief of staff Howard Shafferman, now a lawyer at Ballard Spahr, says in this video interview that while he basic principles of regional transmission planning are widely understood, cost allocation issues will continue to be contentious.

  • In California, the Renewable Energy Transmission Initiative (RETI) identified the transmission projects needed to accommodate these renewable energy goals, support future energy policy, and facilitate transmission corridor designation and transmission and generation siting and permitting.

  • RETI assessed all competitive renewable energy zones in California and possibly also in neighboring states that can provide significant electricity to California consumers by the year 2020. RETI also will identify those zones that can be developed in the most cost effective and environmentally benign manner and will prepare detailed transmission plans for those zones identified for development. RETI work is organized into three phases


    • Phase 1: Identification and ranking of Competitive Renewable Energy Zones (CREZ) in California and neighboring regions; Phase 1B Final Report Posted: January 5, 2009.

    • Phase 2: Development of a statewide conceptual transmission plan to access priority CREZ, based on more detailed analysis of CREZ The final Phase 2B Report, issued in May 2010, documents key changes made in the economic model, technology assumptions, competitive renewable energy zones, and out of-state (OOS) resources.

    • Phase 3: Development of detailed plans of service for priority components of the statewide transmission plan.
    • Click here for the RETI Reports page.

    5. Benefits
    • Economic Efficiencies - More efficient use of existing transmission capacity, better integration of resources, and greater investments in distributed renewable generation and off-grid solutions may increase the availability of transmission and distribution capacity for adding renewable resources and help keep ratepayer costs low and provides substantial economic benefits, including job creation and technology development

    • GHG Reduction - Electricity produced from renewable resources helps to reduce emissions of greenhouse gases and other air pollutants

    • National Security - enhances national energy security; conserves water and finite resources.

    • Reduced Curtailments, - For example, wind farms in West Texas get curtailed routinely at night because there’s not enough transmission capacity. It leads to storage economics and other things, as well as the C/Res zones. If we can reduce the system costs associated with renewable energy, whether it’s transmission capacity, or additional controls, or operating measures then that’s good.

    6. Risks/Issues
    • Transmission for Renewables is Relatively Expensive - Wind and Solar have capacity factors well on the low side of 40% meaning the lines are several times larger than the average power output demands so the cost per MWh-mile is a lot higher. In addition, these lines are a lot longer than would be required to be run from more conventional plants to load centers.

    • Cost Allocation - Cost allocation reform is one of the most difficult issues facing transmission service providers and regional market operators. FERC is proposing to include "public policy" into the list of criteria regulators can consider when allocating "just and reasonable" costs associated with new transmission. The rule also encourages a more regional approach. Who benefits has been the guiding standard for decades.

      The controversy has spawned a contentious debate, with advocates of a narrower view of regulators' discretion would codify a more narrow definition of beneficiaries.

    • Environmental Impacts can result from large renewable generation facilities,
      • A permanent loss of habitat for protected wildlife species and special status plants would occur. The availability of adequate mitigation land to compensate is uncertain, especially for expansive solar projects.
      • Large projects would create blockage of wildlife corridors, potentially constraining or eliminating important linkages between sensitive population groups.
      • Birds and bats can collide with wind turbines if located in areas with notable or threatened avian populations.
      • A permanent change in the visual character of open spaces or agricultural areas would occur, inserting large expanses of industrial features to previously uninterrupted vistas. Desert views would also be affected by glare from the mirrors and towers used in some solar thermal technologies. Wind turbines would alter hilltop and ridgeline views.
      • Limited supplies of groundwater would be used for regular cleaning of thousands of mirrors and panels for solar installations.
      • Public lands in the desert would be converted from open space, available for multiple uses such as recreation, mining, and grazing, to a single exclusive purpose – power generation.
      • A cumulative loss of resources would occur as the impacts above are realized throughout California – especially in the desert, where over 100 projects are already proposed.

    • Fragmented Decision Making - Existing transmission planning processes are fragmented across many jurisdictions, which results in difficult coordination between jurisdictions, delays in implementation of plans, and complex negotiations on sharing of cost. The Federal Government has not adequately supported or implemented an integrated approach to accelerating the development, commercialization, and deployment of renewable energy technologies, renewable electricity generation, and transmission to bring renewable energy to market. The fact that power lines traverse federal and tribal lands also may complicate the process.

    • Fragmented Utility Industry Structure - Before deregulation, the power industry consisted mainly of companies that owned and operated power plants and power lines. There was no question about who would build new power lines to connect to new power plants; the same company built and operated all the lines and the power plants within its system. The new power industry consists of many power plants, built and owned by independent companies; power lines are owned by regulated companies. Generating companies must connect their power plants to the power grid. The challenge is to allocate those costs among the generators and the regulated transmission companies. The transmission company that builds the lines bears risks associated with recovering costs in the regulatory process. That company also must raise the money to make the investment.

    • Funding Models - The wind industry has been strongly pushing for state, regional, and federal policy solutions to more broadly distribute the costs of transmission investments, as FERC’s ruling does today. Unfortunately, other regions of the country are considering policies aimed in the opposite direction, moving back towards a model requiring the next wind plant waiting in line to connect to the grid to pay for all of the cost of upgrading the grid. According to AWEA, such a policy is akin to requiring the next car entering a congested highway to pay the full cost of adding a new lane.

