Powering India: feeding an insatiable need

India Renewable Energy Surge 2024 signals coal's decline as solar and wind capacity soar, aided by policy incentives, grid upgrades, energy storage, and falling costs, accelerating decarbonization and clean power growth.

Key Points

Q1 2024 saw renewables outpace coal in new capacity, led by cheaper solar, wind, policy support, and storage.

✅ 71.5% of new Q1 capacity came from renewables

✅ Solar and wind expand on falling costs and faster permitting

✅ Grid integration needs storage, skills, and just transition

In a landmark shift for the world's second-most populous nation, coal has finally been dethroned as the king of India's energy supply. The first quarter of 2024 saw a historic surge in renewable energy capacity, particularly on-grid solar development across states, pushing its share of power generation past 71.5%. This remarkable feat marks a turning point in India's journey towards a cleaner and more sustainable energy future.

For decades, coal has been the backbone of India's power sector, fueling rapid economic growth but also leading to concerning levels of air pollution. However, a confluence of factors has driven this dramatic shift, even as coal generation surges create short-term fluctuations in the mix. Firstly, the cost of solar and wind power has plummeted in recent years, making them increasingly competitive with coal. Secondly, the Indian government has set ambitious renewable energy targets, aiming for 50% of cumulative power generation capacity from non-fossil fuel sources by 2030. Thirdly, growing public awareness about the environmental impact of coal has spurred a demand for cleaner alternatives.

This surge in renewables is not just about replacing coal. The first quarter of 2024 witnessed a record-breaking addition of 13,669 megawatts (MW) of power generation capacity, with renewables accounting for a staggering 71.5% of that figure, aligning with 30% global renewable electricity milestones seen worldwide. This rapid expansion is driven by factors like falling equipment costs, streamlined permitting processes, and attractive government incentives. Solar and wind energy are leading the charge, and in other major markets renewables are projected to reach one-fourth of U.S. generation in the near term, with large-scale solar farms and wind turbine installations dotting the Indian landscape.

The transition away from coal presents both opportunities and challenges. On the positive side, cleaner air will lead to significant health benefits for millions of Indians. Additionally, India can establish itself as a global leader in the renewable energy sector, attracting investments and creating new jobs, echoing how China's solar PV expansion reshaped markets in the previous decade. However, challenges remain. Integrating such a large amount of variable renewable energy sources like solar and wind into the grid requires robust energy storage solutions. Furthermore, millions of jobs in the coal sector need to be transitioned to new opportunities in the green economy.

Despite these challenges, India's move towards renewables is a significant development with global implications, as U.S. renewable electricity surpassed coal in 2022, underscoring broader momentum. It demonstrates the growing viability of clean energy solutions and paves the way for other developing nations to follow suit. India's success story can inspire a global shift towards a more sustainable energy future, one powered by the sun, wind, and other renewable resources.

Looking ahead, continued government support, technological advancements, and innovative financing mechanisms will be crucial for sustaining India's renewable energy momentum. The future of India's energy sector is undoubtedly bright, fueled by the clean and abundant power of the sun and the wind, as wind and solar surpassed coal in the U.S. in recent comparisons. The world will be watching closely to see if India can successfully navigate this energy transition, setting an example for other nations struggling to balance development with environmental responsibility.

Related News

• Electricity Forum News

• Renewable Energy News

Energy Pricing Factors span electricity generation, transmission, and distribution costs, plus natural gas supply-demand, renewables, seasonal peaks, and wholesale pricing effects across residential, commercial, and industrial customers, usage patterns, weather, and grid constraints.

Key Points

They are the costs and market forces driving electricity and natural gas prices, from generation to delivery and demand.

✅ Generation, transmission, distribution shape electricity rates

✅ Gas prices hinge on supply, storage, imports/exports

✅ Demand shifts: weather, economy, and fuel alternatives

There are a lot of factors that affect energy prices globally. What’s included in the price to heat homes and supply them with electricity may be a lot more than some people may think.

Electricity
Generating electricity is the largest component of its price, according to the U.S. Energy Information Administration (EIA). Generation accounts for 56% of the price of electricity, while distribution and transmission account for 31% and 13% respectively.

