Tag Archives: Rooftop Solar

Renewable energy bill far from perfect, experts say

By Sammy Roth, The Desert Sun

With one week until California’s Legislature closes shop for the year, lawmakers are scrambling to pass an ambitious climate and energy plan. At stake are several top priorities for Gov. Jerry Brown: a 50 percent cut in oil use, a 50 percent increase in energy efficiency in existing buildings, and a 50 percent clean energy mandate.  Some version of the bill will almost certainly pass, despite opposition from the oil industry and centrist Democrats.

There has been little formidable opposition to the clean energy mandate, which is expected to jump-start solar and wind development in the desert and across the state. But for some clean energy experts, the bill leaves a lot to be desired. Critics say the bill doesn’t do enough to promote clean energy sources that can generate electricity around the clock, including geothermal, biomass and solar with storage. They say adding those kinds of power sources to the mix—rather than continuing to focus almost exclusively on traditional solar farms and wind turbines, which can’t provide power around the clock—is needed to keep electricity costs down for homes and businesses, while limiting the carbon pollution. Anything could change before next Friday. But for now, some critics see the bill as a missed opportunity to limit global warming while keeping electricity costs as low as possible.

Building more clean energy will almost certainly lead to higher electricity prices, but the exact costs of transitioning to clean energy are still up in the air. Under California’s current renewable energy mandate—which requires utility companies to buy the cheapest power on the market—utilities have largely opted for traditional solar and wind farms, because they have the lowest up-front costs. Clean energy sources that provide electricity around the clock—like geothermal and solar with storage—typically have higher up-front costs. SB 350 mostly leaves that system in place, but it would instruct utility regulators to consider the benefits of round-the-clock clean energy sources, such as rooftop solar with storage.

Read full article in the Desert Sun

8 Facts That Explain SDG&E’s Complicated Relationship With Rooftop Solar

By Lisa Halverstadt, Voice of San Diego

Despite San Diego’s reputation as a solar mecca, San Diego Gas & Electric and the rooftop solar industry are consistently at odds.

In some ways, the game is rigged for these two to be foes: Rooftop solar has grown rapidly with the help of incentives and mandates, forcing SDG&E to integrate it. State requirements have ensured disagreements between the two play out publicly at the statehouse and at the Public Utilities Commission.

SDG&E has long argued, for example, that solar customers aren’t paying their fair share for use of the power grid, an argument being pushed by utilities across the nation. The solar industry and its supporters say SDG&E’s missing the big picture and discounting the value of rooftop solar, which allows everyday San Diegans to help the region reduce its greenhouse gas emissions. That’s far from the only dispute, though.

Here’s a breakdown of the realities contributing to SDG&E’s strained relationship with the solar industry…

Read full article from Voice of San Diego

California’s Solar Industry Fights Back on Net Metering 2.0

By Jeff St. John, Greentech Media

California’s biggest utilities want future net-metered rooftop solar systems to earn less for the energy they feed to the grid and solar customers to pay extra charges to cover the costs of serving them grid power.  California’s solar industry has a different idea: keep things the way they are — and don’t believe utilities when they say they and their non-solar customers can’t afford it.

In filings this week, key solar groups The Alliance for Solar Choice (TASC), the Solar Energy Industries Association (SEIA) and Vote Solar have asked the California Public Utilities Commission to retain key features of the state’s net metering regime, including full retail payments for the power that rooftop solar systems feed back to the grid. That’s in stark contrast to proposals from the state’s three large investor-owned utilities, which ask the CPUC to lower payments, impose new charges, and make other changes that would reduce the economic payback of future net-metered solar systems. Utilities say that today’s net-metering regime unfairly slants compensation toward rooftop solar and will impose billions of dollars of cost shifts to non-solar customers if not changed.

Read full article from Greentech Media

California Decision Means Rooftop Solar Owners Have Choices

By Amanda H. Miller, CleanEnergyAuthority.com

A new California regulation that allows companies to package energy from small producers and sell it on the wholesale market is good news for the long-term viability of rooftop solar.

As utilities push back against paying the full retail rate for the power solar customers feed onto the grid, some expect the popularity of rooftop solar to wane. News outlets this week have noted that the meteoric rise of rooftop solar could slow when the 30 percent national investment tax credit declines in 2016 and as utilities reduce net metering payments.

But the cost of solar panels has continued to decline and business innovators have continued to come up with creative new ways to make solar affordable. So, just as utility companies prepare to reduce net metering benefits, private industry swoops in with a viable solution that could keep the rooftop solar industry growing 50 percent a year in California.

Read full article from CleanEnergyAuthority.com

The Solar Industry Stands Divided Over California’s 50% Renewable Energy Target

By Julia Pyper, Greentech Media

These days, it’s rare to see rooftop solar installers and investor-owned utilities aligned on state policy issues. But in California, the two industry groups are both lobbying for behind-the-meter solar to count toward the state’s expanded renewable portfolio standard.

