German Energy Demand Hits Historic Low Amid Economic Stagnation

Noncarbon Electricity Investment Strategy helps utilities hedge policy uncertainty, carbon tax risks, and emissions limits by scaling wind, solar, and CCS, avoiding stranded assets while balancing costs, reliability, and climate policy over decades.

Key Points

A strategy for utilities to invest 20-30 percent of capacity in low carbon sources to hedge emissions and carbon risks.

✅ Hedges future carbon tax and emissions limits

✅ Targets 20-30 percent of new generation from clean sources

✅ Reduces stranded asset risk and builds renewables capacity

When utility executives make decisions about building new power plants, a lot rides on their choices. Depending on their size and type, new generating facilities cost hundreds of millions or even billions of dollars. They typically will run for 40 or more years — 10 U.S. presidential terms. Much can change during that time.

Today one of the biggest dilemmas that regulators and electricity industry planners face is predicting how strict future limits on greenhouse gas emissions will be. Future policies will affect the profitability of today’s investments. For example, if the United States adopts a carbon tax 10 years from now, it could make power plants that burn fossil fuels less profitable, or even insolvent.

These investment choices also affect consumers. In South Carolina, utilities were allowed to charge their customers higher rates to cover construction costs for two new nuclear reactors, which have now been abandoned because of construction delays and weak electricity demand. Looking forward, if utilities are reliant on coal plants instead of solar and wind, it will be much harder and more expensive for them to meet future emissions targets, even as New Zealand's electrification push accelerates abroad. They will pass the costs of complying with these targets on to customers in the form of higher electricity prices.

With so much uncertainty about future policy, how much should we be investing in noncarbon electricity generation in the next decade? In a recent study, we proposed optimal near-term electricity investment strategies to hedge against risks and manage inherent uncertainties about the future.

We found that for a broad range of assumptions, 20 to 30 percent of new generation in the coming decade should be from noncarbon sources such as wind and solar energy across markets. For most U.S. electricity providers, this strategy would mean increasing their investments in noncarbon power sources, regardless of the current administration’s position on climate change.

Many noncarbon electricity sources — including wind, solar, nuclear power and coal or natural gas with carbon capture and storage — are more expensive than conventional coal and natural gas plants. Even wind power, which is often mentioned as competitive, is actually more costly when accounting for costs such as backup generation and energy storage to ensure that power is available when wind output is low.

Over the past decade, federal tax incentives and state policies designed to promote clean electricity sources spurred many utilities to invest in noncarbon sources. Now the Trump administration is shifting federal policy back toward promoting fossil fuels. But it can still make economic sense for power companies to invest in more expensive noncarbon technologies if we consider the potential impact of future policies.

How much should companies invest to hedge against the possibility of future greenhouse gas limits? On one hand, if they invest too much in noncarbon generation and the federal government adopts only weak climate policies throughout the investment period, utilities will overspend on expensive energy sources.

On the other hand, if they invest too little in noncarbon generation and future administrations adopt stringent emissions targets, utilities will have to replace high-carbon energy sources with cleaner substitutes, which could be extremely costly.

Economic modeling with uncertainty

We conducted a quantitative analysis to determine how to balance these two concerns and find an optimal investment strategy given uncertainty about future emissions limits. This is a core choice that power companies have to make when they decide what kinds of plants to build.

First we developed a computational model that represents the sectors of the U.S. economy, including electric power. Then we embedded it within a computer program that evaluates decisions in the electric power sector under policy uncertainty.

The model explores different electric power investment decisions under a wide range of future emissions limits with different probabilities of being implemented. For each decision/policy combination, it computes and compares economy-wide costs over two investment periods extending from 2015 to 2030.

We looked at costs across the economy because emissions policies impose costs on consumers and producers as well as power companies. For example, they may lead to higher electricity, fuel or product prices. By seeking to minimize economy-wide costs, our model identifies the investment decision that produces the greatest overall benefits to society.

