Let’s start this grid edge overview with a subject that got a lot of attention from attendees of our Solar Summit 2017 conference this week: the conflict emerging between the Trump administration and the clean energy industry over the question of baseload power plants and grid stability.
In March, Energy Secretary Rick Perry ordered a study to determine how intermittent solar and wind power are affecting the financial viability of coal and nuclear power plants, and thus grid stability. But the renewable energy industry -- and at least one Republican senator from a big wind state -- have pointed out that multiple studies on this subject have taken years to reach solid conclusions based on open processes.
The DOE study, in contrast, is to be completed within 60 days, and with no apparent opportunity for public input. This has stoked fears that it could be the precursor to policy suggestions that could undercut green power, as Solar Energy Industries Association CEO Abby Ross Hopper said this week at GTM’s Solar Summit.
But as SEIA, the Advanced Energy Economy, the American Council on Renewable Energy and the American Wind Energy Association have all pointed out, baseload coal and nuclear plants are struggling not so much because of renewables, and rather more because of cheap natural gas. Research firm ScottMadden released a report this week that underscored this fact. Natural-gas prices remain low across North America, buoyed by continued growth in shale gas production actually outstripping some longstanding traditional supplies.
At this week’s Solar Summit, I spoke to a few grid industry executives who agreed, at least off the record, with the assessment of Perry’s study as a foregone conclusion against green power. They’re not interested in getting involved in the politics of the issue. But they are quite eager to provide data on how their companies’ technologies are helping to integrate wind and solar power into the grid as a stable, predictable and even dispatchable resource. We’ve covered several examples of this kind of thing, from First Solar’s work with NREL with utility-scale solar inverters, to Sempra Energy and OSIsoft’s work with a wind farm backed by lithium-ion batteries.
The ISO update: PJM’s State of the Grid and NYISO’s Power Trends 2017
These issues of renewable energy’s effect on energy markets and policies have been filtering down to the independent system operators (ISOs) and regional transmission organizations (RTOs) that manage transmission grids that serve about two-thirds of the country. As we covered earlier this month, the country’s biggest ISO, mid-Atlantic grid operator PJM, has been taking on the subject with discussions on how to balance state energy policies and interstate energy markets.
PJM President and CEO Andy Ott highlighted this debate during his “State of the Grid” talk on Wednesday at PJM’s Annual Meeting in Chicago. “There’s significant debate about harmonizing public policy and markets,” he told PJM members, adding, “I hope you come up with a solution that will protect the competitive markets while accommodating the states as much you as can.”
PJM’s executives and staffers are necessarily neutral on these political subjects. But they are responsible for maintaining reliability in the midst of an increasingly diverse mix of generation resources, Ott pointed out. And in PJM’s March report on the subject, the grid operator found that it could handle renewable energy reaching about 20 percent of its capacity before reliability issues start to arise, far beyond today’s roughly 6 percent.
He also noted that cybersecurity has become a reliability issue for PJM as well. The grid operator is working on strengthening network design, as well as expanding partnerships with the Defense Department and other government agencies.
Meanwhile in New York, grid operator NYISO related its Power Trends 2017 report this week, highlighting how the state is managing the growth of energy efficiency and distributed energy resources. Energy efficiency and DERs are forecasted to reduce peak demand on New York’s bulk power system by more than 900 megawatts this year, a figure that’s set to grow to nearly 3,300 megawatts by 2027.
That means that overall usage of electric energy from New York’s bulk power system is expected to decline slightly over the next decade -- but peak demand is expected to increase at a moderate pace. This, of course, will require a more flexible mix of generation and demand-side resources to meet growing peaks, along with a careful analysis of the relative costs and benefits of the mix of efficiency, demand response, energy storage, plug-in electric vehicles, and other new assets as replacements for traditional grid and generation investments.
While NYISO doesn’t have oversight over distribution grid assets, it is working with the state’s Public Service Commission, utilities and other stakeholders as part of the state’s Reforming the Energy Vision effort. This week’s report notes that NYISO is relying on its Distributed Energy Resource Roadmap, released in February, to guide efforts to integrate distributed resources into wholesale electricity markets over the next three to five years.
