by Jeff St. John
August 18, 2017

New York’s Reforming the Energy Vision initiative may appear to be moving slowly to the outside observer. But for the utilities, regulators and technology providers carrying it out, it’s innovation at a breathtaking pace.

After all, an ambitious overhaul of a state’s energy markets and utility grid operations and planning paradigms doesn’t happen overnight -- or without a few unforeseen roadblocks derailing a project or two. 

Greentech Media’s New York REV Future 2017 conference next month will bring together policymakers and utility and technology executives working on this statewide transformation. (And remember, all GTM Squared members get access to our live stream!)

To inform next month's discussion, we’ve pulled together utility updates, project descriptions, and other filings with the New York Public Service Commission under the REV proceeding, to get acquainted with what’s been, after an eventful spring, a relatively quiet summer.

Our team of analysts at GTM Research provided a good overview of the key accomplishments of REV this year, and what key questions remain to answer. These include whether or not the state will set an energy storage target, the status of the 17 REV demonstration projects ranging from virtual power plants to smart home energy portals, and how the state’s six big investor-owned utilities will start opening up more RFPs for non-wires alternatives -- DERs deployed in lieu of grid investments -- beyond the showcase Brooklyn Queens Demand Management project. 

The latest demo project reports reveal more challenges, like interdepartmental delays and technology integration challenges. Con Edison notified the PSC this spring that it was canceling its 4-megawatt-hour distributed solar-storage virtual power plant contract with SunPower and Sunverge, after it couldn’t reach agreement with state building officials and the NYC fire department on how to permit its behind-the-meter lithium-ion batteries. 

This summer also saw New York’s utilities unveil a bigger list of non-wires alternative projects they’re planning to put up for bid, as well as award a couple of contracts to relieve load in midtown Manhattan by 2021.

On the customer-facing side of things, utility-branded marketplaces are getting homeowners online to check their bills, buy LED light bulbs and smart thermostats, and in a few cases, get up-to-date energy data -- if they’re OK with the utility installing a special meter, since New York has just started to roll out smart meters. 

(A note to readers interested in reading the original documents: The PSC’s website doesn’t support direct linking very well, so if you want to read a particular filing, visit the PSC’s main REV docket page, find the title you're looking for, and click.) 

The DER demos: A long way from pilots to DSPs

Let’s start with the demonstration projects linked to REV’s overall vision of a medium- and low-voltage distribution grid that’s fully capable of managing DERs at mass scale and compensating them for their grid value. REV has come up with some key goals on this front.

First, each utility is creating a distributed system implementation plan (DSIP) to guide how DERs will fit into its ongoing grid planning and operations. Each utility filed a DSIP last year, and after the PSC demanded some more information in a March filing, the utilities refiled amended versions in May. 

Second, REV is asking each utility to work toward becoming a distributed system platform provider, connecting “transactions between customers and third-party DER products and services.”

The set of technologies that will allow this to happen has been dubbed a distributed system platform, or DSP -- it's a bit like a goosed-up distribution management system, a bit like a transmission grid operator’s suite of operations and market management software, and it brings together a whole lot of new technologies now just being put to the test in real-world applications. 

National Grid’s Distributed System Platform pilot with the Buffalo Niagara Medical Campus and startup Opus One is taking on the challenge of field-testing its version of a DSP. We covered the launch of this $4.8 million, two-year effort at last year’s REV Future conference, when the partners were just starting on their plan to link up DER-equipped buildings to distribution feeders.

The eventual goal is to test Opus One’s real-time, two-way power flow modeling of these distribution circuits to dispatch and control DERs to solve grid problems, from voltage and VAR support in real time, to peak load modifications and dynamic load management over the longer haul. 

This is a complex effort, and not something that gets off the ground right away. In its second-quarter 2017 update, National Grid noted that it’s seen multiple delays, including a three-month delay to refine the financial modeling methodology for hourly price signals to DER owners, a formulation known as LMP+D+E (the local transmission node marginal energy price, plus distribution system values, plus environmental and social values).

Meanwhile, delays on advanced feeder modeling and forecasting from National Grid’s internal teams mean either waiting for that work to be done, or coming up with “other alternatives for feeder modeling and forecasting that are not as accurate.”

