by Jeff St. John
July 14, 2017

Sometimes technology and policy fall out of sync, and sometimes they reinforce one another. In Colorado, Xcel Energy and state regulators have just started a new experiment in how to unshackle the utility from a system that rewards it for selling as much energy as possible -- largely as a result of negotiations over how to allow a big smart meter deployment to move ahead. 

Late last month, after more than three years of effort, Xcel Energy reached an agreement with Colorado state regulators and more than a dozen parties in a settlement to move ahead with a $612 million plan to deploy up to 1.6 million smart meters across its service territory. The investment also includes communications infrastructure to help manage its distribution grids, and a volt/VAR optimization system that could reduce the utility's energy load by up to 2 percent. 

Ironically, it's these benefits that have held up progress on the plan for so long. Unlike utilities in California, New York, Illinois, or the other dozen states that have decoupled electric utility revenues from energy sales, Xcel recovers a “substantial amount” of its fixed costs through the variable revenues that come from sales to customers -- and anything that reduces those sales is a threat to those revenues. 

Xcel's original idea for solving that problem, a fixed “grid use charge,” was roundly panned by most of the parties involved, from environmental groups to commercial and industrial energy customer associations. The Colorado Public Utilities Commission rejected the idea in 2015, and Xcel submitted a new proposal last year, containing its next idea -- decoupling. 

In decoupled states, the regulator sets a target level of sales and revenues, and then a year later, compares it to what actually happened. Any over-collection is refunded to customers through a bill credit, and any under-collection is brought back through a bill surcharge. Xcel's Revenue Decoupling Adjustment (RDA) pilot will apply this concept over the next five years to two groups of residential and small commercial customers. 

The first group will stay on their regular rates. The second will volunteer for Xcel's Residential Demand Time of Use (RD-TOU) pilot rate, an optional time-of-use rate that would reward customers who shift some of their usage to off-peak periods -- and punish them for using more power during peak hours. One of the key reasons Xcel has cited for deploying smart meters is to support these kinds of time-of-use rates to offer customers the value of off-peak pricing to make up for charging them more -- and hopefully driving down demand -- during hot summer afternoon peaks. 

After a year, all of these customers bills will be compared to changes in their weather-normalized energy usage over the year under the existing residential rate, and the differences will be summed up. Then a “Demand-Side Management disincentive offset amount,” or DSM, which the Colorado PUC set in place to compensate for revenues Xcel may lose through implementing its own demand-side management programs, is subtracted. This net adjustment amount is passed back to both standard and RD-TOU customers in the next year’s bills, in the form of a surcharge or credit. 

Here’s a more technical outline of Xcel’s RDA plan for those interested. The Colorado PUC largely accepted Xcel’s 2016 plan, but did modify it to increase small commercial customer participation in the pilot. 

Xcel says that moving toward decoupling could give it the revenue assurance to offer new rate designs, such as its proposed RD-TOU rate, to its customers at large. It could also help remove the disincentive associated with rooftop solar installations -- namely, the fact that net-metered customers pay much less in energy bills, and thus less in fixed cost recovery. And it could help with implementing commonsense solutions like integrated volt/VAR optimization (VVO).

About half of all states have instituted decoupling for utilities providing electricity, natural gas, or both, according to this running tally from the Natural Resources Defense Council. Xcel has actually been on the forefront of adding states to this roster -- besides its new plan in Colorado, it was the first utility to start testing decoupling in Minnesota through a three-year pilot project approved in 2015 and started last year

A smart meter market update: Contracts, partnerships and IPOs 

Many of the innovations being plotted by Xcel, including TOU rates and VVO, rely on smart meters that can record and report energy usage in 15-minute intervals, or measure and alert utility operators to voltage changes on the edges of the grid in real time. This brings the decoupling discussion back to Xcel’s smart meter deployment plans, which are a big deal in their own right. 

GTM Research analyst Paulina Tarrant noted that Xcel’s smart meter plans represent a long-awaited boost to a U.S. market that’s seen only three previous AMI contracts for more than 1 million meters over the past year and a half -- the others are Entergy, AEP Ohio and Con Edison. Of course, Xcel still has many steps between last month’s PUC approval and picking a vendor for its deployment, but it’s likely that big AMI players are starting to put together their proposals. 

As the winner of all three of the aforementioned multimillion-meter contracts, Silver Spring Networks is a clear contender for Xcel’s business. But it’s also been picking up some smaller contracts of late, such as its 47,000-meter contract with Grant County Public Utility District in Washington state. Meanwhile, rival AMI vendor Itron is picking up its own smaller-scale contract, like 19,500 meters for Jefferson County PUD

A third major rival, Landis+Gyr, has been in the news lately for its efforts to extricate itself from struggling parent company Toshiba via an IPO. This week it set a price range from 70 to 82 Swiss francs per share for the offering on the Swiss SIX stock exchange, giving a market value of between 2.1 billion francs and 2.4 billion francs, or up to $2.5 billion. 