    • States Rights - Is electricity a local business or is it a regional or national business? There has been push-back in the courts on FERC review of state transmission planning decisions. On Feb 18, 2009, in the U.S. Court of Appeals, Fourth Circuit, two state utilities commissions and two community interest organizations petitioned for review of several rulemaking decisions made by FERC . The Coalition for Fair Transmission Policy — an industry group made up of 10 big utilities including Southern Co., Consolidated Edison, Alliant, DTE Energy, PPL, Progress Energy and PSEG — says it will lobby to change proposed Senate legislation that it says could unfairly spread the costs of building big new transmission lines across multiple states. Or, to put it another way, “states and regions that get the benefits of new transmission should be the ones to pay for them.

    • NIMBY - Not In My Backyard - Most people probably would prefer that transmission companies build new transmission lines where no one can see them. Transmission owners often find it difficult to identify acceptable transmission routes because few property owners welcome the prospect of having new transmission lines constructed nearby.

    • Geography - Space for new transmission lines may be limited. Even in areas that have a preexisting right-of-way for a transmission line, new population growth may make it difficult to install new, larger towers and lines.

    • Gold Plating - More utility investment than is necessary to ensure reliability.

    • Lack of Transmission Data - Data collections that the Federal Government relies on to monitor reliability have not kept pace with the ascendancy of transmission in a restructuring industry. The Government does not have the electrical models and data necessary to verify that existing and planned transmission capability is adequate to keep the lights on.

    • Lack of Retail Price Signals - Until we have meaningful, relevant retail price signals and retail choice for retail consumers, it is impossible for us to know the economic value of additional transmission infrastructure. That, combined with the high level of political lobbying from Boone Pickens and others, leads me to be extremely cautious in recommending large-scale transmission infrastructure construction. What if we spend lots of money (including taxpayer money) building this network, and it turns out we were wrong about its economic value? Then we’ve just created another set of stranded assets.

    • Uncertainties in Carbon Policy - We cannot know the economic value to retail consumers/taxpayers of additional transmission infrastructure connecting large-scale renewables until we have an economically meaningful carbon price, which implies that carbon policy uncertainty should be resolved before we start long-distance transmission planning.

    • Interference - Railroads are concerned about the potential for electromagnetic interference, if AC transmission lines are run along rail right of ways. HVDC lines don’t have these interference issues. Any agreements would probably have to be negotiated with individual U.S. railroads.

      7. Success Criteria
    • Seamless Regulatory System - It is critical that both states and the federal government set clear rules about who will pay for what. Without clear rules, many transmission companies will hesitate to build new transmission capacity, and generators will hesitate to build new power plants, potentially threatening reliability. Establish clear and complete filing requirements for siting proceedings.

    • Single State Entity Responsible for Transmission Siting Approval - In a few states, several government entities have responsibility to approve transmission siting proposals.

    • Complete, Funded Studies - Establish a fee structure whereby applicants pay for the costs of the studies required in the siting process. Ensure that the siting authority’s analysis takes into account a “what if” analysis, considering other options to meet a perceived need. Demand for electricity is volatile, despite forecasters’ best efforts to predict it. Siting proceedings may work for the best results if they allow for sensitivities from demand forecasts. Integrate generation and transmission planning; add demand resources. Include transmission corridors in urban growth plans.

    • Inter-State Collaboration - Enable state siting authorities to collaborate with comparable agencies in other states to review projects that cross state lines. Some transmission lines cross state boundaries, yet most state siting authorities can review only the part of the line located in their state. Coordinate state permitting processes with federal processes.

    • Time Limit for Decision Making - Set a statutory limit for the time allowed to consider a transmission siting application.

    • Identify REZ - Identify important scenic, ecological, environmental and other resources. With this information, transmission companies can avoid these areas or mitigate the visual effects of their proposals if these areas cannot be avoided.

    • Transparency - Integrate the public into consideration of siting proposals. Define considerations that can be evaluated and discussed in a transmission line siting case.

    • Retail Rates - Impose retail rates that reflect actual cost differences within a service territory to promote sound siting proposals. Examine the interactions between rate caps and rate freezes and investments in transmission.

    8. Next Steps
    • The Stimulus Bill provided assistance for the development of interconnection-based transmission plans for the Eastern and Western Interconnections, and for ERCOT. The Stimulus Bill specifically provides: “That for the purpose of facilitating the development of regional transmission plans, the Office of Electricity Delivery and Energy Reliability within the DOE is provided $80 million to conduct a resource assessment and an analysis of future demand and transmission requirements after consultation with FERC.

    • Under the 2009 Recovery Act, the DOE released a Funding Opportunity for Resource Assessment and Interconnection-Level Transmission Analysis and Planning $60 million is available to facilitate the development or strengthening of capabilities in each of the three interconnections serving the lower 48 states of the United States, to prepare analyses of transmission requirements under a broad range of alternative futures and develop long-term interconnection-wide transmission expansion plans. The interconnections are the Western Interconnection, the Eastern Interconnection, and the Texas Interconnection. There are two broad topics: Interconnection-Level Analysis and Planning and Cooperation Among States on Electric Resource Planning and Priorities. DOE intends to make 3 awards under each topic for each interconnection. To facilitate collaboration, DOE may make an award under the Cooperation topic to more than one state in the Eastern Interconnection. The funding period is 3-5 years.