More investments in clean generation make economic sense

We found that for a broad range of assumptions, the optimal investment strategy for the coming decade is for 20 to 30 percent of new generation to be from noncarbon sources. Our model identified this as the best level because it best positions the United States to meet a wide range of possible future policies at a low cost to the economy.

From 2005-2015, we calculated that about 19 percent of the new generation that came online was from noncarbon sources. Our findings indicate that power companies should put a larger share of their money into noncarbon investments in the coming decade.

While increasing noncarbon investments from a 19 percent share to a 20 to 30 percent share of new generation may seem like a modest change, it actually requires a considerable increase in noncarbon investment dollars. This is especially true since power companies will need to replace dozens of aging coal-fired power plants that are expected to be retired.

In general, society will bear greater costs if power companies underinvest in noncarbon technologies than if they overinvest. If utilities build too much noncarbon generation but end up not needing it to meet emissions limits, they can and will still use it fully. Sunshine and wind are free, so generators can produce electricity from these sources with low operating costs.

In contrast, if the United States adopts strict emissions limits within a decade or two, they could prevent carbon-intensive generation built today from being used. Those plants would become “stranded assets” — investments that are obsolete far earlier than expected, and are a drain on the economy.

Investing early in noncarbon technologies has another benefit: It helps develop the capacity and infrastructure needed to quickly expand noncarbon generation. This would allow energy companies to comply with future emissions policies at lower costs.

Seeing beyond one president

The Trump administration is working to roll back Obama-era climate policies such as the Clean Power Plan, and to implement policies that favor fossil generation. But these initiatives should alter the optimal strategy that we have proposed for power companies only if corporate leaders expect Trump’s policies to persist over the 40 years or more that these new generating plants can be expected to run.

Energy executives would need to be extremely confident that, despite investor pressure from shareholders, the United States will adopt only weak climate policies, or none at all, into future decades in order to see cutting investments in noncarbon generation as an optimal near-term strategy. Instead, they may well expect that the United States will eventually rejoin worldwide efforts to slow the pace of climate change and adopt strict emissions limits.

In that case, they should allocate their investments so that at least 20 to 30 percent of new generation over the next decade comes from noncarbon sources. Sustaining and increasing noncarbon investments in the coming decade is not just good for the environment — it’s also a smart business strategy that is good for the economy.

Related News

• Electricity Forum News

• Climate Change News

Crouching Yeti APT targets energy infrastructure with watering-hole attacks, compromising servers to steal credentials and stage intrusions; Kaspersky Lab links the Energetic Bear group to ICS threats across Russia, US, Europe, and Turkey.

Key Points

Crouching Yeti APT, aka Energetic Bear, is a threat group that targets energy firms using watering-hole attacks.

✅ Targets energy infrastructure via watering-hole compromises

✅ Uses open-source tools and backdoored sshd for persistence

✅ Scans global servers to stage intrusions and steal credentials

A hacker collective known for attacking industrial companies around the world have had some of their infrastructure identified by Russian security specialists.

Kaspersky Lab said that it has discovered a number of servers compromised by the group, belonging to different organisations based in Russia, the US, and Turkey, as well as European countries.

The Russian-speaking hackers, known as Crouching Yeti or Energetic Bear, mostly focus on energy facilities, as seen in reports of infiltration of the U.S. power grid targeting critical infrastructure, for the main purpose of stealing valuable data from victim systems.

Hacked servers

Crouching Yeti is described as an advanced persistent threat (APT) group that Kaspersky Lab has been tracking since 2010.

#google#

Kaspersky Lab said that the servers it has compromised are not just limited to industrial companies. The servers were hit in 2016 and 2017 with different intentions. Some were compromised to gain access to other resources or to be used as intermediaries to conduct attacks on other resources.

Others, including those hosting Russian websites, were used as watering holes.

It is a common tactic for Crouching Yeti to utilise watering hole attacks where the attackers inject websites with a link redirecting visitors to a malicious server.

