Eight Areas of Electricity Innovation to Watch in 2017

Puerto Rico Microgrid Regulations outline renewable energy, CHP, and storage standards, enabling islanded systems, PREPA interconnection, excess energy sales, and IRP alignment to boost resilience, distributed resources, and community power across the recovering grid.

Key Points

Rules defining microgrids, requiring 75 percent renewables or CHP, and setting interconnection and PREPA fee frameworks.

✅ 75 percent renewables or CHP; hybrids allowed

✅ Registration, engineer inspection, and annual generation reports

✅ PREPA interconnection fees; excess energy sales permitted

The Puerto Rico Energy Commission unveiled 29 pages of proposed regulations last week for future microgrid installations on the island.

The regulations, which are now open for 30 days of public comment, synthesized pages of responses received after a November 10 call for recommendations. Commission chair José Román Morales said it’s the most interest the not-yet four-year-old commission has received during a public rulemaking process.

The goal was to sketch a clearer outline for a tricky-to-define concept -- the term "microgrid" can refer to many types of generation islanded from the central grid -- as climate pressures on the U.S. grid mount and more developers eye installations on the recovering island.

“There’s not a standard definition of what a microgrid is, not even on the mainland,” said Román Morales.

According to the commission's regulation, “a microgrid shall consist, at a minimum, of generation assets, loads and distribution infrastructure. Microgrids shall include sufficient generation, storage assets and advanced distribution technologies, including advanced inverters, to serve load under normal operating and usage conditions.”

All microgrids must be renewable (with at least 75 percent of power from clean energy), combined heat and power (CHP) or hybrid CHP-and-renewable systems. The regulation applies to microgrids controlled and owned by individuals, customer cooperatives, nonprofit and for-profit companies, and cities, but not those owned by the Puerto Rico Electric Power Authority (PREPA). Owners must submit a registration application for approval, including a certification of inspection from a licensed electric engineer, and an annual fuel, generation and sales report that details generation and fuel source, as well as any change in the number of customers served.

Microgrids, like the SDG&E microgrid in Ramona in California, can interconnect with the PREPA system, but if a microgrid will use PREPA infrastructure, owners will incur a monthly fee. That amounts to $25 per customer up to a cap of $250 per month for small cooperative microgrids. The cost for larger systems is calculated using a separate, more complex equation. Operators can also sell excess energy back to PREPA.

Big goals for the island's future grid

In total, 53 groups and companies, including Sunnova, AES, the Puerto Rico Solar Energy Industries Association (PR-SEIA), the Advanced Energy Management Alliance (AEMA), and the New York Smart Grid Consortium, submitted their thoughts about microgrids or, in many cases, broader goals for the island’s future energy system. It was a quick turnaround: The Puerto Rico Energy Commission offered a window of just 10 days to submit advice, although the commission continued to accept comments after the deadline.

“PREC wanted the input as fast as possible because of the urgency,” said AES CEO Chris Shelton.

AES’ plan includes a network of “mini-grids” that could range in size from several megawatts to one large enough to service the entire city of San Juan.

“The idea is, you connect those to each other with transmission so they can have a co-optimized portfolio effect and lower the overall cost,” said Shelton. “But they would be largely autonomous in a situation where the tie-lines between them were broken.”

According to estimates provided in AES’ filing, utility-scale solar installations over 50 megawatts on the island could cost between $40 and $50 per megawatt-hour. Those prices make solar located near load centers an economic alternative to the island’s fossil-fuel generating plants. The utility’s analysis showed that a 10,000-megawatt solar system could replace 12,000 gigawatt-hours of fossil generation, with 25 gigawatt-hours of battery storage leveling out load throughout the day. Puerto Rico’s peak load is 3,000 megawatts.

In other filings, PR-SEIA urged a restructuring of FEMA funds so they’re available for microgrid development. GridWise Alliance wrote that plans should consider cybersecurity, and AEMA recommended the commission develop an integrated resource plan (IRP) that includes distributed energy resources, microgrids and non-wires alternatives.