    9. Projects
    • Tres Amigas - Clovis New Mexico- 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.

    10. Links
    1. FERC Order 1000 Explained   - AOL Energy/FERC
    2. WIRES (Working group for Investment in Reliable and Economic electric Systems) Washington, DC - A non-profit trade association of transmission providers, customers, and equipment and service companies formed to promote investment in electric transmission and progressive State and Federal policies that advance energy markets, economic efficiency, and consumer and environmental benefits through development of electric power infrastructure.
    3. Coordinating Interstate Electric Transmission Siting: An Introduction to the Debate The National Council on Electricity Policy July 2008
    4. AWEA – American Wind Energy Association
    5. WECC - Western Electricity Coordinating Council
    6. FERC - Transmission Investment
    7. RETI - The Renewable Energy Transmission Initiative is a statewide initiative to help identify the transmission projects needed to accommodate these renewable energy goals, support future energy policy, and facilitate transmission corridor designation and transmission and generation siting and permitting
    8. Western Renewable Energy Zones - Phase 1 Report:Mapping concentrated, high quality resources to meet demand in the Western Interconnection's distant markets Publication number DOE-1000-2009-011.
    9. California Energy Commission - Joint Integrated Energy Policy Report and Siting Committee Workshop on Transmission Planning Information and Policy Actions May 4, 2009
    10. Cities Struggle With Access to Green Energy Sources
      In cities across the country, officials are faced with the task of getting renewable energy from the outskirts of town to the urban centers where demand is greatest. NewsHour correspondent Spencer Michels reports from Los Angeles.
    11. Major Court Ruling Clears The Way To Let Renewables Into The Grid - By Ari Philips ThinkProgress Aug 19,  2014


    California Net Metering Debate

    August 2014 - Added Def. Value of Solar

    The solar industry and the state’s utilities disagree over just what impact net metering has on electricity rates, utility costs and grid operations.

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

    2. Acronyms/Definitions
    3. Business Case
    4. Benefits
    5. Risks/Issues
    6. Success Criteria
    7. Next Steps
    8. Companies/Organizations
    9. Links

    • AB-327the controversial California bill that tackles residential electricity rate reform and solar net metering policy in one fell swoop, was approved by the state Senate on Sep 9, 2013 and the Senate revisions passed the Assembly on Sep 12.   Gov. Jerry Brown has indicated his support.

    • Utilities have long argued that net metering doesn’t adequately compensate them for the costs they face in supplying solar-equipped customers with grid power while the sun isn’t shining. Too many net-metered customers could force utilities to raise rates on all non-solar customers, and eventually lead to a death spiral for utilities that end up paying out more than they’re taking in from their customer base. They argue that poor rate payers who cannot afford solar end up subsidizing rich home owners who have the capital to invest in roof top systems.

    • Solar advocates, by contrast, point to studies that show that net metering of distributed solar power is a net asset, rather than a liability, to the grid at large. Those benefits can stretch from lowering the average cost of electricity for all users, to helping meet the state’s aggressive goals to supply more and more of its power from renewable resources in the coming years.

    • Under current California low, Net Energy Metering (NEM) allows solar owners to roll their meters backward for every kilowatt-hour they send to the grid (up to the point where their bills zero out). The return they get on the electricity they generate is the same retail rate they pay for what they consume. Since the top electricity tiers are very expensive, solar can be very competitive.

    • NEM for California's IOU's is currently capped at 5%. Utilities and the CPUC have disagreed how the 5% should be calculated.

    • The California Solar Initiative was structured when it was launched in 2007 as a ten-step incentive program, and we are now at step ten. There is not another incentive program that will replace that.

    2. Acronyms/Definitions

    1. ABx 1 - During the energy crisis, the Legislature passed ABx1 (Keeley, 2001) to protect California ratepayers from rampant price fluctuations due to a dysfunctional wholesale electricity market. ABx1 1 authorized the Department of Water Resources (DWR) to issue revenue bonds to purchase power at such prices the department deemed appropriate, on behalf of the cash-strapped investor-owned utilities (IOUs) which couldn't keep up with the volatile wholesale prices. Among other stabilizing efforts, ABx1 1 included a provision that prohibited the CPUC from increasing rates for usage under 130% of baseline(tiers 1 and 2) until DWR bond charges were paid off. Those charges continue.

      Because rates in the two lowest tiers were frozen, increased costs for generation, distribution, transmission and new programs created by the Legislature and the CPUC, have been disproportionately borne by those customers whose electricity usage falls in the upper tiers.

    2. SB 695 - In 2009 SB 695 (Kehoe) was signed into law as an urgency statute. Among its provisions, the bill removed the freeze on tier 1 and tier 2 rates and intended to allow for gradual rate increases through 2018 at which time the caps for those increases would sunset. Different formulas were created for Non-CARE customers and CARE enrollees.

      As a consequence, beginning Jan 1, 2010, the CPUC could grant increases in rates charged to non-CARE residential customers for tier 1 and 2 rates by the annual percentage change in the Consumer Price Index from the prior year plus one percent, but not less than three percent or more than five percent per year. Increases in tier 1 and 2 rates for the residential CARE program were statutorily tied to annual cost of living adjustments for CalWork's benefits not to exceed three percent per year. The IOUs were also permitted to add a third tier of rates for CARE enrollees. Prior to SB 695, CARE enrollees were subject to charges under only the first two rate tiers.

