Utility and Efficiency Businesses Take Key Step on New Utility Rate Designs

Georgia Electricity Imports October 2017 surged as hydropower output fell and thermal power plants underperformed; ESCO balanced demand via low-cost imports, mainly from Azerbaijan, amid rising tariffs, kWh consumption growth, and a widening generation-consumption gap.

Key Points

They mark a record import surge due to costly local generation, lower hydropower, ESCO balancing costs, and rising demand.

✅ Imports rose 832% YoY to 157 mln kWh, mainly from Azerbaijan

✅ TPP output fell despite capacity; only low-tariff plants ran

✅ Balancing price 13.8 tetri/kWh signaled costly domestic PPAs

In October 2017, Georgian power plants generated 828 mln. KWh of electricity, marginally up (+0.79%) compared to September. Following the traditional seasonal pattern and amid European concerns over dispatchable power shortages affecting markets, the share of electricity produced by renewable sources declined to 71% of total generation (87% in September), while thermal power generation’s share increased, accounting for 29% of total generation (compared to 13% in September). When we compare last October’s total generation with the total generation of October 2016, however, we observe an 8.7% decrease in total generation (in October 2016, total generation was 907 mln. kWh). The overall decline in generation with respect to the previous year is due to a simultaneous decline in both thermal power and hydro power generation. 

Consumption of electricity on the local market in the same period was 949 mln. kWh (+7% compared to October 2016, and +3% with respect to September 2017), and reflected global trends such as India's electricity growth in recent years. The gap between consumption and generation increased to 121 mln. kWh (15% of the amount generated in October), up from 100 mln. kWh in September. Even more importantly, the situation was radically different with respect to the prior year, when generation exceeded consumption.

The import figure for October was by far the highest from the last 12 years (since ESCO was established), occurring as Ukraine electricity exports resumed regionally, highlighting wider cross-border dynamics. In October 2017, Georgia imported 157 mln. kWh of electricity (for 5.2 ¢/kWh – 13 tetri/kWh). This constituted an 832% increase compared to October 2016, and is about 50% larger than the second largest import figure (104.2 mln. kWh in October 2014). Most of the October 2017 imports (99.6%) came from Azerbaijan, with the remaining 0.04% coming from Russia.

The main question that comes to mind when observing these statistics is: why did Georgia import so much? One might argue that this is just the result of a bad year for hydropower generation and increased demand. This argument, however, is not fully convincing. While it is true that hydropower generation declined and demand increased, the country’s excess demand could have been easily satisfied by its existing thermal power plants, even as imported coal volumes rose in regional markets. Instead of increasing, however, the electricity coming from thermal power plants declined as well. Therefore, that cannot be the reason, and another must be found. The first that comes to mind is that importing electricity may have been cheaper than buying it from local TPPs, or from other generators selling electricity to ESCO under power purchase agreements (PPAs). We can test the first part of this hypothesis by comparing the average price of imported electricity to the price ceiling on the tariff that TPPs can charge for the electricity they sell. Looking at the trade statistics from Geostat, the average price for imported electricity in October 2017 remained stable with respect to the same month of the previous year, at 5.2 ¢ (13 tetri) per kWh. Only two thermal power plants (Gardabani and Mtkvari) had a price ceiling below 13 tetri per kWh. Observing the electricity balance of Georgia, we see that indeed more than 98% of the electricity generated by TPPs in October 2017 was generated by those two power plants.

What about other potential sources of electricity amid Central Asia's power shortages at the time? To answer this question, we can use the information derived from the weighted average price of balancing electricity. Why balancing electricity? Because it allows us to reconstruct the costs the market operator (ESCO) faced during the month of October to make sure demand and supply were balanced, and it allows us to gain an insight about the price of electricity sold through PPAs.

ESCO reports that the weighted average price of balancing electricity in October 2017 was 13.8 tetri/kWh, (25% higher than in October 2016, when it was below the average weighted cost of imports – 11 vs. 13 – and when the quantity of imported electricity was substantially smaller). Knowing that in October 2017, 61% of balancing electricity came from imports, while 39% came from hydropower and wind power plants selling electricity to ESCO under their PPAs, we can deduce that in this case, internal generation was (on average) also substantially more expensive than imports. Therefore, the high cost of internally generated electricity, rather than the technical impossibility of generating enough electricity to satisfy electricity demand, indeed appears to be one the main reasons why electricity imports spiked in October 2017.