“In the process of analysing infected servers, researchers identified numerous websites and servers used by organisations in Russia, US, Europe, Asia and Latin America that the attackers had scanned with various tools, possibly to find a server that could be used to establish a foothold for hosting the attackers’ tools and to subsequently develop an attack,” said the security specialists in a blog posting.

“The range of websites and servers that captured the attention of the intruders is extensive,” the firm said. “Kaspersky Lab researchers found that the attackers had scanned numerous websites of different types, including online stores and services, public organisations, NGOs, manufacturing, etc.

Kaspersky Lab said that the hackers used publicly available malicious tools, designed for analysing servers, and for seeking out and collecting information. The researchers also found a modified sshd file with a preinstalled backdoor. This was used to replace the original file and could be authorised with a ‘master password’.

“Crouching Yeti is a notorious Russian-speaking group that has been active for many years and is still successfully targeting industrial organisations through watering hole attacks, among other techniques,” explained Vladimir Dashchenko, head of vulnerability research group at Kaspersky Lab ICS CERT.

Russian government?

“Our findings show that the group compromised servers not only for establishing watering holes, but also for further scanning, and they actively used open-sourced tools that made it much harder to identify them afterwards,” he said.

“The group’s activities, such as initial data collection, the theft of authentication data, and the scanning of resources, are used to launch further attacks,” said Dashchenko. “The diversity of infected servers and scanned resources suggests the group may operate in the interests of the third parties.”

This may well tie into a similar conclusion from a rival security vendor.

In 2014 CrowdStrike claimed that the ‘Energetic Bear’ group was also tracked in Symantec's Dragonfly research and had been hacking foreign companies on behalf of the Russian state.

The security vendor had said the group had been carrying out attacks on foreign companies since 2012, with reports of breaches at U.S. power plants that underscored the campaign, and there was evidence that these operations were sanctioned by the Russian government.

Last month the United States for the first time publicly accused Russia in a condemnation of Russian grid hacking of attacks against the American power grid.

Symantec meanwhile warned last year of a resurgence in cyber attacks on European and US energy companies, including reports of access to U.S. utility control rooms that could result in widespread power outages.

And last July the UK’s National Cyber Security Centre (NCSC) acknowledged it was investigating a broad wave of attacks on companies in the British energy and manufacturing sectors.

Related News

• Electricity Forum News

• Grid Technologies News

Hong Kong Electricity Tariff Increase reflects a projected 1-2% rise as HK Electric and CLP Power shift to cleaner fuel and natural gas, expand gas-fired units and LNG terminals, and adjust the fuel clause charge.

Key Points

An expected 1-2% 2018 rise from cleaner fuel, natural gas projects, asset growth, and shrinking fuel cost surpluses.

✅ Expected 1-2% rise amid cleaner fuel and gas shift

✅ Fuel clause charge and asset expansion pressure prices

✅ HK Electric and CLP Power urged to use surpluses prudently

Hong Kong customers have been asked to expect higher electricity bills next year, as seen with BC Hydro rate increases in Canada, with a member of a government panel on energy policy anticipating an increase in tariffs of one or two per cent.

The environment minister, Wong Kam-sing, also hinted they should be prepared to dig deeper into their pockets for electricity, as debates over California electric bills illustrate, in the wake of power companies needing to use more expensive but cleaner fuel to generate power in the future.

HK Electric supplies power to Hong Kong Island, Lamma Island and Ap Lei Chau. Photo: David Wong

The city’s two power companies, HK Electric and CLP Power, are to brief lawmakers on their respective annual tariff adjustments for 2018, amid Ontario electricity price pressures drawing international attention, at a Legislative Council economic development panel meeting on Tuesday.

HK Electric supplies electricity to Hong Kong Island and neighbouring Lamma Island and Ap Lei Chau, while CLP Power serves Kowloon and the New Territories, including Lantau Island.

Wong said on Monday: “We have to appreciate that when we use cleaner fuel, there is a need for electricity tariffs to keep pace. I believe it is the hope of mainstream society to see a low-carbon and healthier environment.”

