Distributed Generation Market Drivers
Important Legislative Market Drivers:
Greenhouse Gas legislation that requires cities and businesses to reduce fossil fuel use.
Renewable Portfolio Standard (RPS) requires utilities to produce 33% of their energy with renewable energy by 2020.
Distributed Generation-providing energy at the load. Not tied to transmission lines.
Feed-in-tariffs. Pricing renewable energy to include certain externalities and to encourage points 1-3 above.
SB 32 coming online in 4th quarter of 2010. <3 MW systems.
Environmental. Air and water quality standards not met with non-renewable electrical generation fuels in new facilities.
RPS and Utilities
The Renewable Portfolio Standard requires retail sellers (defined as investor‐owned utilities, electric service providers, and community choice aggregators) to increase renewable energy as a percentage of their retail sales to 20 percent by 2010. State law also requires publicly owned utilities to implement the standard but gives them flexibility in developing specific targets and timelines. In November 2008, Governor Schwarzenegger raised California’s renewable energy goals to 33 percent by 2020 in his Executive Order S‐14‐08. In July 2009, the California Public Utilities Commission reported that the three investor‐owned utilities were supplying approximately 13 percent of their aggregated total sales from eligible renewable resources as of 2008, far below the 20 percent required by 2010. Publicly owned utilities are showing some progress in renewable energy procurement with expectations for the 15 largest publicly owned utilities of 12.4 percent of RPS eligible renewable retail sales by 2011, but this progress is still far short of the renewable target.
California Energy Commission Recommendation
Because of the importance of achieving the state’s RPS goals, the IEPR Committee reinforces the need for the California Public Utilities Commission to be committed to imposing penalties on investor‐owned utilities for non‐compliance with RPS targets.
Senate Bill 1078 (Sher, Chapter 516, Statutes of 2002): Established California’s Renewables Portfolio Standard (RPS) requiring retail sellers of electricity (IOUs, community choice aggregators, electric service providers) to procure 20 percent of retail sales from renewable energy by 2017. The publicly owned utilities are encouraged, but not required, to meet .
Energy Action Plans I (2003) and II (2005): The first Energy Action Plan recommended accelerating the RPS deadline to 20 percent by 2010, and the second recommended a further goal of 33 percent renewables by 2020.
Senate Bill 107 (Simitian, Chapter 464, Statutes of 2006): Required the IOUs to meet the “20 percent by 2010” goal as recommended in the Energy Action Plan I. The bill expanded the RPS reporting requirements of the publicly owned utilities to the Energy Commission and expanded RPS eligibility of out‐of‐state renewable resources.
Executive Order S‐06‐06 (2006): Established a biomass target of 20 percent within the established RPS goals for 2010
Executive Order S‐14‐08 (2008): Established accelerated RPS targets (33 percent by 2020) as recommended in the Energy Action Plan II. The order also called for the formation of the Renewable Energy Action Team, comprised of the Energy Commission, Department of Fish and Game, Bureau of Land Management, and U.S. Fish and Wildlife Service. Through the team, the Energy Commission and the Department of Fish and Game are to prepare a plan for renewable development in sensitive desert habitat.
Executive Order S‐21‐09 (2009): Directs the ARB to work with the CPUC, the California ISO, and the Energy Commission to adopt regulations increasing California’s RPS to 33 percent by 2020. The ARB must adopt these regulations by July 31, 2010.
NOTE. The 33 percent RPS target is expected to provide 15.2 percent of the total GHG reductions needed to meet the AB 32 goal of achieving 1990 emissions levels by 2020. The state will not meet its greenhouse gas reduction targets if it does not meet the 33% RPS.
Climate Chnage and Greenhouse Gases (GHG)
Renewable energy is the first supply‐side resource in the loading order and a key strategy for achieving a significant portion of the Climate Change Scoping Plan target for greenhouse gas emission reductions from the electricity sector. Increasing the amount of renewable energy in California’s electricity mix also reduces the risks and costs associated with potentially high and volatile natural gas prices while also reducing the state’s dependence on imported natural gas used to generate electricity. Renewable resources also provide other benefits such as economic development and new employment opportunities, benefits that are becoming increasingly important given the current recession.