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Sault Ste. Marie Smart Grid Investment upgrades PUC Distribution infrastructure with federal funding, clean energy tech, outage reduction, customer insights, and reliability gains, creating 140 jobs and attracting industry to a resilient, efficient grid.

Key Points

A federally funded PUC Distribution project to modernize the citywide grid, cut outages, boost efficiency, and create jobs.

✅ $11.8M federal funding to PUC Distribution

✅ Citywide smart grid cuts outages and energy loss

✅ 140 jobs; attracts clean tech and industry

PUC Distribution Inc. in Sault Ste. Marie is receiving $11.8 million from the federal government to invest in infrastructure, as utilities nationwide have faced pandemic-related losses that underscore the need for resilient systems.

The MP for the riding, Terry Sheehan, made the announcement on Monday.

The money will go to the utility's smart grid project, where technologies like a centralized SCADA system can enhance situational awareness and control.

"This smart grid project offers a glimpse into our clean energy future and represents a new wave of economic activity for the region," Sheehan said.

"Along with job creation, new industries will be attracted to a modern grid, supported by stable electricity pricing that helps competitiveness, all while helping the environment."

His office says the investment will allow the utility to reduce outages, provide more information to customers to help make smarter electricity use choices, aligned with Ontario's energy-efficiency programs that encourage conservation, and offer more services.

"This is an innovative project that makes Sault Ste. Marie a leader," mayor Christian Provenzano said.

"We will be the first city in our country to implement a community-wide smart grid. Once it is complete, the smart grid will make our energy infrastructure more reliable, reduce energy loss and lead to a more innovative economy for our community."

The project will also create 140 new jobs.

"As a community-focused utility, we are always looking for innovative ways to help our customers save money amid concerns about hydro disconnections during winter, and reduce their carbon footprint," Rob Brewster, president and CEO of PUC Distribution said.

"The investment the government has made in our community will not only help modernize our city's electrical distribution system [as] once the project is complete, Sault Ste. Marie will have access to an electricity grid that can handle the growing demands of a city in the 21st century."

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Southeast Electricity Demand Forecast examines how energy efficiency, photovoltaics, electric vehicles, heat pumps, and demand response shape grid needs, stabilize load through 2030, shift peaks, and inform utility planning across the region.

Key Points

An outlook of load shaped by efficiency, solar, EVs, with demand response keeping usage steady through 2030.

✅ Stabilizes regional demand through 2030 under accelerated adoption

✅ Energy efficiency and demand response are primary levers

✅ EVs and heat pumps drive growth post 2030; shift winter peaks

Electricity markets in the Southeast are facing many changes on the customer side of the meter. In a new report released today, we look at how energy efficiency, photovoltaics (solar electricity), electric vehicles, heat pumps, and demand response (shifting loads from periods of high demand) might affect electricity needs in the Southeast.

We find that if all of these resources are pursued on an accelerated basis, electricity demand in the region can be stabilized until about 2030.

After that, demand will likely grow in the following decade because of increased market penetration of electric vehicles and heat pumps, but energy planners will have time to deal with this growth if these projections are borne out. We also find that energy efficiency and demand response can be vital for managing electricity supply and demand in the region and that these resources can help contain energy demand growth, reducing the impact of expensive new generation on consumer wallets.

National trends

This is the second ACEEE report looking at regional electricity demand. In 2016, we published a study on electricity consumption in New England, finding an even more pronounced effect. For New England, with even more aggressive pursuit of energy efficiency and these other resources, consumption was projected to decline through about 2030, before rebounding in the following decade.

These regional trends fit into a broader national pattern. In the United States, electricity consumption has been characterized by flat electricity demand for the past decade. Increased energy efficiency efforts have contributed to this lack of consumption growth, even as the US economy has grown since the Great Recession. Recently, the US Energy Information Administration (EIA – a branch of the US Department of Energy) released data on US electricity consumption in 2016, finding that 2016 consumption was 0.3% below 2015 consumption, and other analysts reported a 1% slide in 2023 on milder weather.