Secretary for the Environment Wong Kam-sing believes most people desire a low-carbon environment. Photo: Sam Tsang

But he declined to comment on how much the tariffs might rise.

World Green Organisation chief executive William Yu Yuen-ping, also a member of the Energy Advisory Committee, urged the companies to better use their “overflowing” surpluses in their fuel cost recovery accounts.

Tariffs are comprised of two components: a basic amount reflecting a company’s operating costs and investments, and the fuel clause charge, which is based on what the company projects it will pay for fuel for the year.

William Yu of World Green Organisation says the companies should use their surpluses more carefully. Photo: May Tse

Critics have claimed the local power suppliers routinely overestimate their fuel costs and amass huge surpluses.

In recent years, the two managed to freeze or cut their tariffs thanks to savings from lower fuel costs. Last year, HK Electric offered special rebates to its customers, which saw its tariff drop by 17.2 per cent. CLP Power froze its own charge for 2017.

Yu said the two companies should use the surpluses “more carefully” to stabilise tariffs.

Rise after fall in Hong Kong electricity use linked to subsidies

“We estimate a big share of the surplus has been used up and so the honeymoon period is over.”

Based on his group’s research, Yu believed the tariffs would increase by one or two per cent.

Economist and fellow committee member Billy Mak Sui-choi said the expansion of the power companies’ fixed asset bases, such as building new gas-fired units and offshore liquefied natural gas terminals, a pattern reflected in Nova Scotia's 14% rate hike recently approved by regulators, would also cause tariffs to rise.

To fight climate change and improve air quality, the government has pledged to cut carbon intensity by between 50 and 60 per cent by 2020. Officials set a target of boosting the use of natural gas for electricity generation to half the total fuel mix from 2020.

Both power companies are privately owned and monitored by the government through a mutually agreed scheme of control agreements, akin to oversight seen under the UK energy price cap in other jurisdictions. These require the firms to seek government approval for their development plans, including their projected basic tariff levels.

At present, the permitted rate of return on their net fixed assets is 9.99 per cent. The deals are due to expire late next year.

Earlier this year, officials reached a deal with the two companies on the post-2018 scheme, settling on a 15-year term. The new agreements slash their permitted rate of return to 8 per cent.

Related News

• Electricity Forum News

• Energy Policy News

Nuclear Power Construction Milestones spotlight EPR builds, Hualong One steam generators, APR-1400 grid integration, and VVER startups, with hot functional testing, hydrostatic checks, and commissioning advancing toward fuel loading and commercial operation.

Key Points

Key reactor project steps, from testing and grid readiness to startup, marking progress toward safe commercial operation.

✅ EPR units advance through cold and hot functional testing

✅ Hualong One installs 365-ton steam generators at Fuqing 5

✅ APR-1400 and VVER projects progress toward grid connection

The world’s nuclear power industry has been busy in the new year, with several construction projects, including U.S. reactor builds, reaching key milestones as 2018 began.

EPR Units Making Progress

Four EPR nuclear units are under construction in three countries: Olkiluoto 3 in Finland began construction in August 2005, Flamanville 3 in France began construction in December 2007, and Taishan 1 and 2 in China began construction in November 2009. Each of the new units is behind schedule and over budget, but recent progress may signal an end to some of the construction difficulties.

EDF reported that cold functional tests were completed at Flamanville 3 on January 6. The main purpose of the testing was to confirm the integrity of primary systems, and verify that components important to reactor safety were properly installed and ready to operate. More than 500 welds were inspected while pressure was held greater than 240 bar (3,480 psi) during the hydrostatic testing, which was conducted under the supervision of the French Nuclear Safety Authority.

With cold testing successfully completed, EDF can now begin preparing for hot functional tests, which verify equipment performance under normal operating temperatures and pressures. Hot testing is expected to begin in July, with fuel loading and reactor startup possible by year end. The company also reported that the total cost for the unit is projected to be €10.5 billion (in 2015 Euros, excluding interim interest).

