Larger Solar Farms Submitted into CAISO Cluster for 2018

There are several factors that are making it more probable for new projects being submitted into the annual CAISO cluster application window each march to be larger than in prior years.

  1.  The cost of starting a CAISO cluster application process is $150,000 regardless of size.
  2.  Secondly the time for finishing through the phase I, phase II and final agreement process is the same for all sizes
  3. It is increasingly difficult to find a 70KV line for the old 20MW preferred project that allows a line tap and therefore does not require building a significant local substation
  4. The CA utilities have fulfilled their RPS quotas for several years into the future.

These and other factors make it more prone to start 100-300MW type projects on selected transmission lines where there is a probability of receiving full deliver-ability some years in the future.

We find that now these larger projects are starting to be more prevalent than in the past when the golden size was 20MW on a 69KV transmission line and you might win an annual RPS RFO or RAM RFO with the big three utilities

 

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California RAM Programs Ending

The final RAM RFO offering are now ended, but the utilities can use this purchasing mechanism for future RFOs as they may seem fit to offer.

This program was a great boon to 20MW size solar projects in California from it’s inception until its final termination with filings in late 2015 and early 2016 to request termination from the CPUC.

PG&E completed its last RAM RFO with one 20MW project awarded to a First Solar project in the Tehachapi area.

This picture below shows the locations of the submissions into this final RAM RFO of PG&E.  There were 27 viable large solar projects in CA that are at the Phase II or Interconnection agreement stage and therefore eligible for bidding in the RFO.

 

 Solar Investment Due Diligence | Solar Farm Technology California

 

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Community Solar Has Great Growth Potential

One solar sector that has the potential for significant growth in the 2017 -2018 time frame is “Community Solar” in select states in the U.S.  According to a recent Green Tech Media report while there are only 80MWs of community solar projects in operation there are 2.5GWs of projects in the development pipeline.  There is however a very select number of states that have the regulatory processes and utility commission approvals of viable programs where this activity will be concentrated.  Those states are:

  • Massachusetts
  • Minnesota
  • Colorado
  • New York
  • Maryland

It is also true that the promise of “Utility Scale” Community Solar(i.e. 10MW or greater) is not developing due to the requirement in most instances of a least one large corporate customer to account for 40%-50% of the output of the solar project.

Rural Electric Co-ops account for the largest number of programs online and in development, but the small customer bases limit the scale of these programs.

Navigating the specific regulations of each state, city, and program takes dedicated effort to succeed in this exciting growth segment for solar.

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Utilities Move to Cluster Process For Most Distributed Generation Connections

With the recent change in Rule 21 the CA IOUs have been allowed to move most previously approved Independent Study Process applications into a twice a year cluster study process.  It is called the Distribution Group Study Process and happens in September and March of each year.

You can see the outline of the proposals in this presentation by the IOUs.

Rule 21_Webinar_Slides

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The Williamson Act: Agricultural Land Conservation and Solar Development (Update)

The California Department of Conservation has issued an updated position paper on the Williamson act called, “Considerations in Citing Solar Facilities on Land Enrolled in the Williamson Act”. This provides suggestions to cities and counties for permitting solar development on agricultural land under contract in the California Land Conservation Act.

Among the suggestions made in the paper have to do with solar compatibility to underlying agricultural uses. A positive compatibility determination can be made under the following conditions:

Certain non‐agricultural uses, including solar power generation, may be compatible with an underlying agricultural use. The Williamson Act provides three general circumstances when a solar power generation facility may be found compatible. First, a solar power generation facility may be a compatible use as an“electrical facility” when located on non‐contracted land within an agricultural preserve. Second, a Solar investment professionals on contracted land may be a compatible use if it meets the “principles of compatibility” as set forth in Government Code Section 51238.1(a). Whether a proposed solar installation is compatible with the underlying agricultural use of the land depends almost entirely on the specific circumstances. The statutory test directs cities and counties to look at the degree to which the proposed project would significantly interfere with the underlying agricultural operation. If a proposed solar project would displace or impair only a very small percentage of the current or reasonably foreseeable agricultural operations on the subject contracted parcel or parcels, then the local jurisdiction could find that the solar panels would not reach the level of significant displacement and therefore be an allowed use.