Source, California Energy Commission
Increased use of distributed generation is another strategy for meeting the state’s GHG reduction goals. Distributed energy systems are complementary to the traditional electric power system and include small scale power generation technologies (for example, CHP, photovoltaic, small wind turbines) located close to where the energy is being used. Distributed generation has many advantages, including increased grid reliability, energy price stability, and reduced emissions, especially in industrial applications. California is leading the nation in implementing policies to encourage distributed generation development. The following policies were implemented to encourage the use of distributed generation systems as a way of meeting the state’s climate change goals while increasing reliability:
Distributed Generation and Feed-in Tariff (FIT) Legislation
Senate Bill 1 (Murray, Chapter 132, Statutes of 2006): This bill enacted the Governor’s Million Solar Roofs program with the overall goal of installing 3,000 MW of solar PV systems.
Increasing CHP is a key strategy for displacing conventional power sources. To help track the state’s CHP goals, the ARB will report on the GHG emissions reductions resulting from the increase of electricity generated from CHP. Also, in December 2009, the Energy Commission is scheduled to adopt guidelines to establish the technical criteria for CHP system eligibility for programs developed by IOUs and publicly owned utilities.
SB 32 Creates the state’s first European feed-in tariff with rates to be set by the CPUC by July 2010. Signed by Governor in October 2009.
AB 1106 Feed In-Tariff is a full German/Spain equivalent feed in-tariff that has passed the state Assembly and is now in the Senate Appropriations Committee. If approved by this committee in early 2010 it will go for a final vote in the Senate. If approved by the Senate it will be sent to the Governor for signature.
While reducing greenhouse gas emissions is of paramount concern, it is not the only environmental issue facing California’s electricity sector. The State Water Resources Control Board has issued a draft policy to phase out the use of once-through cooling in the state’s 19 coastal power plants to reduce impacts on marine life from the pumping process and the discharge of heated water. Another issue is the lack of emission credits in the South Coast Air Quality Management District that makes it difficult to obtain the necessary permits to build reliable replacement power before aging, less-efficient power plants can be retired or repowered.
Despite efforts to expand renewable generation, recent utility RPS procurement forecasts for 2010 and 2020 indicate that substantial challenges remain. As of June 2009, the CPUC has approved 116 RPS contracts totaling 8,334 MW; of that approved capacity, a little over 10 percent – 860 MW – has come on‐line and is delivering energy to the grid. An additional 13 contracts for 5,941 MW are under review.56 While the IOUs have made progress adding renewable contracts to their portfolios, they do not expect to meet the 2010 target and will be significantly below the 33 percent target in 2020 unless they add renewable resources at a much faster pace.
California Energy Commission staff estimate that if the ARB Climate Change Scoping Plan goals are achieved for energy efficiency, CHP, and roof‐top solar, the state will need 45,000 GWhs of additional renewable energy to meet the RPS goals.
California Energy Commission Comments on DG
The 2007 Integrated Energy Policy Report (IEPR) identified the need to expand and upgrade California’s distribution system to prepare for the resource mix needed to reach GHG emission reduction goals. With state policies that rely increasingly on preferred resources, the distribution system must be able to integrateand efficiently use distributed resources. With potentially billions of dollars being spent on distribution system upgrades, the state needs to ensure that those upgrades will facilitate meeting the goals for increased renewable resources.
To support the goal of integrating increased quantities of both renewable and nonrenewable distributed generation into the grid, the Energy Commission recommends:
The Energy Commission and the CPUC should open a joint proceeding to develop a comprehensive understanding of the importance of distribution system upgrades, not only to assure reliability, but also to support the cost‐effective integration and interoperability of large amounts of distributed energy for both on‐site use and wholesale export. The proceeding should focus on the following:
1.Requiring utilities to provide an assessment of the areas or locations on their systems in which distributed generation for both on‐site use and/or export would be of greatest value. The studies should report on operational characteristics that would have greatest value; tools, data and criteria used to select these locations; and obstacles to deploying specific types of distributed generation in these areas (for example, high density residential areas).
2.Reviewing and requiring the use of distribution system operational models and economic/capital investment models in utility rate cases.
3. Requiring utilities to use these tools to demonstrate that investments in advanced grid technologies will support grid modernization goals, including from a standpoint of cost effectiveness.
4. Implementing and validating open International Electrotechnical Commission (IEC) communication standards for distributed energy resources before proprietary solutions become established. Although these standards are not required in the United States, they are being implemented in Europe where most countries are mandated to use IEC standards. California can leverage European efforts to develop and implement these standards and ensure that the state benefits from the widespread use of communication standards. Once implemented for photovoltaic, the same communication standards can be used for other renewable systems, such as wind, fuel cells, and biomass, as well as for distribution automation equipment.