Finding the locational value of energy efficiency
One of the most challenging aspects of merging distributed energy and utility economics has to do with determining the locational costs and values of DERs on distribution grid investments and operations. We’ve covered this subject for years, with a focus on states like California and New York that have launched specific policy efforts on this front (DRP and IDER, and REV, respectively). Then there are the technical challenges of creating a distribution system operator to manage this interplay, and of course, the intersection at which technologies and policies yield real-world financial results.
This week, ICF Consulting released a report on this subject, based on work it did with an unnamed “major U.S. utility” to analyze distribution system data and identify grid locations with the greatest need for capacity upgrades -- typically locations that are forecast to experience significant load growth. It then applied “traditional” infrastructure solutions such as feeder reconductoring to alleviate capacity needs, and compared and contrasted them to various mixes of DERs, including solar, demand response, batteries and broad efficiency.
Efficiency remains the cheapest of these alternatives, but as we’ve covered in some detail, today’s efficiency programs are largely based on utility-wide incentive and rebate offerings. But ICF’s analysis found that capturing even modest distribution deferral values can still lead to “meaningful increases” -- between 4 percent and 27 percent -- in energy efficiency program cost-benefit ratios.
That would, of course, require utilities to target the customers dwelling at the most beneficial grid locations, all without offering them additional incentives or financial benefits unavailable to other customers. ICF suggests that utilities could accomplish this through multi-channel marketing plans to increase program participation without increasing subsidies.
On the subject of energy efficiency, DOE released its 2017 Better Buildings Progress Report this week, noting that the Obama-era Better Buildings Challenge has led to an estimated $1.9 billion in cumulative energy and cost savings amongst the 345 public and private sector groups participating. That’s nearly double the $1 billion in savings shown in its 2015 report.
GTM Research on AMI, DERMS and state-by-state energy storage incentives
GTM Research has been busy, with a flurry of reports and research notes released this week. First, we’ve got the new AMI Global Forecast 2017-2021, which predicts cumulative global AMI installations will reach 922 million by 2021. Much of this growth will be driven by a predicted $48 billion spend on European smart meter deployments over the next five years, analyst Paulina Tarrant notes -- if the countries involved don’t fall further behind schedule. Meanwhile, China is well ahead of the rest of Asia in deploying low-cost AMI infrastructure,
In North America, meanwhile, the next five years will see a spike in deployments as 1-million-plus-customer utilities including Con Edison, Entergy, AEP Ohio, Consumer Energy, Commonwealth Edison, Ameren and Nevada Power move ahead with rollouts. Growth in the U.S. will taper off in 2020 as these deployments near completion, unless other large utilities that haven’t yet announced full-scale AMI rollout plans -- such as Niagara Mohawk Power, Los Angeles Dept. of Water and Power, Puget Sound Energy, and Jersey Central Power & Light -- pull the trigger, which could add another 5.75 million smart meters to the forecast.
In a related note, West Monroe Partners released a report this week finding the water utility industry is about seven years behind the electric industry when it comes to leveraging smart meter data. Only 35 percent of water providers use AMI today, compared to more than 70 percent of electric utilities. The main barrier is cost, with several utilities saying they would need external funding to make it feasible.
Has the acronym DERMS (which stands for "distributed energy resource management system") outlived its usefulness? GTM Research’s grid research director Ben Kellison’s new research note argues that case, noting that few technology companies have the full suite of capabilities that constitute a true DERMS product, and that most are more properly considered as upgrades to legacy utility software. At the same time, focusing on the concept of soup-to-nuts DERMS overlooks the near-term benefits to be delivered through software for DER lifecycle management -- a term that can include software that helps utilities in states like New York and California manage distribution system planning that incorporates DER values.
And in a reminder of the importance of state incentives, GTM Research energy storage analyst Brett Simon has published a note highlighting the new opportunities emerging in Hawaii under proposed legislation. HB 1593, the only one of five pieces of legislation supporting storage to make it to consideration as a bill before the state legislature, would apply to systems installed alongside solar and placed into service after July 31, within a budget cap of $30 million.
GTM Research’s economic modeling shows the incentive could increase internal rate of return between 110 basis points and 140 basis points, and net present value by almost $1,000, while lowering leveled costs of energy by roughly $13 per megawatt-hour in real terms and about $17 per megawatt-hour in nominal terms. In other words, “the program has a positive impact on overall system economics, though the changes are not groundbreaking” -- a move in keeping with a state where the market incentives of installing battery-backed solar are already the most attractive in the country.