      The provisions of SB 695 resulted in three to five percent increases on tier 1 and 2 rates for non-CARE customers and resulted in a commensurate decrease in rates for tiers 3, 4, and 5. The rates for CARE enrollees in tiers 1 and 2 have not increased due to the suspension of COLAs for the CalWork's program, except for the addition of a third tier for CARE enrollees in the PG&E service territory. The rate adjustments, overall, were revenue neutral to the IOUs.

      In PG&E service territory the gap between tier 1 and tier 5 decreased by 17 cents, but tier 5 was still 2.65 times higher and 21.88 cents per KWh more.

    3. Rate History Since SB 695
      PG&ETier 1 Tier 2Tier 3Tier 4Tier 5CARE1CARE2CARE3
      SCETier 1 Tier 2Tier 3Tier 4Tier 5CARE1CARE2CARE3
      . In the SDG&E rates which took effect on Sep 1 2013, the rates for tiers 3 and 4 increased more than 20% going to more than $0.34 per kWh in tier 3 and $0.36 in tier 4. A recent notice to customers from SDG&E's president reported the expected impacts - if a bill is now $250, then it will increase to $325 in September. A $100 electric bill will rise to $115. .

      Tier 1 Tier 2Tier 3Tier 4CARE1CARE2CARE4CARE4
    4. SB 743 (Steinberg/Padilla) - modifies the index to which CARE enrollee rate increases are tied to strike CalWorks and add the Consumer Price Index.

      The rates for CARE customers in tiers 1 and 2 have not increased due to the suspension of COLAs for the CalWorks program. Consequently, assistance to CARE customers is far greater than intended.

      On Sep 12, the energy provisions were deleted and the bill was changed to streamline CEQA for a new downtown Sacramento sports arena.   Status: Passed Senate and Assemby Sep 12, 2013,

    5. AB 1755 (Perea, 2012) - authorized the CPUC to approve a fixed charge for residential customers beyond the statutory caps on rate increases for Tier 1 and Tier 2 customers. Status: Senate Floor Inactive File.

    6. CARE - California Alternate Rates for Energy - Program to discount rates for low-income gas and electric customers defined as those with incomes no greater than 200% of the federal poverty level and permits no more than three rate tiers.

      Currently, CARE customers are to receive a 20% discount off of their electric and gas bills. However, because of the cap on Tiers 1 and 2, the effective discount can be much higher if CARE customer is using more than 130% of the baseline allocation. In some instances, Pacific Gas and Electric (PG&E) has reported providing discounts in the range of 60% off of the otherwise applicable bill. (See IOU Charts below)

    7. Cross Subsidies - Recovering costs incurred by one group of customers from another group of customers. For example, California has an explicit policy to shift the cost of the CARE program discounts to all non-CARE customers

    8. Economic Efficiency - Obtaining maximum consumer satisfaction from available resources. In the rate design context, economic efficiency is achieved when pricing reflects the marginal cost of generating and delivering electricity, including externalities.

    9. Externality - A cost or benefit that is not included in the market price of a good because it's not included in the supply price or the demand price. Pollution is an example of an externality cost if producers aren't the ones who suffer from pollution damages. Externality is one type of market failure that causes inefficiency.

    10. Fixed Charges - In the spring of 2010 PG&E, as part of its triennial rate case, PG&E applied to the CPUC to establish a fixed customer charge of $3 for all non-CARE residential customers, and $2.40 for all CARE enrollees. Although the CPUC recognized a growing disparity in rates, they rejected the charge on legal and policy grounds and characterized it as "the most significant change in residential electric rate design in the last decade."

      Legally the CPUC opined that the statutory caps on rate increases for tier 1 and 2 residential customers included any new or increased fixed rate charges. They specifically found that the commission was "prohibited by law from approving PG&E's customer charge to the extent the total bill impacts exceed these statutory limitations on baseline rate increases.".

      Sacramento Municipal Utility District imposed, for the first time, a fixed charge of $10 per residential customer in 2012, which was increased to $12 this year, and there are plans increase the charge $2 per year for 3 to 4 years. Why the tool is critical now is not readily apparent; the costs of electric service now labeled as "fixed" are not new. The IOUs argue that the lack of a fixed charge has caused high usage customers to pay unfairly high bills and created an artificially attractive market for customer-owned generation because the highest tier rates are far in excess of cost. A fixed charge would bring down upper tier rates but the lack of a fixed charge didn't exacerbate the upper tier rates, the rate freeze on tier 1 and 2 customers is largely to blame.

    11. GRC - General Rate Case - Proceedings currently take place every three years before the CPUC. The GRC will set the base revenue requirements for electric/gas operations. These base revenues recover the utility's operation and maintenance expenses, depreciation, and taxes and provide a return on invested capital.

    12. Market Rate Net Metering - The user's energy use is priced dynamically according to some function of wholesale electric prices. The users' meters are programmed remotely to calculate the value and are read remotely. Net metering applies such variable pricing to excess power produced by a qualifying systems.

      Market rate metering systems were implemented in California starting in 2006, and under the terms of California's net metering rules will be applicable to qualifying photovoltaic and wind systems. Under California law the payback for surplus electricity sent to the grid must be equal to the (variable, in this case) price charged at that time.