Finally, under specific circumstances, a solar power generation facility may be approved by a city or county even if it is inconsistent with the principles of compatibility if: (1) the proposed site is located on non‐prime land; (2) the proposed site is approved pursuant to a conditional use permit; and (3) the following four findings are made, based on substantial evidence in the record:

1) The conditional use permit requires mitigation or avoidance of onsite and offsite impacts to agricultural operations.

2) The productive capability of the subject land has been considered as well as the extent to which the solar power generation facility may displace or impair agricultural operations.

3) The Solar Farm Design California  is consistent with the purposes of the Williamson Act, to preserve agricultural and open‐space land, or supports the continuation of agricultural uses, or the use or conservation of natural resources, n the contracted parcel or on other parcels in the agricultural preserve.

4) The solar power generation facility does not include a residential subdivision.

The entire white paper may be downloaded here: http://www.conservation.ca.gov/dlrp/lca/Pages/Index.aspx “Considerations in Siting Solar Facilities on Land Enrolled in the Williamson Act”.

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Solar Project Permitting Trends in California

When local cities and counties are presented with a new planning issue, such as the proliferation of new solar projects, the first thing the agency director does is asks his staff to call other cities and counties and see how they are dealing with that issue. They talk with other agency staff and they get copies of ordinances and plans. As a former staff person I didn’t care for this process as it circumvented the staffs own creativity and skills. But city council’s like to know that they aren’t walking in new territory alone so borrowing processes from other agencies is the local government method of choice when developing new ordinances.

It isn’t surprising then that we are starting to see consistent trends across California relative to how new solar projects are permitted. Some of these new permitting process can help speed up the approval process but only if the applicant understands how to best prepare their application and how to document their projects benefits and differences.

The major trends are: 1) the perceived loss of agricultural land to solar projects and the payment of fees to compensate the county for these loses; 2) The perception of solar projects being temporary uses and not permanent uses; 3) The use of reclamation plans and the payment of reclamation fees for the future decommissioning of solar sites, and; 4) the use of development agreements (DA) in permitting new sites. By managing these new processes one can often negotiate a faster environmental review process for their project.

Preparing reclamation plans takes special care and experience in both solar project development and reclamation planning as an ill-conceived plan could end up costing a lot of money and affecting the bankability of one’s project. Similarly, development agreements need an awareness of how to write conditions of approval in a way that allows project flexibility while keeping costs to a minimum. Development agreements need the engagement of an experienced solar permitting planner, a good financial modeler, and an experienced lawyer. One cautionary point about development agreements and controversial projects- DA’s are legislative actions and can be subject to initiatives, unlike use permits and other quasi-judicial actions. There are certain options to development agreements that can be discussed with local jurisdictions if you are concerned about project opponents taking ballot action against your project in the future.

Every jurisdiction is still requiring use permits and environmental review of each new project and these new permitting trends are add-ons to the existing permit approval process. The permitting process now requires looking years ahead towards the end of the project development cycle. While many landowners have some permitting experience in their local jurisdiction, these new permitting trends require the consultation of persons who understand solar technology, knows  how to permit solar for new construction, knows the costs associated with operating a solar facility, and has a clear idea of how the project can best be terminated and the site used beyond termination.

Solar Investment Professionals | Solar Farm Technology California

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New California Governor Jerry Brown Calls for Feed-in Tariffs to Develop Distributed Generation

January 3, 2011 by Paul Gipe

In an undated posting on Governor Jerry Brown’s campaign web site, the then candidate called for building 12,000 MW of distributed generation out of 20,000 MW of new renewable generation.