Still, the utility and partners are “working on a fast-paced schedule to catch up,” despite losing about one-third of their allotted time to reach second-phase goals like laying out the flow of data and controls between all the parties involved. A high-level overview of what they came up with is shown in the graphic below.

This isn't the only REV project struggling to stay on its timeline. The Flexible Interconnect Capacity Solution demonstration project from Iberdrola’s New York Service Energy Group (NYSEG), Smarter Grid Solutions and Clean Power Research is aimed at creating “a new model for interconnecting [DERs] to the distribution grid using Active Network Management rather than firm capacity." 

ANM is Smarter Grid Solution’s tech platform, which combines hardware at key DER and grid sites with a centralized software platform that orchestrates their operation for grid needs. The startup has already put its technology to work to balance wind power and loads to mitigate overloads on circuits feeding Scottish islands, for example.

NYSEG is hoping its own version will allow it to “manage DERs within grid constraints (e.g., voltage, overloads, etc.) using real-time sensing and controls, avoiding more expensive upgrades.” 

But to test that out, you need some DERs to play with -- and that’s been slow going.

One, a 2-megawatt solar PV farm, landed an interconnection agreement with NYSEG in June 2016, but isn’t expected to come on-line until sometime between January and April 2018. Another, a 350-kilowatt farm waste generator, has been put on hold. Two more megawatt-scale PV farms are being considered, but one isn’t moving ahead because the owner of the site passed away "without providing land rights.”

Delays have proven deadly to Con Edison's Clean Virtual Power Plant project. In April, the utility announced it had terminated its contract with SunPower and put its plan for hundreds of behind-the-meter residential batteries "on hold until further notice.” 

“While Con Edison, SunPower, and Sunverge have had many productive discussions with the [Department of Buildings] and [the Fire Department of New York], we have not yet been able to come to an agreement that would allow the system to be installed in a manner consistent with its original design, nor without making changes that would impact the timing of program goals as envisioned under the original contract with SunPower,” the utility wrote.

FDNY's opposition to lithium-ion batteries behind closed doors has "caused challenges for New York City's storage market for quite some time," GTM Research analyst Brett Simon noted. A storage safety evaluation is underway, but it has yet to lead to faster permitting processes, he said. "New York City continues to be a market where developers note huge opportunity that's hamstrung by Li-ion permitting issues." 

Con Edison isn’t giving up completely, however. It pledged to keep working with the state and FDNY to find a “path forward” for residential battery permitting. When that happens, it plans to “enter into another contract, either with SunPower or another vendor, to deliver the program under a new agreement.” 

Non-wires alternatives: 200 megawatts and counting 

REV’s non-wires alternative (NWA) projects aren’t demonstrations, but rather first-of-their-kind contracts to open up utilities’ “black box” distribution grid planning and investment to participation from DERs. So far, only one has gotten off the ground -- Con Edison’s Brooklyn Queens Demand Management project, meant to defer a $1 billion substation upgrade with a cheaper set of distributed alternatives -- mainly energy efficiency, but also demand response, energy storage and solar PV. 

Over the course of the spring, the state’s big utilities complied with a PSC demand that they publish all their NWA opportunities in the form of an RFP and questionnaire posted online. Con Edison, O&RNYSEGRG&E, Central Hudson and National Grid now have their sites up and running, giving us more insight into what’s on offer. 

Con Edison is leading right now, with BQDM underway and two other projects recently opened and the other closed for bidding. The Hudson and Columbus Circle primary feeder relief projects in midtown Manhattan are seeking a collective 11.1 megawatts of summer peak load reduction. Two more projects seeking a combined 11 megawatts in Williamsburg and Flushing are expected to open this fall, and three more seeking 4 megawatts, 6 megawatts and a whopping 50 megawatts, respectively, are expected to open by the fourth quarter. 

One challenge with NWAs is that the underlying need for them can change underfoot. Con Edison canceled its 65th Street project due to lower-than-expected peak load in the area; it also scaled back in terms of both megawatts and delivery date another project within BQDM for the same reason. Reducing peak load through existing efficiency, demand response, or on-site power generation and energy storage business cases is a good thing, but it does tend to undermine the business case for DERs as a means of achieving grid asset deferral. 

