by Jeff St. John
May 26, 2017

Last week’s Solar Summit 2017 featured a fair amount of talk about the role that California plays in opening its energy markets and grid financing structures to distributed energy resources, or DERs. California is arguably well ahead of New York in this effort, which makes sense, given that it has a lot more DERs -- and the most of any other state in the country.

California is also the first to create a tariff that will allow aggregated DERs -- solar, batteries, demand response and other forms of flexible energy assets -- to bid alongside generators and large-scale loads in its day-to-day energy markets. State grid operator CAISO has had its unfortunately named Distributed Energy Resource Provider (DERP) tariff structure approved by federal regulators, and DER developers are already lining up to aggregate and bid in assets coming this summer. 

California isn't alone in exploring how DERs can play a bigger role in the grid system. New York, a state that’s pushing the grid edge envelope with its Reforming the Energy Vision (REV) initiative, is on a similar path, but playing catch-up.

New York’s test of distributed energy as aggregated grid resource 

Earlier this month, New York state grid operator NYISO released a proposal for pilot projects that could demonstrate whether DERs can play a role in its wholesale markets -- an important step in the REV process. 

NYISO envisions pilots limited to between three and five individual projects, with a minimum of 100 kilowatts if demonstrating energy only, but 1 megawatt if demonstrating regulation or reserves. Individual projects are limited to 10 megawatts of capacity at a single transmission node. 

Unlike CAISO’s full-ahead integration of DERs into its operations environment coming this summer, NYISO’s pilots would be run in a test environment, and participants won’t actually be paid for any “energy injections, load reductions, or ancillary services” they provide. That’s because NYISO can’t pay anyone until it develops a new tariff for these new resources. 

Still, aggregators already participating in NYISO’s existing demand response programs are eligible for pilot projects, as long as that doesn’t interfere with their existing obligations. As for generators, NYISO is evaluating whether they can participate. Would-be participants have a while to plan -- the grid operator doesn’t envision opening applications until the fourth quarter of this year, with initial pilot projects selected by mid-2018. 

NYISO puts energy storage integration on the agenda

Energy storage is also part of NYISO’s pilot project roadmap. It and the rest of the country’s grid operators are under notice by the Federal Energy Regulatory Commission (FERC) that they should start incorporating batteries and other forms of energy storage into their markets. In a May 5 document, NYISO laid out how it plans to test new market structures to accomplish this. 

This program is for energy storage resources of 1 megawatt or larger, since anything smaller can go into its DER pilot. It will come in two tracks: Energy Storage Integration, starting this year, to develop the participation model for storage resources; and Energy Storage Optimization, starting in 2018, to develop an optimization methodology them as part of its overall resource mix. 

One of the list of things FERC has asked ISOs and RTOs to do is to allow for energy storage participation. NYISO’s pilot mainly targets the creation of “bidding parameters that reflect energy storage resource physical and operational characteristics.” To deal with the fact that energy storage acts both as a generator and a load, it’s planning to add bid parameters such as transition time -- how long a resource takes to switch between injection and withdrawal states -- and minimum generation and load requirements. 

California’s latest DER debate over iterative vs. streamlined grid mapping 

All of these aforementioned efforts are aimed at the integration of DERs into transmission grid-scale operations and markets. But there’s probably a lot more value for distributed energy down at the individual circuit, feeder and substation level, if only utilities that run those distribution grids had a way to calculate and compensate for it. 

Both California and New York are working on policies to reward these locational values for DERs, through the mechanism of utilities’ multibillion-dollar distribution grid investment plans. In California, the effort has taken shape in the form of the California Public Utilities Commission's Distribution Resources Plan (DRP) and Integrated Distributed Energy Resources (IDER) proceedings. In simple terms, the DRP deals with how to measure the costs and benefits of DERs for local grid infrastructure and operations, and the IDER deals with how to pay them for it. 

We’ve covered the nitty-gritty details of these proceedings, including some of the conflicts that have arisen between utilities and the solar, energy storage, demand response and energy efficiency industry groups interested in the outcome. For these groups, the DRP’s method of measuring grid capacity for DERs in terms of limits (its Integration Capacity Analysis) and the method of determining their positive values (its Locational Net Benefits Analysis) have been issues of contention. 