Homeowners and businesses pay more for electricity than industrial companies, and U.S. electricity prices have recently surged, highlighting broader inflationary pressures. This is because industrial companies can take electricity at higher voltages, reducing transmission costs for energy companies.

“Industrial consumers use more electricity and can receive it at higher voltages, so supplying electricity to these customers is more efficient and less expensive. The price of electricity to industrial customers is generally close to the wholesale price of electricity,” EIA explains.

NYSEG said based on the average use of 600 kilowatt-hours per month, its customers spent the most money on delivery and transition charges in 2020, 57% or about $42, and residential electricity bills increased 5% in 2022 after inflation, according to national data. They also spent on average 35% (~$26) on supply charges and 8% (~$6) on surcharges.

Electricity prices are usually higher in the summer. Why? Because energy companies use sources of electricity that cost more money. It used to be that renewable sources, like solar and wind, were the most expensive sources of energy but increased technological advances have changed this, according to the International Energy Agency’s 2021 World Energy Outlook.

“In most markets, solar PV or wind now represents the cheapest available source of new electricity generation. Clean energy technology is becoming a major new area for investment and employment – and a dynamic arena for international collaboration and competition,” the report said.

Natural gas
The price of natural gas is driven by supply and demand. If there is more supply, prices are generally lower. If there is not as much supply, prices are generally higher the EIA explains. On the other side of the equation, more demand can also increase the price and less demand can decrease the price.

High natural gas prices mean people turn their home thermostats down a few degrees to save money, so the EIA said reduced demand can encourage companies to produce more natural gas, which would in turn help lower the cost. Lower prices will sometimes cause companies to reduce their production, therefore causing the price to rise.

The three major supply factors that affect prices: the amount of natural gas produced, how much is stored, and the volume of gas imported and exported. The three major demand factors that affect price are: changes in winter/summer weather, economic growth, and the broader energy crisis dynamics, as well as how much other fuels are available and their price, said EIA.

To think the price of natural gas is higher when the economy is thriving may sound counterintuitive but that’s exactly what happens. The EIA said this is because of increases in demand.

Related News

• Electricity Forum News

• Energy Policy News

U.S. Utility Spending Shift highlights rising transmission and distribution costs, grid modernization, and smart meters, while generation expenses decline amid fuel price volatility, capital and labor pressures, and renewable integration across the power sector.

Key Points

A decade-long trend where utilities spend more on delivery and grid upgrades, and less on electricity generation costs.

✅ Delivery O&M, wires, poles, and meters drive rising costs

✅ Generation spending declines amid fuel price changes and PPI

✅ Grid upgrades add reliability, resilience, and renewable integration

Over the past decade, major utilities in the United States have been spending more on delivering electricity to customers and less on producing that electricity, a shift occurring as electricity demand is flat across many regions.

After adjusting for inflation, major utilities spent 2.6 cents per kilowatthour (kWh) on electricity delivery in 2010, using 2020 dollars. In comparison, spending on delivery was 65% higher in 2020 at 4.3 cents/kWh, and residential bills rose in 2022 as inflation persisted. Conversely, utility spending on power production decreased from 6.8 cents/kWh in 2010 (using 2020 dollars) to 4.6 cents/kWh in 2020.

Utility spending on electricity delivery includes the money spent to build, operate, and maintain the electric wires, poles, towers, and meters that make up the transmission and distribution system. In real 2020 dollar terms, spending on electricity delivery increased every year from 1998 to 2020 as utilities worked to replace aging equipment, build transmission infrastructure to accommodate new wind and solar generation amid clean energy transition challenges that affect costs, and install new technologies such as smart meters to increase the efficiency, reliability, resilience, and security of the U.S. power grid.

Spending on power production includes the money spent to build, operate, fuel, and maintain power plants, as well as the cost to purchase power in cases where the utility either does not own generators or does not generate enough to fulfill customer demand. Spending on electricity production includes the cost of fuels including natural gas prices alongside capital, labor, and building materials, as well as the type of generators being built.

Other utility spending on electricity includes general and administrative expenses, general infrastructure such as office space, and spending on intangible goods such as licenses and franchise fees, even as electricity sales declined in recent years.

The retail price of electricity reflects the cost to produce and deliver power, the rate of return on investment that regulated utilities are allowed, and profits for unregulated power suppliers, and, as electricity prices at 41-year high have been reported, these components have drawn increased scrutiny.