SB 350, the “Clean Energy and Pollution Reduction Act of 2015,” seeks to increase the state’s renewable energy target from 33 percent by 2020, to 50 percent by 2030. It also calls for cutting petroleum use in the transportation sector by half, and doubling the energy efficiency of buildings over the next 15 years. The bill has already passed the California Senate, and is now making its way through the Assembly.

One of the issues both utilities and solar installers have raised is that distributed solar should not be treated any differently than utility-scale solar as the state crafts the rules around meeting the new 50 percent target. As the RPS stands today, California utilities are only required to buy energy and renewable energy credits (RECs) from utility-scale solar plants. California is the only state in the country that does not count distributed solar toward the state’s RPS goal, either through a distributed generation carve-out or by generating RECs.

In letters to the Assembly Committee on Utilities and Commerce, Southern California Edison and PG&E argue that “state policy should not pick technology winners and losers, favoring only utility-scale renewables,” and call on the legislature to “expand the scope of eligible renewable resources to include distributed generation facilities such as rooftop solar that the state already acknowledges are renewable, yet do not count toward the RPS goal.” This change would give utilities more ways to meet the lofty 50 percent RPS goal. It would also give them a potentially more affordable way to meet the goal by leveraging existing and future private investment toward meeting the RPS, rather than necessarily having to contract for new large-scale projects using ratepayer dollars.

The issue has made strange bedfellows of power companies and rooftop solar installers, which have clashed in several states over the future of net energy metering. Meanwhile, it has pitted rooftop solar companies against large-scale solar installers, which are actively lobbying against the RPS change.

Read full article from Greentech Media

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Southern California Edison To Buy Solar Energy From Borrego PV Projects

Southern California Edison (SCE) has signed power purchase agreements (PPA) with Borrego Solar Systems for the electricity generated from rooftop wholesale distributed generation (WDG) projects.

Under the five 20-year PPAs, SCE will purchase 10MW solar photovoltaic (PV) capacity from the WDG projects which Borrego Solar plans to build. The systems will be located on industrial warehouse buildings in Southern California.

These projects are part of SCE’s fourth solicitation under the Solar Photovoltaic Program (SPVP) for Independent Power Producers, a five-year program to procure 125 MW of primarily rooftop PV projects. These new PPAs will bring Borrego Solar’s total participation in the program to nine projects totaling 17 MW. Once fully operational, the Borrego Solar portfolio will generate enough energy to power approximately 3,672 homes.

Read full article from Energy Business Review

California’s Distributed Energy Grid Plans: The Next Steps

By Jeff St. John, Greentech Media

Last week, after a year of behind-the-scenes work and much public debate, California’s big three investor-owned utilities turned in their long-awaited distribution resource plans (DRPs). These DRPs are essentially blueprints for how Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric are going to merge rooftop solar, behind-the-meter energy storage, plug-in electric vehicles and other distributed energy resources (DERs) into their day-to-day grid operations and long-range distribution grid planning and investment regimes.

Each California utility has created mapping tools that show how much capacity is available on each distribution circuit for new DER interconnection, for instance — something that could be very useful for distributed energy developers. All three utilities have also agreed on a common set of measures for how DERs could help shore up grid capacity, increase reliability, serve system-wide needs, and otherwise stand in for costly utility upgrades. And each has laid out how it plans to fold these DRP methodologies into their general rate cases (GRCs), the once-every-three-years process that determines how much each can charge its customers for its capital and operating costs for the coming years.

Many questions remain about how to determine which combination of DERs will meet the least-cost models that utilities use to rank their distribution grid upgrades, and what kinds of new capabilities grid-supporting DERs will need to have to serve as replacements for utility investments. There’s also much uncertainty about how DERs serving as stand-ins for grid infrastructure should be paid for, and how their costs and benefits should be shared. These issues are of major interest for solar-storage combinations from SolarCity and Tesla, SunEdison and Green Charge Networks, Sungevity and Sonnenbatterie, and SunPower and partners Stem and Sunverge, which see an opportunity for earning grid services revenues as stand-ins for distribution grid investments. They’re also important for the commercial building and residential energy management platform providers looking for ways to tap California’s emerging opportunities for distributed demand response.

These costs and values wouldn’t just flow from utilities and their customers to DER providers—each utility’s DRP asks the California Public Utilities Commission (CPUC) for permission to spend lots of money on beefing up their own systems to enable their visions. Southern California Edison alone is estimating its DRP-related capital expenditures could add up to $347 million to $560 million over the next three years, for example, and PG&E and SDG&E will also be seeking new funding, though they haven’t yet specified how much.