An air of optimism, though 1.5 million are still without power

After the commission completes the microgrid rulemaking, a new IRP is next on the commission’s to-do list. PREPA must file that plan in July, and regulators are working furiously to make sure it incorporates the recent flood of rebuilding recommendations from the energy industry.

Though the commission has the final say when it comes to approval of the plan, PREPA will lead the IRP process. The utility’s newly formed Transformation Advisory Council (TAC), a group of 11 energy experts, will contribute.

With that group, along with New York’s Resiliency Working Group, lessons from California's grid transition, the Energy Commission, the utility itself, and the dozens of other clean energy experts and entrepreneurs who want to offer their two cents, the energy planning process has a lot of moving parts. But according to Julia Hamm, CEO of the Smart Electric Power Alliance and a member of both the Energy Resiliency Working Group and the TAC, those working to establish standards for Puerto Rico’s future are hitting their stride.

“Certainly over the past three months, it has been a bit of a challenge to ensure that everybody has been coordinating efforts. Just over the past couple of weeks, we’ve seen some good progress on that front. We’re starting to see a lot more communication,” she said, adding that an air of optimism has settled on the process. “The key stakeholders all have a very common vision for Puerto Rico when it comes to the power sector.”

Nisha Desai, a PREPA board member who is liaising with the TAC, affirmed that collaborators are on the same page. “Everyone is violently in agreement that the future of Puerto Rico involves renewables, microgrids and distributed generation,” she said.

The TAC will hold its first in-person meeting in mid-January, and has already consulted with the utility on its formal fiscal plan submission, due January 10.

Though many taking part in the process feel the once-harried recovery is beginning to adopt a more organized approach, Desai acknowledges that “there are a lot of people in Puerto Rico who feel forgotten.”

Puerto Rico’s current generation sits at just 72.6 percent, in a nation facing longer, more frequent outages due to extreme weather. The government recently offered its first estimate that about half the island, 1.5 million residents, remains without power.

In late December and into January, 1,500 more crewmembers from 18 utilities in states as far flung as Minnesota, Missouri and Arizona will land on the island to aid further restoration through mutual aid agreements.

“The system is getting up to speed, getting to 100 percent, but there’s still some instability,” said Román Morales. “Right now it’s a matter of time.”

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US Electricity Sales Decline amid population growth and GDP gains, as DOE links reduced per capita consumption to energy efficiency, warmer winters, appliances, and bulbs, while hotter summers and rising AC demand may offset savings.

Key Points

US electricity sales fell 3% since 2010 despite population and GDP growth, driven by efficiency gains and warmer winters.

✅ DOE links drops to efficiency and warmer winters

✅ Per capita residential use fell about 7% since 2010

✅ Rising AC demand may offset winter heating savings

Since 2010, the United States has grown by 17 million people, and the gross domestic product (GDP) has increased by $3.6 trillion. Yet in that same time span, electricity sales in the United States actually declined by 3%, according to data released by the U.S. Department of Energy (DOE), even as electricity prices rose at a 41-year pace nationwide.

The U.S. decline in electricity sales is remarkable given that the U.S. population increased by 5.8% in that same time span. This means that per capita electricity use fell even more than that; indeed, the Department of Energy pegs residential electricity sales per capita as having declined by 7%, even as inflation-adjusted residential bills rose 5% in 2022 nationwide.

There are likely multiple reasons for this decline in electricity sales. Department of Energy analysts suggest that, at least in part, it is due to increased adoption of energy-efficient appliances and bulbs, like compact fluorescents. Indeed, the DOE notes that there is a correlation between consumer spending on “energy efficiency” and a reduction in per capita electricity sales, while utilities invest more in delivery infrastructure to modernize the grid.