In 2021, demand for consumer goods and the energy needed to produce them has been outpacing supply, though power demand sliding in 2023 with milder weather has also been noted. This difference has contributed to higher prices for fuels used by electric generators, especially natural gas. The increased cost for fuel, capital, labor, and building materials, as seen in the U.S. Bureau of Labor Statistics’ Producer Price Index, is increasing the cost of power production for 2021. U.S. average electricity prices have been higher every month of this year compared with 2020, according to our Monthly Electric Power Industry Report.

Related News

• Electricity Forum News

• Energy Policy News

California Rooftop Solar Rate Reforms propose shifting net metering to fixed access fees, peak-demand charges, and time-of-use pricing, aligning grid costs, distributed generation incentives, and retail rates for efficient, least-cost electricity and fair cost recovery.

Key Points

Policies replacing net metering with fixed fees, demand charges, and time-of-use rates to align costs and incentives.

✅ Large fixed access charge funds grid infrastructure

✅ Peak-demand pricing reflects capacity costs at system peak

✅ Time-varying rates align marginal costs and emissions

The California Public Service Commission has proposed revamping electricity rates for residential customers who produce electricity through their rooftop solar panels. In a recent New York Times op‐​ed, former Governor Arnold Schwarzenegger argued the changes pose an existential threat to residential rooftop solar. Interest groups favoring rooftop solar portray the current pricing system, often called net metering, in populist terms: “Net metering is the one opportunity for the little guy to get relief, and they want to put the kibosh on it.” And conventional news coverage suggests that because rooftop solar is an obvious good development and nefarious interests, incumbent utilities and their unionized employees, support the reform, well‐​meaning people should oppose it. A more thoughtful analysis would inquire about the characteristics and prices of a system that supplies electricity at least cost.

Currently, under net metering customers are billed for their net electricity use plus a minimum fixed charge each month. When their consumption exceeds their home production, they are billed for their net use from the electricity distribution system (the grid) at retail rates. When their production exceeds their consumption and the excess is supplied to the grid, residential consumers also are reimbursed at retail rates. During a billing period, if a consumer’s production equaled their consumption their electric bill would only be the monthly fixed charge.

Net metering would be fine if all the fixed costs of the electric distribution and transmission systems were included in the fixed monthly charge, but they are not. Between 66 and 77 percent of the expenses of California private utilities do not change when a customer increases or decreases consumption, but those expenses are recovered largely through charges per kWh of use rather than a large monthly fixed charge. Said differently, for every kWh that a PG&E solar household exported into the grid in 2019, it saved more than 26 cents, on average, while the utility’s costs only declined by about 8 cents or less including an estimate of the pollution costs of the system’s fossil fuel generators. The 18‐​cent difference pays for costs that don’t change with variation in a household’s consumptions, like much of the transmission and distribution system, energy efficiency programs, subsidies for low‐​income customers, and other fixed costs. Rooftop solar is so popular in California because its installation under a net metering system avoids the 18 cents, creating a solar cost shift onto non-solar customers. Rooftop solar is not the answer to all our environmental needs. It is simply a form of arbitrage around paying for the grid’s fixed costs.

What should electricity tariffs look like? This article in Regulation argues that efficient charges for electricity would consist of three components: a large fixed charge for the distribution and transmission lines, meter reading, vegetation trimming, etc.; a peak‐​demand charge related to your demand when the system’s peak demand occurs to pay for fixed capacity costs associated with peak use; and a charge for electricity use that reflects the time‐ and location‐​varying cost of additional electricity supply.

Actual utility tariffs do not reflect this ideal because of political concerns about the effects of large fixed monthly charges on low‐​income customers and the optics of explaining to customers that they must pay 50 or 60 dollars a month for access even if their use is zero. Instead, the current pricing system “taxes” electricity use to pay for fixed costs. And solar net metering is simply a way to avoid the tax. The proposed California rate reforms would explicitly impose a fixed monthly charge on rooftop solar systems that are also connected to the grid, a change that could bring major changes to your electric bill statewide, and would thus end the fixed‐​cost avoidance. Any distributional concerns that arise because of the effect of much larger fixed charges on lower‐​income customers could be managed through explicit tax deductions that are proportional to income.