    13. Marginal Cost - The cost of providing one additional unit of a good or service. In the electric utility context there are several types of marginal costs – energy, generation capacity, transmission capacity, and distribution capacity. The change in utility costs resulting from an additional customer or additional use of energy or capacity, or the change in costs related to a change in output. The CPUC uses marginal costs in allocating the utility’s revenue requirement to customer classes, and as reference points in rate design. In the California ratemaking context, short-run marginal costs would reflect current market conditions (e.g., over- or under- capacity situations), while long-run marginal costs would include the entire cost of new facilities.

    14. NEM - Net Energy Metering - An electricity policy for consumers who own renewable energy facilities (such as wind power and solar power), and allows them to use generation whenever needed, instead of just when generated.

      The rules vary significantly from place to place: if net metering is available, if and how long you can keep your banked credits, and how much the credits are worth (retail/wholesale). Most net metering laws involve monthly roll over of kWh credits, a small monthly connection fee, require monthly payment of deficits (i.e. normal electric bill), and annual settlement of any residual credit. The treatment of annual excess generation ranges from lost, to compensation at avoided cost, to compensation at retail rate. In California, excess generation is rolled over indefinitely.

      There is considerable confusion between the terms "net metering" and "feed-in tariff". In general there are three types of compensation for local, distributed generation:

      1. Feed-in Tariff (FIT) which is generally above retail, and reduces to retail as the percentage of adopters increases.    See my post -  Feed-in Tariffs (FIT)

      2. Net Metering - which is always at retail, and which is not technically compensation, although it may become compensation if there is excess generation and payments are allowed by the utility. Net metering only requires one meter. A feed-in tariff requires two.

      3. Power Purchase Agreement (PPA) - compensation which is generally below retail, also known as a "Standard Offer Program", and can be above retail, particularly in the case of solar, which tends to be generated close to peak demand.

    15. Net Purchase and Sale - A different method of providing power to the electricity grid that does not offer the price symmetry of net metering, making this system a lot less profitable for home users of small renewable electricity systems.

      Under this arrangement, two uni-directional meters are installed—one records electricity drawn from the grid, and the other records excess electricity generated and fed back into the grid. The user pays retail rate for the electricity they use, and the power provider purchases their excess generation at its avoided cost (wholesale rate). There may be a significant difference between the retail rate the user pays and the power provider's avoided cost.

    16. Rate Cost Components: In California, rates are unbundled into generation, distribution, and transmission components based on key costdrivers for each component.
      • Generation Costs: Costs related to generating power to produce electricity. Typically defined in terms of capacity costs (e.g., $100/kW) and energy costs ($0.08/kWh).

      • Transmission Costs: Costs associated with the transmission system for moving power long-distances or at high voltage, regulated primarily by FERC.

      • Distribution Costs: Costs associated with distributing power to customers (e.g., poles and wires, meters). Typically defined in terms of capacity costs ($/kW) and customer costs ($ per customer)

      • PPC - Public Purpose Charges: Costs associated with a variety of programs, including energy efficiency, demand response, solar and distributed generation, low-income and medical needs

    17. Tier Rates - Residential electric rates in California's IOU territories are generally designed in a four or five-tiered structure based on the customer's quantity of electricity usage. Within prescribed usage tiers, the amount of electricity consumed is priced at increasing per-unit rates. Tier 1 is the customer's "baseline" - the level deemed necessary to supply a significant portion of the reasonable energy needs of the average residential customer; Tier 2 applies to usage between the baseline and 130% of that amount. Baseline levels vary depending on the climate of the region (e.g. hotter regions have a higher baseline).

      This multi-tiered conservation pricing structure grew out of the energy crisis. Prior to that time, a two-tier pricing structure was common.
      PG&E Tier Rate History  Source: TURN

    18. TOU - Time-of-Use Rates - (See my post Dynamic Pricing)  With time-based rates, utilities charge different prices based on the time of day electricity is used. The different charges should reflect the ups and downs of wholesale power prices due to supply and demand. In hot climates, power is typically most expensive late summer afternoons and early evening hours, when heavy air-conditioning use causes spikes in electricity use. With time-of-use or TOU rates, energy charges are higher during the hours of peak demand but lower at all other times.

      This creates financial incentives for consumers to shift energy use to the less expensive off-peak hours, which relieves the strain on energy supplies. However, customers in the hot climates cannot shift air conditioning use to another time of the day like they can their laundry.

      Peak demand dictates the size of generators, transmission lines, transformers and circuit breakers for utilities even if that amount lasts just a few hours a day. Power generation which is able to quickly ramp-up for peak demand often uses more expensive fuels, is less efficient and has higher marginal carbon emissions. Most natural gas plants in California's fleet are older and lack the fast-start technology, consequently they must idle until needed to meet peak demand and in that stand-by mode continue to produce emissions.

      TOU rates are advocated by many environmental groups who argue that the rates help rein in peak demand and avoid building new power plants. Some electric utilities similarly advocate for TOU because the rate reflects the principle of cost-causation and requires customers to make decisions about energy use when it has the highest cost and encourage customers to shift significant amounts of energy use away from the peak hours when power is most costly.

      TOU metering is a significant issue for solar power systems because they produce energy during the daytime peak-price period, and produce little or no power during the night period, when price is low. When this is the case, the effective output of a solar panel is increased, as more electricity can be consumed than is produced.

      • In Nov 2011, the CPUC approved a decision imposing mandatory time-variant pricing programs on small business customers of PG&E in two stages, beginning in November 2012.