Yet the DOE also notes that states with a greater increase in warm weather days had a corresponding decrease in electricity sales, as milder weather can reduce power demand across years. In southern states, the effect was most dramatic: for instance, from 2010 to 2016, Florida had a 56% decrease in cold weather days that would require heating and as a result, saw a 9% decrease in per capita electricity sales.

The moral is that warm winters save on electricity. But if global temperatures continue to rise, and summers become hotter, too, this decrease in winter heating spending may be offset by the increased need to run air conditioning in the summer, and given how electricity and natural gas prices interact, overall energy costs could shift. Indeed, it takes far more energy to cool a room than it does to heat it, for reasons related to the basic laws of thermodynamics. 

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UK Electricity Price Surge driven by wholesale gas costs, low wind output, and higher gas-fired generation, as National Grid boosts base load power to meet demand, lifting weekend prices toward decade highs.

Key Points

A sharp rise in UK power prices tied to gas spikes, waning wind, and higher reliance on gas-fired generation.

✅ Wholesale gas prices squeeze power, doubling weekend baseload.

✅ Wind generation falls to 3GW, forcing more gas-fired plants.

✅ Tariff hikes signal bill pressure and supplier strain.

The UK’s electricity market has followed the lead of surging wholesale gas prices this week to reach weekend highs, with UK peak power prices not seen in a decade across the market.

The power market has avoided the severe volatility which ripped through the gas market this week because strong winds helped to supply ample electricity to meet demand, reflecting recent record wind generation across the UK.

But as freezing winds begin to wane this weekend National Grid will need to use more gas-fired power plants to fill the gap, meaning the cost of generating electricity will surge.

Jamie Stewart, an energy expert at ICIS, said the price for base load power this weekend has already soared to around £80 per megawatt hour, almost double what one would expect to see for a weekend in March.

National Grid will increase its use of expensive gas-fired power by an extra 7GW to make up for low wind power, which is forecast to drop by two-thirds in the days ahead.

Wind speeds helped to protect the electricity system from huge price hikes on the neighbouring gas market on Thursday, by generating as much as 13GW by some estimates.

However, by the end of Friday this output will fall by almost half to 7GW and slump to lows of 3GW by Saturday, Mr Stewart said.

The power price was already higher than usual at £53/MWh last weekend even before the full force of the storms, including Storm Malik wind generation, hit Britain. That was still well above the more typical "mid-40s” price for this time of year, Mr Stewart added.

The twin price spikes across the UK’s energy markets has raised fears of household bill hikes in the months ahead, even as an emergency energy plan is not going ahead.

Late on Thursday Big Six supplier E.on quietly pushed through a dual-fuel tariff increase of 2.6%, to drive the average bill up to £1,153 from 19 April.

Energy supply minnow Bulb also increased prices by £24 a year for its 300,000 customers, blaming rising wholesale costs.

The UK has suffered two gas price shocks this winter, which is the first since the owner of British Gas shuttered the country’s largest gas storage facility at Rough off the Yorkshire coast.

A string of gas supply outages this week cut supplies to the UK just as freezing conditions drove demand for gas-heating a third higher than normal for this time of year.

It was the first time in almost ten years that National Grid was forced to issue a short supply warning to the market that supplies would fall short of demand unless factories agree to use less.

The twelve-year market price highs followed a pre-Christmas spike when the UK’s most important North Sea pipeline shut down at the same time as a deadly explosion at Europe’s most important gas hub, based in the Austrian town of Baumgarten.

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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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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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Site C Dam Electricity Demand underscores B.C.'s decarbonization path, enabling electrification of EVs, heat pumps, and industry, aligning with BC Hydro forecasts and 2030/2050 GHG targets to supply dependable, renewable baseload power.

Key Points

Projected clean power tied to Site C, driven by B.C. electrification to meet 2030 and 2050 greenhouse gas targets.