California investor-owned utilities have already released maps featuring data from their Integration Capacity Analysis (ICA) work, as a way of roughly guiding developers to parts of the grid that aren’t facing potential problems from additional DERs. But these maps are largely based on models, whereas the DRP envisions them incorporating real-world data -- a method that requires a lot more computation power, but yields more accurate results. 

One big conflict has arisen over how utilities should calculate their ICA limits, using the computation-heavy “iterative” method, or a simpler “streamlined” version. This week, utilities and solar and environmental groups weighed in on this issue, and not surprisingly, they’re not in agreement. 

PG&E’s filing, officially in response to the final report from an ICA-LNBA working group, disagreed with its recommendation to use the iterative methodology for online maps and interconnection processes. “PG&E prefers the streamlined methodology to streamline the interconnection process because...it is superior to the iterative process for the following reasons: a) Interconnection Process Speed and Efficiency, b) Accuracy and Effectiveness, and c) Costs.” 

But the California Solar Energy Industries Association (CalSEIA) warned in a filing this week that “if the ICA values are based on the streamlined methodology, there would be many cases in which DER providers use ICA data to match system design with hosting capacity only to be subject to lengthy interconnection review, system redesign, and costly upgrades. This could lead to a review process that is worse than the current process.” 

Going with an iterative approach, CalSEIA argues, will “provide data that enables DER providers to design systems that avoid the need for lengthy studies and costly distribution upgrades. This will save customers time and money, and will reduce the enormous amount of effort that utilities currently put into interconnection review.” 

Comparing and contrasting California's and New York's approaches to distributed energy

On a final California versus New York note, a new white paper by the Center for Sustainable Energy and UC Berkeley Energy & Resources Group has taken on the subject of how the two states’ distributed generation planning efforts compare. 

There’s some deep analysis and sourcing in the report, but the takeaways are that “California’s regulators focus heavily on the technical implications of DER deployment, while New York’s regulators, through REV, are undertaking a broader initiative that more directly incorporates the overall market structure and utilizes the policy context for encouraging more renewables in the state’s energy system.” It also notes the key structural differences between the two states, such as New York’s access to hydropower and still-low penetration of solar PV.

AMI as smartphone: Silver Spring and Itron expand developers networks

Turning to technology news, GTM Research’s latest AMI forecast projects that global smart meter installations are expected to reach 922 million by 2021. That’s a far cry from the 1.5 billion or so smartphones sold around the world just last year. But it’s still a lot of internet-of-things-enabled devices, with the latest generations coming with computing power and connectivity to accomplish many more tasks than just basic meter reading -- and smart metering companies are seeking applications developers to help expand these possibilities. 

Silver Spring Networks announced last week that it has expanded its IOT developer program, adding a new portal, kits and simulation tool to test out the latest apps for “sensors, actuators, devices and applications within the smart utility, smart city and industrial IOT sectors.” This is a nod to Silver Spring’s efforts to expand beyond networking smart meters. The company already has a big business in smart streetlights, and is working on traffic sensors, air quality monitors and other endpoints. 

Silver Spring’s name for its IOT platform is Starfish. Rival Itron has named its next-generation networking platform Itron Riva, and last week it also released its next-generation development platform, featuring a more compact design to help fit into streetlights, electric-vehicle charging stations and distribution automation gateways, and core inputs and outputs including GPIO, I2C, SPI, Serial, A/D and OTG USB for the industry’s most commonly used sensors. Like Silver Spring, Itron wants to be known as an IOT provider, and has started to link up with streetlights, sensors and EV chargers in pilot projects. 

NRG update: Bloomberg reports pressure for energy giant to sell off renewables 

We’re a long way from the days of David Crane. Earlier this month, Bloomberg reported that Princeton, N.J.-based NRG Energy is considering selling all of its renewable energy portfolio, under pressure from an investor. That would be a sharp turnaround for the multi-state generator and retail energy provider, which owns a huge share of wind and solar power, and in November bought 1,500 megawatts from bankrupt SunEdison

But Bloomberg reports that a panel formed by in February is reviewing a proposal to sell what constitutes up to a third of the company’s portfolio, including wind and solar projects it is developing on its own, as well as those run by its YieldCo, NRG Yield Inc.