Governor Brown specifically calls on the legislature to introduce feed-in tariffs to accomplish this task.
Brown’s position on distributed generation and feed-in tariffs is the most ambitious–and the most specific–of any sitting US Governor.

California has lagged far behind other US states since Brown’s previous tenure as Governor in the early 1980s. At best California produces two percent of its electricity with wind energy and less than one percent from solar energy. Several Midwestern states generate more than seven percent of their electricity with new renewables, mostly wind energy.

12,000 MW of new distributed renewables could produce 15-25 TWh of generation, or about 5%-8% of current consumption. Total new renewables proposed by Brown could generate 30-40 TWh per year for about 10%-13% of consumption.

Below is an excerpt from Brown’s campaign web site titled Jobs for California’s Future. In the campaign’s vernacular, distributed generation is called Localized Electricity Generation.

“My goal is that by 2020, California should produce 20,000 new megawatts (MW) of renewable electricity, and also accelerate the development of energy storage capacity. California can do this by aggressively developing renewables at all levels: small, onsite residential and business systems; intermediate-sized energy systems close to existing consumer loads and transmission lines; and large scale wind, solar and geothermal energy systems. At the same time, California should take bold steps to increase energy efficiency.

“Below is my plan to get us there. It will produce a half a million new jobs in research, development, manufacturing, construction, installation, and maintenance over the next decade.

“1. Build 12,000 MWs of Localized Electricity Generation
California should develop 12,000 megawatts of localized energy by 2020. Localized energy is onsite or small energy systems located close to where energy is consumed that can be constructed quickly (without new transmission lines) and typically without any environmental impact.

Solar systems of up to 2 megawatts should be installed on the roofs of warehouses, parking lot structures, schools, and other commercial buildings throughout the state.

Solar energy projects up to 20 megawatts in size should be built on public and private property throughout the state. For example, we should create the California Solar Highway by placing solar panels alongside our state highways.

The California Public Utilities Commission (CPUC) or Legislature should implement a system of carefully calibrated renewable power payments (commonly called feed in tariffs) for distributed generation projects up to 20 megawatts in size. Holding down overall rates must be part of the design.”

-Paul Gipe

Solar Investment Due Diligence | Solar Farm Business Plan

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2011 CAISO Interconnection (GIP – Generator Interconnection Proceedure) Requests Must Meet March Deadline

During 2010 all of the previous interconnection rules, procedures, fees, and timelines for completing these agreements have been massively changed for solar PV farms in California. Starting first in the spring was the CAISO collapse of separate interconnection rules for small (SGIP) and large (LGIP) solar facilities on the transmission line systems of the utilities into one inclusive “cluster” process. The serial and much simpler SGIP rules were basically abandoned because of utility concerns for being swamped with applications that had overlapping system reliability concerns being studied in isolation of one another. Indeed the CAISO transmission, SCE WDAT, and PG&E WDAT interconnection queues have exploded during 2010. Late in the fall the three utilities abandoned their WDAT distribution connection rules and moved, in unison, to a “cluster” process .

What this means is that the old serial study of individual projects at specific sites is now gone forever into a study process that puts your project into a system upgrade study process with all projects in the same region of the utility system. There are subtle exceptions such as a proposed Independent Study Process or a Fast Track Process that may be viable for smaller projects, but in general the rules are much more complicated and costly to navigate for a solar farm developer.

With some reading of the massive new rules it becomes apparent that your 2011 project trying to get an interconnection agreement in some finite time MUST be placed into the cluster #4 application group that closes by the end of March 2011. If you miss this window then you may wait until the late fall for another possible opening. Of course by then your possible connection site will already be over the capacity allocation limit for a reasonable interconnection charge and you will get a nice large system upgrade bill over a year later than the first group.

The time is now to work with Solar Land Partners to understand these new realities and to make this looming deadline for both transmission and distribution applications for 2011.