✅ Aligns with 25-30% by 2030 and 55-70% by 2050 GHG cuts

✅ Supports EVs, heat pumps, and industrial electrification

✅ Provides dependable baseload alongside efficiency gains

There are valid reasons not to build the Site C dam. There are also valid reasons to build it. One of the latter is the rapid increase in clean electricity needed to reduce B.C.’s greenhouse gas emissions from burning natural gas, gasoline, diesel and other harmful fossil fuel products.

Although former Premier Christy Clark casually avoided near-term emissions targets, Prime Minister Justin Trudeau has set Canadian targets for both 2030 and 2050, and cleaning up Canada's electricity is critical to meeting them. Studies by my research group at Simon Fraser University and other independent analysts show that B.C.’s cost-effective contribution to these national targets requires us to reduce our emissions 25 to 30 per cent by 2030 and 55 to 70 per cent by 2050 — an energy evolution involving, among other things, a much greater use of electricity in buildings, vehicles and industry.

Recent submissions to the Site C hearing have offered widely different estimates of B.C.’s electricity demand in the decade after the project’s completion in 2025, some arguing the dam’s output will be completely surplus to domestic need for years and perhaps decades, even though improved B.C.-Alberta grid links could help balance regional demand. Some of this variation in demand forecasts is understandable. Industrial demand is especially difficult to predict, dependent as it is on global economic conditions and shifting trade relations. And there are legitimate uncertainties about B.C. Hydro’s ability to reduce electricity demand by promoting efficient products and behaviour through its Power Smart program. But some of the forecasts appear to be deliberate exaggerations, designed to support fixed positions for or against Site C.

Our university-based research team models the energy system changes required to meet national and provincial emissions targets, and we have been comparing estimates of the electricity demand implications. These estimates are produced by academics, as well as by key institutions like B.C. Hydro, the National Energy Board, and the governments of Canada and B.C.

Most electricity forecasts for B.C., including the most recent by B.C. Hydro, do not assume that B.C. reduces its greenhouse gas emissions by 25 to 30 per cent by 2030 and 55 to 70 per cent by 2050. When we adjust Hydro’s forecast for just the low end of these targets, we find that in its latest, August 30, submission to the Site C hearing, which followed the premier’s over-budget go-ahead on the project, Hydro has underestimated the demand for its electricity by about three terawatt-hours in 2025, four in 2030 and 10 in 2035. Hydro’s forecast indicates that it will need the five terawatt-hours from Site C. Our research shows that even if Hydro’s demand forecast is too high, appropriate climate policy nationally and in B.C. will absorb all the electricity the dam can produce soon after its completion.

B.C. Hydro does not forecast electricity demand to 2050. But, studies by us and others show that B.C. electricity demand will be almost double today’s levels if we are to reduce emissions by 55 to 70 per cent, even amid a documented risk of missing the 2050 target, in just over three decades while our population, economy, buildings and equipment grow significantly. Most mid- and small-sized vehicles will be electric. Most buildings will be well insulated and heated by electric resistance or electric heat-pumps, either individually or via district heating systems. And many low temperature industrial applications will be electric.

Aggressive efforts to promote energy efficiency will make an important contribution, such that energy demand will not grow nearly as fast as the economy. But it is delusional to think that humans will stop using energy. Even climate policy scenarios in which we assume unprecedented success with energy efficiency show dramatic increases in the consumption of electricity, this being the most favoured zero-emission form of energy as a replacement for planet-destroying gasoline and natural gas.

The completion of the Site C dam is a complicated and challenging societal choice, and delay-related cost risks highlighted by the premier underscore the stakes. There is unbiased evidence and argument supporting either completion or cancellation. But let’s stick to the unbiased evidence. In the case of our 2030 and 2050 greenhouse gas reduction targets, such evidence shows that we must substantially increase our generation of dependable electricity. If the Site C dam is built, and if we are true to our climate goals, all its electricity will be used in B.C. soon after completion.

Mark Jaccard is a professor of sustainable energy in the School of Resource and Environmental Management at Simon Fraser University.

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