Tag Archives: Demand Response

Opinion: An uncertain path to a cleaner future – Zero carbon electricity legislation in New York and California

By Thomas R. Brill & Steven C. Russo (Greenberg Traurig), Utility Dive

Last month, New York passed the Climate Leadership and Community Protection Act, which calls for a carbon free electricity market by 2040. With passage of this law, New York became the sixth state to pass legislation calling for a carbon free electricity market. Just one year earlier, California passed similar legislation, SB100, adopting a state policy to achieve a zero-carbon electricity market by 2045.

These goals will have to be pursued notwithstanding the fact demand for electricity is projected to increase as other sectors pursue beneficial electrification to comply with ambitious emission reduction goals they face. Whether these goals can be achieved, and at what cost, will depend on technology advancements and how these laws are interpreted and implemented by regulators.

New York’s Climate Leadership and Community Protection Act requires 70% of electricity consumed in New York be generated by renewable resources by 2030 and the state must be carbon free by 2040. California’s SB100 requires 60% of electricity come from renewable resources by 2030 and adopts a state policy of a 100% zero carbon electricity by 2045.

The New York legislation explicitly conditions meeting these extraordinarily ambitious renewable energy mandates on maintaining reliability and affordability. This leads to obvious questions: Can a zero-carbon electricity market be achieved in a manner that maintains reliability and affordability, and if so, how? What flexibility exists under these laws to ensure these emission reduction goals can be achieved even if new technologies or significant price declines fail to materialize?

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California Has Too Much Solar Power — And That’s a Good Thing

By Travis Hoium, The Motley Fool

No business wants to create a solution in search of a problem, particularly in the slow-changing energy industry. Instead, businesses want to find solutions for problems that exist and create ways to make money off their solutions.

Enter the exigent problem California is facing: it has too much solar energy. First, who thought that would be a problem in the country’s largest state? Second, why isn’t there a solution if utilities and regulators knew this problem was coming? The short answer is that energy innovators weren’t going to create and install solutions for solar energy’s variability until they knew the utilities and regulators had recognized the problem.

California has made a big push into renewable energy in an effort to meet a 50% renewable energy goal by 2030. It’s built wind and solar plants rapidly over the past decade, which combines with hydropower to provide clean energy to the state. The problem is that solar energy, in particular, isn’t created evenly throughout the day or year and that’s a challenge for the grid.

In March, before peak air conditioner season in the state, there was so much solar energy on the grid that the California Independent System Operator had to tell some solar farms to shut down because there was too much energy for the grid to handle. And that could lead to a blackout.

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Energy Storage: Power Revolution

By Peter Fairley, Nature

It is 2025 and another sweltering summer’s day in California. Millions of solar panels are soaking up the Sun’s rays to power the air-conditioning systems that keep homes and offices throughout the state cool. The devices are working efficiently thanks to an intelligent conversation taking place between the appliances and the electrical grid. As clouds drift across the Sun, casting shadows, the air conditioners deftly increase or decrease their output in sync with the varying flow of solar energy. In areas where the demand for electricity looks as though it will overload the power-transmission lines, home air-conditioning units take it in turns to go offline for an hour. In other areas, where solar power threatens to exceed demand, hot-water heaters are turned on to absorb the extra energy.

This imagined future power grid demonstrates the same degree of flexibility that energy-storage advocates predict will occur with the widespread implementation of batteries, but there is no electrochemistry involved — software manipulates energy-consuming equipment so that most electricity is used when it is most abundant, cheap or green.

The concept is called ‘demand dispatch’, because it would activate and deactivate power demand — much as grid operators dynamically dispatch electricity generated by power plants today. In the future, power grids will probably use both the ‘virtual storage’ created by demand dispatch and the true energy storage from batteries. But demand dispatch could be the bigger player of the two, with smart use of existing appliances offering a smaller environmental footprint and slimmer price tag than batteries.

Read full article in Nature

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.

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

Inside SoCal Edison’s Plan to Open Its Grid to Distributed Energy

By Jeff St. John, Greentech Media

Two years ago, California told its three big investor-owned utilities to do something they’ve never done before — make distributed energy resources (DERs for short) a fundamental part of their billion-dollar distribution grid investment plans.

Under state law AB 327, Southern California Edison, Pacific Gas & Electric and San Diego Gas & Electric were tasked with finding a way to integrate solar PV, behind-the-meter batteries, electric vehicle chargers, building energy management systems, and other distributed energy resources into a new set of distribution resource plans (DRPs). The DRP planning process has been the subject of much debate and scrutiny over the past year, because they have profound implications for how rooftop PV installers, energy storage developers, demand response providers and other third-party DER companies will do business in the state.

Now, with Wednesday’s deadline for utilities to file their plans with the CPUC, the wait is over — and we’ve got details on how one utility is putting its grid-edge plan together. This week, Southern California Edison shared some fundamental features of its DRP, including some new software tools and methodologies to assess distribution grid capacity, the way it plans to assess the costs and benefits of DERs for its upcoming rate case, and new pilot projects to test these propositions in the real world.

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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

Inside the Minds of Regulators: How Different States Are Dealing With Distributed Energy

By Julia Pyper, Greentech Media

With distributed generation steadily rising and creeping into new states, electricity regulators in each region of the U.S. are dealing with change very differently. Regulatory officials from California, Texas, Minnesota and Arizona discussed how they’re addressing some of the most pressing issues in their service territories this week at the National Town Meeting on Demand Response and Smart Grid in Washington, D.C.

California: California is the national leader in the deployment of solar PV, plug-in electric vehicles, grid-scale energy storage and home automation technologies. Today, about 20 percent of the state’s electricity comes from renewable energy, putting California on track to meet its 33 percent renewable energy target by 2020.

But while the Golden State continues to come up with new ways to promote and integrate advanced energy technologies, the focus will shift from renewables in the coming years, said Michael Picker, president of the California Public Utilities Commission.

“We’re moving away from a technology-based discussion to [a discussion of] grid values — what does the grid need, what do customers need?” he said. “And we will probably move away from a focus on renewables per se as a series of technologies, to a series of metrics on reducing greenhouse gas emissions.” Picker added that this shift away from individual technologies toward holistic grid solutions will reinforce a convergence between traditional electric utilities, the transportation industry, the natural gas industry and all types of distributed energy resources (DERs).

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