All three DRPs add up to nearly 1,000 pages, which makes it hard to summarize all the next steps they contain, but here are a few highlights of the challenges to come.

Read full article from Greentech Media

Related articles: How California’s biggest utilities plan to integrate distributed resources (Utility Dive)

Inside the nation’s first renewables-plus-storage microgrid

By Robert Walton, Utility Dive

Borrego Springs, California, sits less than 100 miles from San Diego, but in terms of electric reliability the two places were once worlds apart. San Diego Gas & Electric serves 3.4 million consumers with 1.4 million electric meters in its territory. And last year – for the ninth consecutive year – it was named the most reliable Western utility by PA Consulting Group.  But if you lived in Borrego Springs, an isolated desert community surrounded by a state park, your utility experience was markedly different.

“That area has seen outages over the years, some lasting days on end,” according to Jim Avery, SDG&E’s chief development officer. “Borrego Springs is served by one radial transmission line traversing 60 miles of exposure. It is susceptible to wildfires, windstorms, flooding and hail.” After wildfires knocked out power to the area in 2007 for two days, the utility took a hard look at how to better supply residents and businesses. About 2,800 people live in the community, which is entirely surrounded by Anza-Borrego State Park, the largest park in California.

“As a result of the wildfires, we decided we were going to rethink the way we served communities such as Borrego Springs,” Avery said. “We started our quest for designing a fully-integrated microgrid, one that could integrate conventional sources of generation, renewable sources, such as rooftop solar, as well as substation and utility-scale solar.” The system also includes distributed energy storage and batteries located at substations. With the help of $8 million from the U.S. Department of Energy, “we’ve gone through an evolution in the last seven years towards building that ultimate microgrid,” Avery said. “And we’ve had some opportunities to test it under different conditions.”

The grid was used to avoid some smaller outages, and then earlier this year the California Energy Commission awarded the utility a $5 million grant to expand, allowing it to interconnect with the nearby 26-MW Borrego Springs solar facility.

In late spring, major flooding did damage to SDG&E’s transmission corridor – potentially leaving customers in the dark again. Historically, that would have meant a 10-hour outage as the utility rebuilt the poles. “We would have had customers out of service for almost an entire day,” Avery said. “But because the microgrid was up and running we were able to switch over all of our customers to be fed by the rooftop solar systems scattered out in the community, in addition the large-scale solar, and it was all balanced by the batteries located on the distribution line and at our substations.” Borrego Springs’ peak load is about 14 MW, and rooftop plus utility-scale solar give the community about 30 MW of generation. The batteries can store about 1.5 MW.

Borrego Springs isn’t the only microgrid out there, of course. It’s not even the only one operated by SDG&E, which has a few other grids in place for voltage regulation. But, according to Avery, it is the first of its kind to power an entire community with renewable energy.

Read full article from Utility Dive

US Solar Electricity Production 50% Higher Than Previously Thought

By Jason Kaminsky (kWh Analytics) & Justin Baca (Solar Energy Industry Association), Greentech Media

Renewable energy’s share of our overall energy mix is at the highest level in over 70 years — even with the drought-induced decline in Western hydropower output.

In California, increasing solar power generation made up for the shortfall in hydropower production. In fact, solar production was up so much that California became the first state to get more that 5 percent of its electricity from utility solar. This dramatic growth in solar generation has driven the California Independent System Operator (CAISO) to make a regular habit of reporting record solar outputs as more and more plants come on-line. But while solar electricity produced on the utility side (wholesale) of the meter is easily counted by these agencies, they don’t count distributed generation — the smaller systems located on rooftops — which represents a huge portion of solar generation.

In an effort to provide a more complete estimate of solar generation in the U.S., SEIA and kWh Analytics completed an analysis of U.S. solar production, including previously uncounted generation from behind-the-meter systems. The results were astonishing: we estimate that actual solar production is 50 percent higher than the previous best estimates of solar production. In the 12 months ending in March, solar energy systems in the U.S. generated 30.4 MWh of electricity. The Energy Information Administration’s utility-only estimate for the same period is 20.2 million MWh.

Read full article from Greentech Media

How California plans to integrate distributed resources into its ISO market

By Herman K. Trabish, Utility Dive

A new era of grid operations is about to begin in California.

The state’s grid operator is preparing to offer aggregators of distributed energy resources (DERs) the opportunity to sell into its marketplace, the first in the nation to do so. DERs are the resources on the customer side or the distribution grid side of the electric system, such as rooftop solar, energy storage, plug-in electric vehicles, and demand response, and are typically below the 500 kW minimum size required to sell into the ISO system.

CAISO’s Final Plan

The “straw proposal,” an early draft of the ISO’s DERP initiative, was published last November to give stakeholders an opportunity to comment.  The final draft of the ISO’s plan answers many of the stakeholder concerns, with a focus on details of expanded metering and telemetry, the communications and counting methods, and the technologies the grid operator will need.