Five scenarios for the Southeast

ACEEE’s new study focuses on the Southeast because it is very different from New England, with warmer weather, more economic growth, and less-aggressive energy efficiency and distributed energy policies than the Northeast. For the Southeast, we examined five scenarios: a business-as-usual scenario; two alternative scenarios with progressively higher levels of energy efficiency, photovoltaics informed by a solar strategy for the South that is emerging regionally, electric vehicles, heat pumps, and demand response; and two scenarios combining high numbers of electric vehicles and heat pumps with more modest levels of the other resources. This figure presents electricity demand for each of these scenarios:

Over the 2016-2040 period, we project that average annual growth will range from 0.1% to 1.0%, depending on the scenario, much slower than historic growth in the region. Energy efficiency is generally the biggest contributor to changes in projected 2040 electricity consumption relative to the business-as-usual scenario, as shown in the figure below, which presents our accelerated scenario that is based on levels of energy efficiency and other resources now targeted by leading states and utilities in the Southeast.

To date, Entergy Arkansas has achieved the annual efficiency savings as a percent of sales shown in the accelerated scenario and Progress Energy (a division of Duke Energy) has nearly achieved those savings in both North and South Carolina. Sixteen states outside the Southeast have also achieved these savings statewide.

The efficiency savings shown in the aggressive scenario have been proposed by the Arkansas PSC. This level of savings has already been achieved by Arizona as well as six other states. Likewise, the demand response savings we model have been achieved by more than 10 utilities, including four in the Southeast. The levels of photovoltaic, electric vehicle, and heat pump penetration are more speculative and are subject to significant uncertainty.

We also examined trends in summer and winter peak demand. Most utilities in the Southeast have historically had peak demand in the summer, often seeing heatwave-driven surges that stress operations across the Eastern U.S., but our analysis shows that winter peaks will be more likely in the region as photovoltaics and demand response reduce summer peaks and heat pumps increase winter peaks.

Why it’s vital to plan broadly

Our analysis illustrates the importance of incorporating energy efficiency, demand response, and photovoltaics into utility planning forecasts as utility trends to watch continue to evolve. Failing to include these resources leads to much higher forecasts, resulting in excess utility system investments, unnecessarily increasing customer electricity rates. Our analysis also illustrates the importance of including electric vehicles and heat pumps in long-term forecasts. While these technologies will have moderate impacts over the next 10 years, they could become increasingly important in the long run.

We are entering a dynamic period of substantial uncertainty for long-term electricity sales and system peaks, highlighted by COVID-19 demand shifts that upended typical patterns. We need to carefully observe and analyze developments in energy efficiency, photovoltaics, electric vehicles, heat pumps, and demand response over the next few years. As these technologies advance, we can create policies to reduce energy bills, system costs, and harmful emissions, drawing on grid reliability strategies tested in Texas, while growing the Southeast’s economy. Resource planners should be sure to incorporate these emerging trends and policies into their long-term forecasts and planning.

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Smart solar inverters anchor DER communications and control, meeting IEEE 1547 and California Rule 21 for volt/VAR, reactive power, and ride-through, expanding hosting capacity and enabling grid services via secure real-time telemetry and commands.

Key Points

Smart solar inverters use IEEE 1547, volt/VAR and reactive power to stabilize circuits and integrate DER safely.

✅ Meet IEEE 1547, Rule 21 ride-through and volt/VAR functions

✅ Support reactive power to manage voltage and hosting capacity

✅ Enable utility communications, telemetry, and grid services

Advanced solar inverters could be one of the biggest distributed energy resource communications and control points out there someday. With California now requiring at least early-stage “smart” capabilities from all new solar projects — and a standards road map for next-stage efforts like real-time communications and active controls — this future now has a template.

There are still a lot of unanswered questions about how smart inverters will be used.

That was the consensus at Intersolar this week, where experts discussed the latest developments on the U.S. smart solar inverter front. After years of pilot projects, multi-stakeholder technical working groups, and slow and steady standards development, solar smart inverters are finally starting to hit the market en masse — even if it’s not yet clear just what will be done with them once they’re installed.