Landis+Gyr has also been adding new contracts to boost its current tally of 60 million connected devices, such as the contracts with three Central American utilities -- Electrica de Guatemala S.A. in Guatemala, DELSUR in El Salvador and Elektra Noreste S.A. in Panama -- announced this week, adding up to about 150,000 smart meters over the next year. 

It’s also adding services revenues to its meter sales. Late last month, Landis+Gyr landed a six-year service management contract with Finland utility Caruna, to collect and manage hourly consumption and power quality data from 650,000 residential smart meters. Taking over the management of existing AMI infrastructure is a business sought by multiple vendors -- in April, Itron won a contract to manage Texas-New Mexico Power’s network of about 245,000 customers. 

In a similar move, Sensus, the smart metering giant bought by water treatment company Xylem for $1.7 billion last year, landed an agreement last week with Alliant Energy Corp. Sensus will add its FlexNet communications to the utility’s power grid and natural gas system in Iowa over the next three years. Combining smart meters and water treatment may seem an unusual combination, but it has big potential. Sensus is an important player in water metering, a market that could see a significant boom in the coming years. U.S. water utilities are projected to invest $8.3 billion in smart infrastructure over the next 10 years, according to a new report from Northeast Group.

Streetlights -- particularly those being replaced by LEDs -- are also a major new growth market for AMI vendors. Silver Spring holds the clear lead in this to date, helped along by its acquisition of firm Streetlight.Vision and its smart meter networks in cities like Miami, and now Chicago. Last week, Silver Spring announced it’s working with Ameresco on a four-year modernization project to replace about 250,000 streetlights, or roughly 85 percent of the city’s lights, with smart LEDs. In greenfield projects, it announced a three-year, 110,000-streetlight LED replacement for Jamaica Public Service Company in cities including Kingston, Spanish Town, Negril and Falmouth.

The latest on state DER-grid integration policy 

There are a few states leading in transforming energy policies to integrate distributed energy resources (DERs) into utility grid operations and planning, such as California, New York and Hawaii -- and others that are hot on their heels. One of these is Illinois, where the aforementioned rollout of smart meters and distribution automation are allowing utilities, customers and regulators to consider new ways to make use of DERs. 

A new report from the 51st State, the Smart Electric Power Alliance and ScottMadden outlines the ways Illinois has started to catch up to its coastal brethren, including performance-based ratemaking for utility AMI deployments, and specific targets for solar power, energy efficiency and distributed generation. 

“State law has also taken into account a future in which higher DER penetration will require a more sophisticated approach to customer compensation for behind-the-meter (BTM) resources, an approach that takes a closer look at the locational value of DERs, and allows utilities to treat distributed generation rebates as a regulatory asset and earn a return.” 

Meanwhile, in New York, Con Edison is seeking proposals for a project that would extend the model of its Brooklyn-Queens Neighborhood Program (BQDM) to another targeted group of customers in the same two boroughs, plus Manhattan. Last week’s call for proposals seeks businesses that can help customers install solar panels, fuel cells, energy-efficient equipment, batteries and other distributed energy resources, to help reduce the need for power in these areas by about 30 megawatts.

Its model, BQDM, was launched in 2014 to help replace a $1.2 billion substation upgrade through DERs, ranging from grid-tied batteries and commercial-industrial load control to apartment building energy efficiency and demand response. The goal, to gain a combined 41 megawatts of load reduction through late afternoon into late evening, appears in reach -- although, as we’ve noted at Greentech Media, its execution is not without its critics

The same holds true in California, where the solar industry is clashing with utility Southern California Edison about how it has, or hasn’t, calculated the costs and values of rooftop solar and associated DERs into its grid modernization plans. 

As part of the utility’s 2018 general rate case, the California Public Utilities Commission is considering a challenge from the Solar Energy Industries Association (SEIA) and Vote Solar against SCE’s multibillion-dollar grid modernization plan. This sprawling document covers everything from replacing hundreds of smaller substations with more powerful ones, to merging its complex of software platforms into an overarching system of systems

In simple terms, the groups say that $2.7 billion of the $4 billion or so SCE wants to spend over the next three years on this effort isn’t necessary, for two main reasons. One, the groups say that SCE is overestimating how much distributed solar will be coming onto its system over that time -- a proposition it backs up with SEIA/GTM Research data. Second, it doesn’t take into account the positive values that could be provided by DERs. 

“SCE is underestimating the positive and exaggerating the negative impact of distributed energy,” Sean Gallagher, SEIA’s vice president of state affairs, explained in a blog post. SEIA wants the utility to turn to the CPUC’s Distributed Resource Planning (DRP) proceeding to “determine the optimal locations for grid modernization investments and the relative cost-effectiveness of utility-owned versus third-party-owned communications technologies."

It’s not clear whether SCE could be expected to include such values in an ongoing rate case, however -- after all, the rules for valuing DERs are only just being formulated through the DRP proceeding, while the follow-on IDER proceeding to turn these values into actual compensation awaits action after its sponsor, Commissioner Mike Florio, departed last year. Whether or not SCE is overestimating solar growth is another matter, and it seems like something commission staff might address.