DER Aggregation

The ISO’s proposal provides a framework for the aggregation of DER to meet the ISO’s 0.5 MW minimum participation requirement and participate in ISO wholesale markets as an aggregated resource. The ISO proposes to classify a distributed energy resource provider or “DERP” as the owner/operator of one or more aggregations of individual distributed energy resources2 (DER) that participate in the ISO market as an aggregate resource rather than as individual resources.

Metering

In today’s California market, all of CAISO’s centralized generators have a resource identity (resource ID) and are required to have “revenue quality metering.” That can be via a direct interaction between the ISO and the resource ID, or it can be through a scheduling coordinator that mediates between the ISO and the resource ID. But for distributed resources, assigning a resource ID to each one is not feasible.

The proposal allows a scheduling coordinator to take administrative control of aggregated distributed energy accounts and meter them with any technology, including any online technology, that suits their purposes. The aggregator can be its own scheduling coordinator or can hire a third-party. A directly connected interface between the ISO and the aggregator is no longer required.

Locational dispersion and capacity of DERP aggregations

There are some 4,900 market pricing nodes (PNodes) on the ISO system. The system is also divided into load aggregation points (LAPs) that follow the territories of the state’s three investor-owned utilities. They are subdivided into sub-LAPs. With the issue of counting the DERPs clarified, the proposal takes up the question of how the ISO can keep track of the multiple sources and types and locations of DERs with which it will have to deal.

Under the new proposal, DERP aggregations may consist of one or more sub-resources at single or multiple locations. There can be multiple small resources across multiple PNodes, but they must be within one sub-LAP.  There is no minimum size limitation on the individual sub-resources in a DERP aggregation. This means that individual sub-resources may exceed the ISO’s minimum participation requirement of 0.5 MW. DERP aggregations across multiple PNodes may not exceed 20 MW, but for DERP aggregations limited to a single PNode, there is no MW size limitation.

Mixing DERs

For DERP aggregations limited to a single PNode, the sub-resources may be heterogeneous – that is, a mixture of sub-resource types is permitted, and there is no MW size limitation. It is not required that all of the sub-resources move in the same direction, only that the net movement of the aggregate of the sub-resources equate to the ISO dispatch instruction.

DERP aggregations across multiple PNodes may not exceed 20 MW. For DERP aggregations across multiple PNodes, all sub-resources within that sub-LAP must be homogenous and must move in the same direction as the ISO dispatch instruction. Homogenous aggregations are those in which all sub-resources are generation, energy storage acting together in charge or discharge only, or are load. For aggregations of energy storage, all sub-resources must be operating in the same mode (i.e., charging or discharging, but not a mix of the two) in response to an ISO dispatch.

The ISO performs network analyses to make certain the system is receiving what the market is selling into it. Sub-resources in an aggregation across multiple PNodes can cause distribution variability. But the PNode distribution variability must be minimized or “the congestion impacts estimated in the network analysis will be off.”  Until the ISO has enough operational experience to know whether the distribution variability would be a problem, it wants to limit DER aggregations “to those that move in the same direction as the ISO dispatch instruction.”

This is especially relevant to aggregated solar-plus-storage technologies that might be producing both load and generation, the final draft acknowledges. “The ISO recognizes that there is great interest in aggregating mixtures of rooftop solar, energy storage, plug-in electric vehicles, and demand response across multiple PNodes, without all the limitations required in this proposal. The ISO plans to examine such options in subsequent initiatives.”

Wait ‘Til Next Year

Several stakeholders suggested provisions be made for demand response (DR) in aggregations of distributed resources, but the ISO chose to limit its role, and does not include demand response participating as Proxy Demand Resource (PDR) or Reliability Demand Response Resource (RDRR) in the DERP proposal. In the proposal, the ISO clarifies that demand response participating as PDR or RDRR would continue to participate under its existing demand response framework and not under the DERP framework. The ISO says the existing PDR and RDRR framework already provides for market participation of aggregated demand response. This existing framework is designed to accommodate load reducing resources whose performance is assessed under a baseline methodology.

Stakeholders also suggested including in the DERP final proposal both the alternative baselines for PDR, and the alignment between distribution level interconnection and the ISO New Resource Implementation process. They are part of a separate energy storage initiative. These suggestions were declined. To facilitate bringing aggregated DERs into its marketplace, the ISO wants to include initially only those that can be directly metered under the specified terms.

The ISO will take formal comments on the final draft through June 24th. If approved by the Board in mid-July, the ISO will probably file by early autumn with the Federal Energy Regulatory Commission. That approval will require at least 60 days.

Read full article in Utility Dive