“From the technical perspective, the standards are firm,” Roger Salas, distribution engineering manager for Southern California Edison, said. In September of last year, his utility started requiring that all new solar installations come with “Phase 1" advanced inverter functionality, as defined under the state’s Rule 21.

Later this month, it’s going to start requiring “reactive power priority” for these inverters, and in February 2019, it’s going to start requiring that inverters support the communications capabilities described in “Phase 2,” as well as some more advanced “Phase 3” capabilities.

Increasing hosting capacity: A win-win for solar and utilities

Each of these phases aligns with a different value proposition for smart inverters. The first phase is largely preventative, aimed at solving the kinds of problems that have forced costly upgrades to how inverters operate in solar-heavy Germany and Hawaii.

The key standard in question in the U.S. is IEEE 1547, which sets the rules for what grid-connected DERs must do to stay safe, such as trip offline when the grid goes down, or avoid overloading local transformers or circuits.

The old version of the standard, however, had a lot of restrictive rules on tripping off during relatively common voltage excursions, which could cause real problems on circuits with a lot of solar dropping off all at once.

Phase 1 implementation of IEEE 1547 is all about removing these barriers, Salas said. “They need to be stable, they need to be connected, they need to be able to support the grid.”

This should increase hosting capacity on circuits that would have otherwise been constrained by these unwelcome behaviors, he said.

Reactive power: Where utility and solar imperatives collide

The old versions of IEEE 1547 also didn’t provide rules for how inverters could use one of their more flexible capabilities: the ability to inject or absorb reactive power to mitigate voltage fluctuations, including those that may be caused by the PV itself. The new version opens up this capability, which could allow for an active application of reactive power to further increase hosting capacity, as well as solve other grid edge challenges for utilities.

But where utilities see opportunity, the solar industry sees a threat. Every unit of reactive power comes at the cost of a reduction in the real power output of solar inverters — and almost every solar installation out there is paid based on the real power it produces.

“If you’re tasked to do things that rob your energy sales, that will reduce compensation,” noted Ric O'Connell, executive director of the Oakland, Calif.-based GridLab. “And a lot of systems have third-party owners — the Sunruns, the Teslas — with growing Powerwall fleets — that have contracts, performance guarantees, and they want to get those financed. It’s harder to do that if there’s uncertainty in the future with curtailment."

“That’s the bottleneck right now,” said Daniel Munoz-Alvarez, a GTM Research grid edge analyst. “As we develop markets on the retail end for ...volt/VAR control to be compensated on the grid edge and that is compensated back to the customer, then the customer will be more willing to allow the utility to control their smart inverters or to allow some automation.”

But first, he said, “We need some agreed-upon functions.”

The future: Communications, controls and DER integration

The next stage of smart inverter functionality is establishing communications with the utility. After that, utilities will be able use them to monitor key DER data, or issue disconnect and reconnect commands in emergencies, as well as actively orchestrate other utility devices and systems through emerging virtual power plant strategies across their service areas.

This last area is where Salas sees the greatest opportunity to putting mass-market smart solar inverters to use. “If you want to maximize the DERs and what they can do, the need information from the grid. And DERs provide operational and capability information to the utility.”

Inverter makers have already been forced by California to enable the latest IEEE 1547 capabilities into their existing controls systems — but they are clearly embracing the role that their devices can play on the grid as well. Microinverter maker Enphase leveraged its work in Hawaii into a grid services business, seeking to provide data to utilities where they already had a significant number of installations. While Enphase has since scaled back dramatically, its main rival SolarEdge has taken up the same challenge, launching its own grid services arm earlier this summer.

Inverters have been technically capable of doing most of these things for a long time. But utilities and regulators have been waiting for the completion of IEEE 1547 to move forward decisively. Patrick Dalton, senior engineer for Xcel Energy, said his company’s utilities in Colorado and Minnesota are still several years away from mandating advanced inverter capabilities and are waiting for California’s energy transition example in order to choose a path forward.