The current rooftop solar subsidies in California also should end because they have perverse incentive effects on fossil fuel generators, even as the state exports its energy policies to neighbors. Solar output has increased so much in California that when it ends with every sunset, natural gas generated electricity has to increase very rapidly. But the natural gas generators whose output can be increased rapidly have more pollution and higher marginal costs than those natural gas plants (so called combined cycle plants) whose output is steadier. The rapid increase in California solar capacity has had the perverse effect of changing the composition of natural gas generators toward more costly and polluting units.

The reforms would not end the role of solar power. They would just shift production from high‐​cost rooftop to lower‐​cost centralized solar production, a transition cited in analyses of why electricity prices are soaring in California, whose average costs are comparable with electricity production in natural gas generators. And they would end the excessive subsidies to solar that have negatively altered the composition of natural gas generators.

Getting prices right does not generate citizen interest as much as the misguided notion that rooftop solar will save the world, and recent efforts to overturn income-based utility charges show how politicized the debate remains. But getting prices right would allow the decentralized choices of consumers and investors to achieve their goals at least cost.

Related News

• Electricity Forum News

• Energy Policy News

Germany net-zero roadmap charts coal phase-out by 2030, rapid renewables buildout, energy storage, and hydrogen-ready gas engines to cut emissions and lower LCOE by 34%, unlocking a resilient, flexible, low-cost power system by 2040.

Key Points

Plan to phase out coal by 2030 and gas by 2040, scaling renewables, storage, and hydrogen to cut LCOE and emissions.

✅ Coal out by 2030; gas phased 2040 with hydrogen-ready engines

✅ Add 19 GW/yr renewables; 30 GW storage by 2040

✅ 34% lower LCOE, 23% fewer emissions vs slower path

Germany can achieve significant reductions in emissions and the cost of electricity by phasing out coal in 2030 under its coal phase-out plan but must have a clear plan to ramp up renewables and pivot to sustainable fuels in order to achieve net-zero, according to a new whitepaper from Wartsila.

The modelling, published in Wärtsilä new white paper ‘Achieving net-zero power system in Germany by 2040’, compares the current plan to phase out coal by 2030 and gas by 2045 with an accelerated plan, where gas is phased out by 2040. By accelerating the path to net-zero, Germany can unlock a 34% reduction in the levelised cost of energy, as well as a 23% reduction in the total emissions, or 562 million tonnes of carbon dioxide in real terms.

The modelling offers a clear, three-step roadmap to achieve net-zero: rapidly increase renewables, energy storage and begin future-proofing gas engines in this decade; phase out coal by 2030; and phase out gas by 2040, converting remaining engines to run on sustainable fuels.

The greatest rewards are available if Germany front-loads decarbonisation. This can be done by rapidly increasing renewable capacity, adding 19 GW of wind and solar PV capacity per year. It must also add a total of 30GW of energy storage by 2040.

Håkan Agnevall, President and CEO of Wärtsilä Corporation said: “Germany stands on the precipice of a new, sustainable energy era. The new Federal Government has indicated its plans to consign coal to history by 2030. However, this is only step one. Our white paper demonstrates the need to implement a three-step roadmap to achieve net-zero. It is time to put a deadline on fossil fuels and create a clear plan to transition to sustainable fuels.”

While a rapid coal phase-out has been at the centre of recent climate policy debates, including the ongoing nuclear debate over Germany’s energy mix, the pathway to net-zero is less clear. Wärtsilä’s modelling shows that gas engines should be used to accelerate the transition by providing a short-term bridge to enable net zero and navigate the energy transition while balancing the intermittency of renewables until sustainable fuels are available at scale.

However, if Germany follows the slower pathway and reaches net-zero by 2045, it risks becoming reliant on gas as baseload power for much of the 2030s amid renewable expansion challenges that persist, potentially harming its ability to reach its climate goals. 

Creating the infrastructure to pivot to sustainable fuels is one of the greatest challenges facing the German system. The ability to convert existing capacity to run purely on hydrogen via hydrogen-ready power plants will be key to reaching net-zero by 2040 and unlocking the significant system-wide benefits on offer.