Olkiluoto 3 began hot functional testing in December. Teollisuuden Voima Oyj—owner and operator of the site—expects the unit to produce its first power by the end of this year, with commercial operation now slated to begin in May 2019.

Although work on Taishan 1 began years after Olkiluoto 3 and Flamanville 3, it is the furthest along of the EPR units. Reports surfaced on January 2 that China General Nuclear (CGN) had completed hot functional testing on Taishan 1, and that the company expects the unit to be the first EPR to startup. CGN said Taishan 1 would begin commercial operation later this year, with Taishan 2 following in 2019.

Hualong One Steam Generators Installed

Another Chinese project reached a notable milestone on January 8. China National Nuclear Corp. announced the third of three steam generators had been installed at the Hualong One demonstration project, which is being constructed as Unit 5 at the Fuqing nuclear power plant.

The Hualong One pressurized water reactor unit, also known as the HPR 1000, is a domestically developed design, part of China’s nuclear program, based on a French predecessor. It has a 1,090 MW capacity. The steam generators reportedly weigh 365 metric tons and stand more than 21 meters tall. The first steam generator was installed at Fuqing 5 on November 10, with the second placed on Christmas Eve.

Barakah Switchyard Energized

In the United Arab Emirates, more progress has been made on the four South Korean–designed APR-1400 units under construction at the Barakah nuclear power plant. On January 4, Emirates Nuclear Energy Corp. (ENEC) announced that the switchyard for Units 3 and 4 had been energized and connected to the power grid, a crucial step in Abu Dhabi toward completion. Unit 2’s main power transformer, excitation transformer, and auxiliary power transformer were also energized in preparation for hot functional testing on that unit.

“These milestones are a result of our extensive collaboration with our Prime Contractor and Joint Venture partner, the Korea Electric Power Corporation (KEPCO),” ENEC CEO Mohamed Al Hammadi said in a press release. “Working together and benefitting from the experience gained when conducting the same work on Unit 1, the teams continue to make significant progress while continuing to implement the highest international standards of safety, security and quality.”

In 2017, ENEC and KEPCO achieved several construction milestones including installation and concrete pouring for the reactor containment building liner dome section on Unit 3, and installation of the reactor containment liner plate rings, reactor vessel, steam generators, and condenser on Unit 4.

Construction began on the four units (Figure 1) in July 2012, May 2013, September 2014, and September 2015, respectively. Unit 1 is currently undergoing commissioning and testing activities while awaiting regulatory review and receipt of the unit’s operating license from the Federal Authority for Nuclear Regulation, before achieving 100% power in a later phase. According to ENEC, Unit 2 is 90% complete, Unit 3 is 79% complete, and Unit 4 is 60% complete.

VVER Units Power Up

On December 29, Russia’s latest reactor to commence operation—Rostov 4 near the city of Volgodonsk—reached criticality, as other projects like Leningrad II-1 advance across the fleet, and was operated at its minimum controlled reactor power (MCRP). Criticality is a term used in the nuclear industry to indicate that each fission event in the reactor is releasing a sufficient number of neutrons to sustain an ongoing series of reactions, which means the neutron population is constant and the chain reaction is stable.

“The transfer to the MCRP allows [specialists] to carry out all necessary physical experiments in the critical condition of [the] reactor unit (RU) to prove its design criteria,” Aleksey Deriy, vice president of Russian projects for ASE Engineering Co., said in a press release. “Upon the results of the experiments the specialists will decide on the RU powerup.”

Rostov 4 is a VVER-1000 reactor with a capacity of 1,000 MW. The site is home to three other VVER units: Unit 1 began commercial operation in 2001, Unit 2 in 2010, and Unit 3 in 2015.

Related News

• Electricity Forum News

• Power Generation News

Canada Clean Electricity Exports leverage hydroelectric power, energy storage, and transmission interconnections to meet rising IEA-forecast demand, support electrification, decarbonize grids, and attract green finance with stable policy and advanced technology.