In the meantime, it’s possible that Xcel's front-of-meter volt/VAR optimization investments in Colorado, including grid edge devices from startup Varentec, could solve many of the issues that have been addressed by smart inverter efforts in Hawaii and California, he noted.

The broader landscape for rolling out smart inverters for solar installations hasn’t changed much, with Hawaii and California still out ahead of the pack, while territories such as Puerto Rico microgrid rules evolve to support resilience. Arizona is the next most important state, with a high penetration of distributed solar, a contentious policy climate surrounding its proper treatment in future years, and a big smart inverter pilot from utility Arizona Public Service to inform stakeholders.

All told, eight separate smart inverter pilots are underway across eight states at present, according to GTM Research: Pacific Gas & Electric and San Diego Gas & Electric in California; APS and Salt River Project in Arizona; Hawaiian Electric in Hawaii; Duke Energy in North Carolina; Con Edison in New York; and a three-state pilot funded by the Department of Energy’s SunShot program and led by the Electric Power Research Institute.

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Massachusetts Solar Net Metering faces new demand charges and elimination of residential time-of-use rates under an MDPU order, as Eversource cites grid cost fairness while clean energy advocates warn of impacts on distributed solar growth.

Key Points

Policy letting solar customers net out usage with exports; MDPU now adds demand charges and ends TOU rates.

✅ New residential solar demand charges start Dec 31, 2018.

✅ Optional residential TOU rates eliminated by MDPU order.

✅ Eversource cites grid cost fairness; advocates warn slower solar.

A recent Massachusetts Department of Public Utilities' rate case order changes the way solar net metering works and eliminates optional residential time-of-use rates, stirring controversy between clean energy advocates and utility Eversource and potential consumer backlash over rate design.

"There is a lot of room to talk about what net-energy metering should look like, but a demand charge is an unfair way to charge customers," Mark LeBel, staff attorney at non-profit clean energy advocacy organization Acadia Center, said in a Tuesday phone call. Acadia Center is an intervenor in the rate case and opposed the changes.

The Friday MDPU order implements demand charges for new residential solar projects starting on December 31, 2018. Such charges are based on the highest peak hourly consumption over the course of a month, regardless of what time the power is consumed.

Eversource contends the demand charge will more fairly distribute the costs of maintaining the local power grid, echoing minimum charge proposals aimed at low-usage customers. Net metering is often criticized for not evenly distributing those costs, which are effectively subsidized by non-net-metered customers.

"What the demand charge will do is eliminate, to the extent possible, the unfair cross subsidization by non-net-metered customers that currently exists with rates that only have kilowatt-hour charges and no kilowatt demand, Mike Durand, Eversource spokesman, said in a Tuesday email. 

"For net metered facilities that use little kilowatt-hours, a demand charge is a way to charge them for their fair share of the cost of the significant maintenance and upgrade work we do on the local grid every day," Durand said. "Currently, their neighbors are paying more than their share of those costs."

It will not affect existing facilities, Durand said, only those installed after December 31, 2018.

Solar advocates are not enthusiastic about the change and see it slowing the growth of solar power, particularly residential rooftop solar, in the state.

"This is a terrible outcome for the future of solar in Massachusetts," Nathan Phelps, program manager of distributed generation and regulatory policy at solar power advocacy group Vote Solar, said in a Tuesday phone call.

"It's very inconsistent with DPU precedent and numerous pieces of legislation passed in the last 10 years," Phelps said. "The commonwealth has passed several pieces of legislation that are supportive of renewable energy and solar power. I don't know what the DPU was thinking."

 

TIME-OF-USE PRICING ELIMINATED

It does not matter when during the month peak demand occurs -- which could be during the week in the evening -- customers will be charged the same as they would on a hot summer day, LeBel said. Because an individual customer's peak usage does not necessarily correspond to peak demand across the utility's system, consumers are not being provided incentives to reduce energy usage in a way that could benefit the power system, Acadia Center said in a Tuesday statement.

However, Eversource maintains that residential customer distribution peaks based on customer load profiles do not align with basic service peak periods, which are based on Independent System Operator New England's peaks that reflect market-based pricing, even as a Connecticut market overhaul advances in the region, according to the MDPU order.