Orange & Rockland has seven projects seeking a collective 32 megawatts of peak reduction, ranging from 15.5 megawatts to 280 kilowatts, between now and the mid-2020s. Central Hudson claims four projects, all already underway. And National Grid has the most projects, including 17 separate bids with a collective 117.5 megawatts of load relief and reliability need between 2019 and 2022. 

Meanwhile, NYSEG has a total of 10 projects, and fellow Iberdrola utility Rochester Gas & Electric has five projects, which they’ve measured not in megawatts but in cost: $49 million for RG&E and $57.5 million for NYSEG. These utilities also have the widest timespan in projects, with some delivery dates in 2030 and beyond, as shown below.

Customer connectivity, online marketplaces, and the matter of smart meters 

Most of the REV demo projects are aimed at getting utility customers online, connected, aware and involved in how they use energy. They're also aimed at helping customers understand how their distributed energy investment choices affect the broader system’s needs.

Five of the 17 projects are testing out “utility-branded marketplaces” -- web portals that offer online shopping and easy-claim rebates for LED light bulbs, smart thermostats, and other third-party gear, along with customer service features like bill payment, energy alerts and enrollment into load-control programs. 

The general approach is largely traditional, as evidenced by last month’s update from Rochester Gas & Electric’s Energy Marketplace. The portal is run by Simple Energy, a San Diego, Calif.-based startup with big utility customer connectivity projects across the country. In its recent quarterly update, it reported such efforts as “promoted thermostat and lighting sales in conjunction with Earth Day and Mother’s and Father’s Day as well as the summer season in general.” 

Some of the customer-focused REV demos are getting deeper into customer data. Central Hudson’s CenHub project involves Simple Energy and Comverge, the demand response provider now owned by Itron.

In June, Central Hudson started testing Insights+, a subscription service for residential mass-market enrollment, which “enables drill-down into time-based electric usage dashboards,” with data in annual, monthly and hourly intervals. It also started a 63-home test group whose subscriptions are paid for by Comverge, and had installed 17 Insights+ meters, the cellular meters supported by its January agreement to have Itron take over its advanced metering efforts.

Central Hudson, like the rest of New York’s utilities, is hampered by its lack of smart meters -- a big difference from California, which has been fully smart-metered for most of this decade. Smart meters provide interval data, the lifeblood of energy data analytics. And while most large-scale commercial and industrial customers have some form of interval metering, the mass of New York’s residential customers are still equipped with old-fashioned electromechanical meters. 

The limitations of this situation are displayed in utilities’ proposals for how to test out Smart Home rates -- the REV-defined rate structures meant to support time-of-use and peak pricing today, and a broader set of options for DER-equipped homes in the future.

Central Hudson is proposing a new time-of-use electric rate for customers in specific geographic regions who agree to get an Insights+ meter or load control device. National Grid is proposing a test in its Clifton Park project, featuring about 1,400 meters from Itron. And NYSEG and RG&E have proposed a “distributed storage simulation platform to test price signals and the associated customer response that results.” 

Con Edison and O&R, meanwhile, have proposed adding “smart home capabilities” and demonstrating new pricing frameworks alongside their AMI deployments with Silver Spring Networks. Silver Spring CEO Mike Bell noted in an earnings call earlier this month that Con Edison turned on its first metering connections in Staten Island this spring, marking a milestone in terms of real-world deployments.

But there are still 5 million more meters and five years to go before every customer in the territory has one. Sister utility Orange & Rockland filed an application in January that included an expansion of its existing AMI rollout to a full deployment for an additional $98 million.

New York’s AMI lag is playing to its advantage in terms of technology, however.

Con Edison’s $1.3 billion smart meter rollout with networking vendor Silver Spring Networks will support an AMI network with more granular interval data capture and exchange, more robust two-way connectivity, and a more smoothly integrated back-end than the Silver Spring network rolled out with California’s Pacific Gas & Electric. And Itron’s rollout with Central Hudson uses technology far more flexible than the smart meters it deployed for Southern California Edison and San Diego Gas & Electric. 

Interested in going even deeper? We've got you covered at GTM's New York REV Future 2017 conference on September 26 and 27 in Brooklyn, New York. Sign up today. It's a must-attend if you're doing business in New York, or if you're from another area of the country and trying to understand the Empire State's reforms.