      • In Dec 2012, the CPUC approved a decision imposing mandatory time-variant pricing programs on small business customers of SDG&E starting in November 2014, with an optional program commencing in November 2013.
    19. Value of Solar - The basic concept behind value of solar is that utilities should pay a transparent and market-based price for solar energy. The value of solar energy is based on:
      1. Avoiding the purchase of energy from other, polluting sources
      2. Avoiding the need to build additional power plant capacity to meet peak energy needs
      3. Providing energy for decades at a fixed price
      4. Reducing wear and tear on the electric grid, including power lines, substations, and power plants x
    20. Source: Institute for Local Self-Reliance

      Value of solar is not like net metering, where producing energy reduces your electricity bill just like turning off a light. As adopted, Minnesota’s value of solar formula includes all of the basic components of the theoretical policy, however, the overall adopted policy had some good elements that were lost in the legislative process.

      Source: Institute For Local Self-Reliance

    3. Business Case
    • Utilities argue: "An electricity bill’s per-kilowatt-hour charge has three primary portions, the generation portion of the charge, the amount for that kilowatt-hour to actually be generated, the transmission portion of the charge, the part you pay for the use, construction, maintenance, etc., of the transmission line between the generation station and the local substation, and the distribution charge that is very similar to the transmission portion but is for the distribution system that actually allows the electricity to be delivered. NEM customers avoid paying non-generation components of rates for the portion of their electricity."

      Instead of NEM, SCE would like a “buy-all/sell-all (BA/SA) model” in which customers pay standard retail rates and get some payment for every kilowatt-hour they produce. BA/SA, however, would reimburse not the retail rate but only the generation portion of the retail rate.

    • Solar advocates argue: "Cost in our electric infrastructure in California is driven by peak demand. There is a huge benefit to reducing peak, and that is what the residential rooftop solar supported by NEM does. There are costs, but there are also benefits, and it works out that it is not really a subsidy.”

      A study on the cost-effectiveness of NEM in the Pacific Gas and Electric (PG&E) service territory by Crossborder Energy that concluded that, “on average over all customer classes, NEM does not impose costs on non-NEM customers,” adding, “on average, over all customer classes, NEM may now be cost-effective throughout the investor-owned utilities’ territories.”

    • SB 327 As Ammended
      1. Requires the California Public Utilities Commission (PUC), when it approves changes to electric service rates charged to residential customers, to determine that the changes are reasonable, including that the changes are necessary in order to ensure that the rates paid by residential customers are fair, equitable, and reflect the costs to serve those customers.

      2. Requires PUC to consider specified principles in approving any changes to electric service rates.

      3. Requires PUC to report to the Legislature its findings and recommendations relating to tiered residential electric service rates in a specified rulemaking by January 31, 2014.

      4. Recasts and revises limitations on electric and natural gas service rates of residential customers, including the rate increase limitations applicable to electric service provided to California Alternate Rates for Energy (CARE) customers.

      The Senate amendments, substantively revise this bill by adding new provisions
      1. Require the IOUs to provide annual distribution plans and for the PUC to approve those plans, if it finds them reasonable, in each IOU General Rate Case.

      2. Revise the current Net Energy Metering (NEM) statute to specify the maximum program capacity for customers in IOU service areas, require the PUC to develop a new NEM program by July 2015 and establish a transition to the new NEM program by 2017. The new NEM program is to be based on electrical system costs and benefits to nonparticipating ratepayers and remove both the total system capacity cap and the one megawatt project size limit. Existing NEM customers will be transitions no later than December 2020 to the new NEM.

        AB 327, as amended, calls for the CPUC to create a new study to serve as the basis for the state’s big three investor-owned utilities to develop brand-new net metering programs by the end of 2015, and instructs them to put those new programs in place in 2017.

        The bill states "There shall be no limitation on the number of new eligible customer-generators entitled to receive service pursuant to the standard contract or tariff after January 1, 2017" This means the current 5% cap for NEM of aggregate consumer demand will be eliminated.

        The three IOUs defined aggregate consumer demand as “coincident” peak demand. Renewables advocates argue that “non-coincident” peak demand should be used.

        Coincident peak demand is the designated period when all sectors (residential, commercial and industrial) reach their maximum electricity consumption and the state’s consumption peaks.

        Non-coincident peak demand is the sum of the individual peaking demands of all customers in the three sectors. Residential peak is typically late afternoon, commercial peak is early mid afternoon, and industrial peak can be at night. That sum of all peaks is greater than the total peak demand at any one time of the day.

        When the installed DG capacity eligible for NEM divided by the peak demand gets to five percent, the utilities are off the hook. So they want that bottom number to be smaller. Renewables advocates want just the opposite because the larger number keeps what one solar advocate called their “backbone” incentive in place.

        In April 2013, the CPUC concluded that the legislature “did not intend ‘aggregate customer peak demand’ to mean coincident peak demand

        Solar and ratepayer advocates were concerned that individual utilities might seek to alter the rates and tariffs that net-metering customers face in ways that could reduce their value. To counter that possibility, the new amendment to AB 327 requires that any such changes take place during a “rulemaking proceeding involving every large electrical corporation.”

        That means that the state’s three IOUS's, PG&E, SCE, and SDG&E, won’t be free to make changes on their own, but will have to collectively seek changes in a major CPUC process

      3. Provide the PUC with authority to require IOUs to procure renewable energy generation above that which is required in the 33% Renewable Portfolio Standard.