5.Because net metering is an essential tool for making renewable distributed generation a cost‐effective choice for customers and for maximizing the development of in‐state renewable generation that requires no transmission upgrades, the Legislature should require utilities to increase their net energy metering cap to 5 percent to allow reasonable growth and support for the deployment of renewable generation in California. The CPUC is required to report to the Legislature and the Governor by January 1, 2010, on the costs andbenefits of net energy metering. Once that report has been completed and reviewed, increasing the cap beyond 5 percent can be evaluated.
Role of Distributed Resources
Although improvements are underway to streamline siting and permitting for transmission and renewable energy facilities, there is a risk that a resource mix depending heavily on utility‐scale solar electric projects in remote areas may be delayed beyond 2020. Shifting to a resource mix including both large‐scale central station projects and distributed generation (DG) would help the state meet its goal of 33 percent of retail sales from renewable energy by 2020 and lay the foundation for achieving the Governor’s Executive Order goal of 80 percent reduction in greenhouse gas emissions from 1990 levels by 2050.
Distributed renewable resources include ground‐mounted solar projects up to 20 MW in size; distributed biogas capacity from wastewater processing, landfill gas, animal manure digester gas, and food processing; distribution‐scale solid fuel biomass; other clean stand‐alone technologies; and distribution‐level CHP that reduces GHG emissions through the joint production of electricity and energy needed to meet industrial and commercial thermal loads.
Renewable projects that interconnect to the grid at the distribution level can come on‐line faster than large projects (greater than 20 MW) that interconnect to the transmission system directly.
Typically DG facilities do not require new transmission investment, extensive environmental reviews, or a lengthy permitting process.
Recent studies indicate substantial technical potential for distribution‐level generation resources located at or near load. A 2007 estimate from the Energy Commission suggests that there is roof space for over 60,000 MW of PV capacity, although the study did not factor in roof space that is shaded or being used for another purpose.The California Renewable Energy Transmission Initiative Phase 1B Final Report (RETI Phase 1B Report) included a preliminary estimate suggesting that as much as 27,500 MW of 20‐MW ground‐mount PV projects could be located at substations in California.246 The California Biomass Collaborative estimates that there is technical potential for about 1,700 MW of distributed biogas capacity in California from wastewater processing, landfill gas, animal manure digester gas, and food processing Studies by the CPUC and the Energy Commission have included scenarios of high penetration of distributed resources. The CPUC Energy Division Preliminary 33 Percent Implementation Analysis included a scenario with about 14 gigawatt (GW) of PV systems under 20 MW and also included about 250 MW of distributed biogas capacity. Energy Commission staff analysis included a scenario that met one‐fifth of the 33 percent goal with biopower, consistent with the Governor’s Executive Order S‐06‐06. This scenario included about 8 GW of distributed solar and about 190 MW of distributed biopower, although this excludes biomass projects identified by the RETI Phase 1B report as having fuel to support more than 20 MW of solid‐fuel biomass capacity.
Simulations and system analysis have shown that a significant amount of wholesale distributed renewable energy could be integrated into the California distribution grid. A recent analysis byE3 for the CPUC Energy Division found that approximately 69 percent of the California IOUsubstations can interconnect projects of 10 MW or smaller. Another study by General Electric onthe effect of distributed renewable energy on feeder lines found that limits could range from 15percent to 50 percent of feeder capacity depending on location and distribution. In addition,preliminary staff analysis suggests that about 10 GW to 11 GW of wholesale distributed renewable energy could be connected at the distribution level, at substations, or on distribution feeders.
So far, the potential for distributed resources to contribute to the RPS goals remains largely untapped. As of July 2009, there are more than 560 MW of PV and more than 300 MW of biopower installed in California at the distribution level (20 MW or less per project). While mostof the currently installed PV is not eligible for the RPS, much of the biopower is. IOUs have active RPS contracts for more than 180 MW of projects 20 MW and smaller; this is less than 2 percent of IOU RPS contracts. Publicly owned utilities have active RPS contracts for almost 150MW of projects 20 MW and smaller; this is about 14 percent of publicly owned utility RPS contracts.
Distributed energy resources (DER) are parallel and stand-alone electric generation units located within the electric distribution system at or near the end user. DER can be beneficial to both electricity consumers and if the integration is properly engineered, the energy utility.