"The residential Time of Use rates we're eliminating are obsolete, having been designed decades ago when we were responsible for both the generation and the delivery of electricity," Eversource's Durand said.

"We are no longer in the generation business, having divested of our generation assets in Massachusetts in compliance with the law that restructured of our industry back in the late 1990s. Time Varying pricing is best used with generation rates, where the price for electricity changes based on time of day and electricity demand and can significantly alter electric bills for households," he said.

Additionally, only 0.02% of residential customers take service on Eversource's TOU rates and it would be difficult for residential customers to avoid peak period rates because they do not have the ability to shift or reduce load, according to the order.

"The Department allowed the Companies' proposal to eliminate their optional residential TOU rates in order to consolidate and align their residential rates and tariffs to better achieve the rate structure goal of simplicity," the MDPU said in the order.

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Maine Climate Council Act targets 80% renewable power by 2030 and 100% by 2050, slashing greenhouse gas emissions via clean electricity, grid procurement, long-term contracts, wind and hydro integration, resilience planning, and carbon sequestration.

Key Points

A Maine policy forming a Climate Council to reach 80% renewables in 2030 100% in 2050 and cut greenhouse gas emissions.

✅ 80% renewable electricity by 2030; 100% by 2050.

✅ 45% GHG cut by 2030; 80% by 2050.

✅ Utility procurement authority for clean capacity and energy.

The winds of change have shifted and are blowing Northward, as Maine’s Governor, Janet T. Mills, has put forth an act establishing a Climate Council to guide the state’s consumption to 80% renewable electricity in 2030 and 100% by 2050, echoing New York's Green New Deal ambitions underway.

The act, LR 2478 (pdf), also sets a goal of reducing greenhouse gas emissions by 45% in 2030 and 80% by 2050. The document will be submitted to the state Legislature for consideration.

The commission would have the authority to direct investor owned transmission and distribution utilities to run competitive procurement processes, and enter into long-term contracts for capacity resources, energy resources, renewable energy credit contracts, and participate in regional programs, as these all lead toward the clean electricity and emissions-reducing goals that mirror California's 100% mandate debates today.

The Climate Council would convene industry working groups, including Scientific and Technical, Transportation, Coastal and Marine, Energy, and Building & Infrastructure working groups, plus others as needed, where examples like New Zealand's electricity transition could inform discussions.

Membership within the council would include two members of the State Senate, two members of the House, a tribal representative, many department commissioners (Education, Defense, Transportation, etc.), multiple directors, business representatives, environmental non-profit members, and climate science and resilience representatives as well.

The council would update the Maine State Climate Plan every four years, and solicit input from the public and report out progress on its goals every two years, similar to planning underway in Minnesota's carbon-free plan framework. The first Climate Action Plan would be submitted to the legislature by December 1, 2020.

Specifically, the responsibilities of the Scientific and Technical Subcommittee were laid out. The group would be scheduled to meet at least every six months, beginning no later than October 1, 2019. The group would be tasked with reviewing existing scientific literature, including net-zero electricity pathways research, to use it as guidance, recognizing gaps in the state’s knowledge, and guiding outside experts to ascertain this knowledge.  The group would consider ocean acidification, and climate change effects on the state’s species; establish science-based sea-level rise projections for the state’s coastal regions by December 1, 2020; create a climate risk map for flooding and extreme weather events; and consider carbon sequestration via biomass growth.

The state’s largest power plants (above image), generate about 31% from gas, 28% from wood and 41% from hydro+wind. Already, the state has a very clean electricity profile, much like efforts to decarbonize Canada's power sector continue apace. Below, the U.S. Energy Information Administration (EIA) notes that 51% of electricity generation within the state comes from mostly wind+hydro, with a small touch from solar power. The state also gets 24% from wood and other biomass, which would lead some to argue that the state is already at 75% “renewable electricity”. The Governor’s document does reference wind power specifically as a renewable, however, no other specific electricity source. And there is much reference to forestry, agriculture, and logging – specifically noting carbon sequestration – but nothing regarding electricity.

The state’s final 25% of electricity mostly comes from natural gas, even as renewable electricity momentum builds across North America, with this author choosing to put “other” under the fossil percentage noted above.

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