Key Points

Canada's cross-border power sales from hydro and renewables, enabled by storage, transmission, and supportive policy.

✅ Hydro leads generation; expand transmission interties to the US

✅ Deploy storage to balance wind and solar variability

✅ Streamline regulation and green finance to scale exports

As global electricity demand continues to surge, Canada finds itself uniquely positioned to capitalize on this expanding market by choosing an electric, connected and clean pathway that scales with demand. With its vast natural resources, advanced technology, and stable political environment, Canada can play a crucial role in meeting the world’s energy needs while also advancing its own economic interests.

The International Energy Agency (IEA) has projected that global electricity demand will grow significantly over the next decade, driven by factors such as population growth, urbanization, and the increasing electrification of various sectors, including transportation and industry. This presents a golden opportunity for Canada to bolster its energy security as it boasts an abundance of renewable energy sources, particularly hydroelectric power. Currently, hydroelectricity accounts for about 60% of Canada’s total electricity generation, making it one of the largest producers of this clean energy source in the world.

The growing emphasis on renewable energy aligns perfectly with Canada’s strengths, with the Prairie Provinces emerging as leaders in new wind and solar capacity across the country. As countries worldwide strive to reduce their carbon footprints and transition to greener energy solutions, Canada’s clean energy resources can be harnessed not only to meet domestic needs but also to export electricity to neighboring countries and beyond. The U.S., for instance, is already a significant market for Canadian electricity, with interconnections facilitating the flow of power across borders. Expanding these connections and investing in infrastructure could further increase Canada’s electricity exports.

Moreover, advancements in energy storage technology present another avenue for Canada to enhance its role in the global electricity market. With the rise of intermittent energy sources like wind and solar, the ability to store excess electricity generated during peak production times becomes essential. Canada’s expertise in technology and innovation positions it well to develop and deploy energy storage solutions that can stabilize the grid through grid modernization projects and ensure a reliable supply of electricity.

Additionally, Canada’s commitment to reducing greenhouse gas emissions and combating climate change aligns with the global shift towards sustainable energy. By investing in renewable energy projects and supporting research and development, Canada can not only meet its climate targets, including zero-emissions electricity by 2035, but also attract international investment. Green financing initiatives are becoming increasingly popular, and Canada can leverage its reputation as a leader in environmental stewardship to tap into this growing market.

However, to fully realize these opportunities, Canada must address some key challenges. Regulatory hurdles, infrastructure limitations, and the need for a coordinated national energy strategy are critical issues that must be navigated. Streamlining regulations and fostering collaboration between federal and provincial governments will be essential in creating a conducive environment for investment in renewable energy projects.

Furthermore, public acceptance and community engagement are vital components of developing new energy projects, especially where solar power adoption lags and outreach is needed. Ensuring that local communities benefit from these initiatives—whether through job creation, economic investment, or shared revenues—will help garner support and facilitate smoother project implementation.

In addition to domestic efforts, Canada should also position itself as a global leader in energy diplomacy. By collaborating with other nations to share best practices, technologies, and resources, Canada can strengthen its influence in international energy discussions. Engaging in multilateral initiatives aimed at addressing energy poverty and promoting sustainable development will not only enhance Canada’s standing on the world stage but also open doors for Canadian companies to expand their reach.

In conclusion, as the global demand for electricity rises, Canada stands at a crossroads, with a tremendous opportunity to lead in the clean energy sector. By leveraging its natural resources, investing in technology, and fostering international partnerships, Canada can not only meet its energy needs but also pursue zero-emission electricity by 2035 while positioning itself as a key player in the global electricity market. The path forward will require strategic planning, investment, and collaboration, but the potential rewards are significant—both for Canada and the planet.

Related News

• Electricity Forum News

• Renewable Energy News

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.”

Related News

• Electricity Forum News

• Grid Technologies News