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Distributed Generation Market Drivers

Distributed Generation Market Drivers

Important Legislative Market Drivers:

  1. Greenhouse Gas legislation that requires cities and businesses to reduce fossil fuel use.

  2. Renewable Portfolio Standard (RPS) requires utilities to produce 33% of their energy with renewable energy by 2020.

  3. Distributed Generation-providing energy at the load. Not tied to transmission lines.

  4. 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.

  5. 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.

RPS Legislation

  1. 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 .

  2. 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.

  3. 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

  1. 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.

  2. Source, California Energy Commission

Distributed Generation

  1. 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

  1. 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 and solar farm design California.

  2. 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.

  3. 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.

  4. 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.

Environmental Issues

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 for solar investment professionals.

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.

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Land Use and Utility Scale Solar Projects

Utility-Scale Generation

Almost all of the nation’s electricity supply comes from central generation technologies, also known as “utility-scale” generation. This model generates a large amount of electricity inexpensively at a central power plant and transmits the power to users through a network of transmission cables—the grid. The difference today is that most of the existing utility scale generation is done with fossil fuels such as coal or natural gas. New to this energy mix are utility scale solar generation facilities.The land use issues associated with utility scale solar projects differ from those of traditional energy generation projects The major difference between the two types of generation facilities is that fossil fuel generation facilities require large land areas for their mining and transportation,  which makes their overall impact far more destructive than the siting of solar business plan facilities.

Some utility-scale renewable energy plants have a larger footprint than coal or natural gas plants, as seen in the graphic below. However, it is important to note that unlike fossil fuels, solar energy does not require the use of additional land for extraction, refining, and transportation of the fuel inputs. One estimate (2) finds that in total over a 30-year period, a surface coal mine will use 21,844 acres of land while an average wind array will use 4,720 acres to produce the same amount of power. But even though the land occupied by wind turbines can be used for other purposes such as farming and ranching, it still has a large and possibly fragmenting impact as generating facilities are spread across a large area.

Because of the land-use requirements and impacts of utility-scale generation, efforts to meet our energy needs and combat climate change should prioritize conservation, efficiency, and solar power generation as much as possible. If state and national greenhouse gas reduction goals are to be reached, utility-scale solar energy generation must be a part of the energy mix as well.

Nevertheless, environmental impacts associated with utility solar investment due diligence are factored into siting decisions both by state agencies- as in the case of CSP projects that use water-and with local jurisdictions during the conditional use permit process. During the permitting of solar energy projects the local jurisdiction looks at water use, the extent and timing of land/surface disturbance, and of possible habitat and endangered species impacts. By using best management practices most of these issues can be mitigated and the natural landscape maintained, or these issues can be mitigated by proper site selection. But permitting agencies need to understand that by approving utility scale solar projects there will be fewer local and regional land use impacts then if they approved a conventional energy facility. The jurisdiction needs to look at all associated regional impacts from a facility and not just the issues generated at the project site.

Future Energy Generation

New interconnection rules in California are encouraging utility scale projects less than 5 MW. And the California Public Utilities Commission will soon create a feed-in tariff pursuant to SB32. SB 32 encourages 1-3 MW size solar projects by offering developers a higher tariff rate then standard utility purchase agreements. SB32 requires that California utilities provide 750 MW SB 32 of capacity. That is 250 separate project sites.

According to IMS Research, the utility-scale market is set to surge in 2011, and is estimated to grow five times faster than the rest of the industry.

With the approval of these projects and with the demand for utility scale projects growing rapidly, solar developers will be called on to develop best management practices to mitigate any land use impacts associated with solar development. But during the course of their permitting process solar developers need to educate the local permitting staff about the true regional impacts of fossil fuel energy facilities and on the long term environmental benefits utility scale solar provides their community.

1 SolarBuzz. “Distributed Power Generation: compare solar energy with alternative energy sources.” http://www.solarbuzz.com/DistributedGeneration.htm

2  Gipe, Paul. Wind Energy Comes of Age. John Wiley and Sons: 1995. page 395

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