      4. Authorize the PUC to approved fixed monthly charges no greater than $10 for residential customers and $5 for low-income customers beginning in 2016. Specify discounts for low-income customers are not to exceed 30% to 35% of the average non-low-income customer.

        AB 327 doesn’t change rates itself. “Rate reform is going to be decided by the CPUC. All that AB 327 does is give the CPUC some more tools in that process.

      5. Establish that by 2018 the default rate schedule for residential customers shall be based on Time of Use and establishes provisions to protect senior or other vulnerable customers, in hot climate zones, from unreasonable hardship.

      6. Add technical amendments to the provisions related to residential electricity rate reform.

    • PUC Residential Rate Design Proceeding (R.12-06-013) is underway. On June 28, 2012, PUC initiated a proceeding to examine current residential electric rate design, including the tier structure in effect for residential customers, the state of time variant and dynamic pricing, potential pathways from tiers to time variant and dynamic pricing, and preferable residential rate design.

      This PUC proceeding is open to the public and allows interested parties opportunities to participate by making comments on PUC rulings, making rate design proposals, commenting on proposals made by others, commenting on proposals made by staff, and commenting on any decision made by PUC. According to the public schedule, final rounds of comments are due mid-summer 2013. This would be followed by a draft decision, which is also open to comments. (See 7. Next Steps and  9. Links below)

    4. Benefits
    • Reducing Peak Demand - Solar advocates argue "Cost in our electric infrastructure in California is driven by peak demand. There is a huge benefit to reducing peak, and that is what the residential rooftop solar supported by NEM does. There are costs, but there are also benefits, and it works out that it is not really a subsidy.”

    • Incentives for Conservation & Energy Efficiency - Large fixed charges can undermine customer incentives to reduce consumption and undertake energy efficiency improvements. For example, if you used 500 kilowatt-hours of electricity per month (about average for a California customer) and your rate was 15 cents for each of those kilowatt-hours, it might take two years to recover your investment in new energy efficient lighting.

      But if the utility charged you a $25 fixed charge per month, and reduced your rate to 10 cents per kilowatt hour to compensate, it would now take three years for that same energy efficiency investment to pay back because you cannot avoid that $25 charge and you would have to save 50 percent more kilowatt hours to recover your investment. Similar impacts would occur for consumers considering the installation of rooftop solar.

      (Note: AB327 permits fixed charges, but does not require them,

    • Reduced GHG - SB 327 makes it clear NEM will be additive to the state's 33% RPS goal for renewable energy.

    5. Risks/Issues
    • Cost Calculation Methodology - Utilities' "all-in cost" is what energy experts call the "avoided cost." An avoided-cost analysis does not consider longer-term impacts. It is very hard for traditional utility people to see rooftop solar as a resource because they do not control it. As a result, they don’t consider it a resource; they think of it as opportunity energy, so they are not willing to consider cumulative impacts.

      In the absence of real data, utilities assume a simplistic binomial distribution of costs and benefits. The straw man is that solar either avoids transmission and distribution costs or it doesn’t, and the conclusion is that since it doesn’t, because PV has to be connected to the grid, therefore all the costs apply to solar and none are avoided.

      Will there will be worst-case days with both high peak demand and high cloud cover? I'd say "no" for a California summer heat wave, but I'm not responsible for maintaining the grid. Maybe a giant wildfire blots out the sun?

      In addition, economics change based on PV penetration. Enough solar on the grid will collapse peak hour demand. That has already happened in Germany. When high peak demand falls then the spread between the wholesale cost of midday power and late night power goes away. The most expensive power will be found just before solar kicks in and right after it goes away. In that potential future case, end-user solar would be sending relatively low value electricity to the grid and taking back more expensive.

    • Stranded Costs -   Utilities argue "An electricity bill’s per-kilowatt-hour charge has three primary portions, the generation portion of the charge, the amount for that kilowatt-hour to actually be generated, the transmission portion of the charge, the part you pay for the use, construction, maintenance, etc., of the transmission line between the generation station and the local substation, and the distribution charge that is very similar to the transmission portion but is for the distribution system that actually allows the electricity to be delivered. NEM customers avoid paying non-generation components of rates for the portion of their electricity."

    • Unfair Upper Tiers  - If a family can't buy or lease solar to shave the tier 3 and 4 electricity rates off of their bill, and if they don't qualify for enrollment in the CARE program, the cost of electricity, particularly in hot climates, can be a tremendous burden.

    • Legislative Rate Making - There is little disagreement between that the indices and freezes on tier 1 and 2 residential rates must be eliminated and that any modification for those rates must be gradual so as to prevent ratepayer shock. But should the Legislature provide a framework for rate design to reflect and protect its priorities? Some argue that restrictions in statute amount to "legislative ratemaking"

    • Equity - Utilities argue the beneficiaries of net metering are relatively rich home owners, while relatively poor rate payers who cannot afford to install solar or do not own their own homes have to support more fixed costs.

    • Time Lag in Net Metering Contracts - Under existing law, net metering would be suspended completely as of 2014, AB 327 removes that suspension. Utilities and the solar industry have been working under a deadline imposed by the CPUC, which would force net metering programs to cease as of the end of 2014. AB 327, as currently amended, would put that worry to rest.

      Under current law, there are no grandfathering protections at all for existing net metering customers. Everything under this is additive. These are all additional protections that nobody had before.

    • Impact on Current Net Metering Contracts - It was feared AB 327 would subject today’s existing net metering contracts to review and potential rewriting, as the CPUC comes up with a new net metering regime. That led some groups to decry the bill as an attempt to undercut their investment in solar.

      The Sep 2013 bill revisions address this concern by setting a deadline of Mar 31, 2014 for the CPUC to set a procedure for how it will deal with “grandfathering” existing net metering contracts into the new program that AB 327 requires it to create. It also states that “Any rules adopted by the commission shall consider a reasonable expected payback period based on the year the customer initially took service under the tariff or contract.”

      While that doesn’t change the fact that existing net metering contracts will be subject to change, it does address the concern that the previous version of the bill was “creating a lag time of uncertainty as the market waited for the new rules.

    • Net Metering Cap - Several years ago, the CPUC extended the cap for net metering from 2.5 percent to 5 percent of each IOU's nameplate capacity, but there’s been a longstanding dispute about how the  cap should be calculated.  Once the total number of customers signed up for net metering exceeded that cap, in terms of their kilowatt contribution to their utility’s total power mix, new customers would have been excluded.

      AB327 removes all legal uncertainty, and makes clear how the cap is calculated. As amended,, it sets clear figures for when each utility will reach that cap. That will either come as of Dec 31, 2016, or at the following capacities, whichever come first: 607 megawatts for SDG&E; 2,240 megawatts for SCE; and 2,409 megawatts for PG&E.

    • Consumer Backlash to TOU Rates - The impacts of TOU rates would be especially felt by inland climates where air conditioning use is the highest and drives peak demand in the state. if not managed well, the imposition of mandatory TOU rates on customers will result in a significant customer revolt. Even with effective notice and education of customers about how to manage TOU rates, the inland regions of California will be hit the hardest due to their reliance on air conditioning during the summer months.

      SMUD announced its TOU rate structure this year but customers will not be switched to TOU until 2018. To ensure that customers have adequate notice and education and to gain customer acceptance, delay default TOU and permit mandatory TOU with bill protection beginning in 2020.

    • Low Income Incentives - Because lower rates tend to encourage greater electricity consumption, should assistance for low-income households be offered as a fixed monthly credit, similar to food stamps, rather than as a rate discount?

    6. Success Criteria In 2007 the CPUC adopted principles for rate design and expressed intent to use those as guidance in the Residential Rate Design Proceeding currently underway
    1. Rates should be based on marginal cost;
    2. Rates should be based on cost-causation principles;
    3. Rates should encourage conservation and reduce peak demand;
    4. Rates should provide stability, simplicity and customer choice; 
    5. Rates should encourage economically efficient decision-making.
    7. Next Steps
    • The CPUC initiated a rulemaking on policy guidance for rate design in the summer of 2012 (R.12-06-013). They intend to consider how the state's energy policy goals for 2020 are affected by retail rate design and how rate design policies can and should be used to meet long-term climate and energy policy goals in an effort to align rates with policy objectives. More specifically, the proceeding will examine "whether the current tier structure continues to support the underlying statewide-energy goals facilitates the development of customer-friendly technologies, and whether the rates result in inequitable treatment across customers and customer classes."

    8. Companies/Organizations
    1. CPUC - California Public Utilities Commission, San Franciso

    2. DRA - Division of Ratepayer Advocates San Francisco - A California state agency whose statutory mission is to obtain the lowest possible rate for service consistent with reliable and safe service levels. In fulfilling this goal, DRA also advocates for customer and environmental protections.

    3. PG&E - Pacific Gas and Electric, San Francisco

    4. SCE - Southern California Edison, Rosemead

    5. SDG&E - San Diego Gas and Electric, San Diego

    6. SMUD - Sacramento Municipal Utility District, Sacramento

    7. TURN - The Utility Reform Network, San Francisco

    9. Links
    1. Minnesota Value of Solar
    2. Free the Grid 2012 - policy guide that grades all 50 states on two key renewable energy programs: net metering and interconnection procedures.

    3. AB-327 Electricity: natural gas: rates: net energy metering: California Renewables Portfolio Standard Program.

    4. DSIRE - The Database of State Incentives for Renewable Energy

    5. DRA's Presentation on Rate Design Basics.

    6. CPUC -  Residential Rate Design Proceeding  (R.12-06-013)

      Aug. 27, 2012, 9:30 a.m. – 4 p.m.: Workshop to Discuss and Refine Preliminary Questions including transitioning to Time Varying and Dynamic Rates for Residential Rate Structure Rulemaking
    7. Dec. 5-6, 2012: Public Workshops on the CPUC's proceeding to Conduct a Comprehensive Examination of Investor Owned Electric Utilities’ Residential Rate Structures (R.12-06-013)
    8.  CPUC Workshop - December 6, 2012 - Retail Rate Reform Proceeding
      [Archive Video Part 1] [Send Eclip]
      [Archive Video Part 2] [Send Eclip]
       CPUC Workshop - December 5, 2012 - Retail Rate Reform Proceeding
      [Archive Video Part 1] [Send Eclip]
      [Archive Video Part 2] [Send Eclip]

      June 25, 2013Workshop on Time Varying and Dynamic Rates

       CPUC Workshop - June 25, 2013 - Time Varying and Dynamic Rates
      [Archive Video Part 1] [Send Eclip]
      [Archive Video Part 2] [Send Eclip]