Jan Andersson, General Manager of Market Development in Germany, Wärtsilä Energy added: “To reach the 2040 target and unlock the greatest benefits, the most important thing that Germany can do is build renewables now. 19 GW is an ambitious target, but Germany can do it. History shows us that Germany has been able to achieve high levels of renewable buildout in previous years. It must now reach those levels consistently.

“Creating a clear plan which sets out the steps to net zero is essential. Renewable energy is inherently intermittent, so flexible energy capacity will play a vital role. While batteries provide effective short-term flexibility, gas is currently the only practical long-term option. If Germany is to unlock the greatest benefits from decarbonisation, it must have a clear plan to integrate sustainable fuel. From 2030, all new thermal capacity must run solely on hydrogen.”

Analysis of the last decade demonstrates that the rapid expansion of renewable energy is possible, and that renewables overtook coal and nuclear in generation. Previously, Germany has built large amounts of renewable capacity, including 8GW of solar PV in 2010 and 2011, 5.3 GW of onshore wind in 2017, and 2.5 GW of offshore wind in 2015.

The significant reductions in the cost of electricity demonstrated in the modelling are driven by the fact that renewables are far cheaper to run than coal or gas plants, even as coal still provides about a third of electricity in Germany. The initial capital investment is far outweighed by the ongoing operational expense of fossil fuel-based power.

As well as reducing emissions and costs, Germany’s rapid path to net-zero can also unlock a series of additional benefits. If coal is phased out by 2030 but capacity is not replaced by high levels of renewable energy, Germany risks becoming a significant energy importer, peaking at 162 TWh in 2035. The accelerated pathway would reduce imports by a third.

Likewise, more renewable energy will help to electrify district heating, meaning Germany can move away from carbon-intensive fuels sooner. If Germany follows the accelerated path, 57% of Germany’s heating could be electrified in 2045, compared to 10% under the slower plan.

Jan Andersson concluded: “The opportunities on offer are vast. Germany can provide the blueprint for net zero and galvanise an entire continent. Now is the time for the new government to seize the initiative.”

Related News

• Electricity Forum News

• Power Generation News

FortisAlberta COVID-19 response delivers safe electricity distribution across Alberta, with remote monitoring, 24/7 support, outage alerts, dispersed crews, and business continuity measures to sustain essential services for customers and communities.

Key Points

Plan ensuring reliable electricity in Alberta through 24/7 support, remote monitoring, outage alerts, and dispersed crews.

✅ 24/7 customer support via 310-WIRE and mobile app

✅ Remote monitoring and rapid outage restoration

✅ Dispersed crews in 50 communities for faster response

As the COVID-19 pandemic continues to evolve in Alberta (and around the world), FortisAlberta is taking the necessary actions and precautions informed by utility disaster planning to protect the health and well-being of its employees and to provide electricity service to its customers. FortisAlberta serves more than half a million customers with the electricity they depend on to take care of their families and community members throughout our province.

"We recognize these are challenging times as while most Albertans are asked to stay home others continue to work in the community to provide essential services, including utility workers in Ontario demonstrating support efforts. As your electricity distribution provider, please be assured you can count on us to do what we do best – provide our customers with safe and reliable electricity service wherever and whenever they need it," says Michael Mosher, FortisAlberta President and CEO.

FortisAlberta is proud to be a part of the communities it serves and commits to keeping the lights on for its customers. The company is providing a full range of services for its customers and has instilled best practices within critical parts of its business. The company's control centre continues to remotely monitor, control, and restore, where possible, the delivery of power across the entire province, including during events such as an Alberta grid alert that stress the system. Early in March, FortisAlberta implemented its business continuity plan and the company remains fully accessible to customers 24/7 by phone at 310-WIRE (9473) or through its mobile app where customers can report outages online or view details of an outage. Customers can also sign up for outage alerts to their mobile phone and/or email address to let them know if an outage does occur.

FortisAlberta's power line employees are geographically dispersed across 50 different communities so they can quickly address any issues that may arise. The company has implemented work from home measures and isolation best practices, and is planning for potential on-site lockdowns where necessary to ensure no disruption to customers.

FortisAlberta will continue to remain in close communication with its stakeholders to provide updates to customers and with industry associations to share guidance specific to the electricity sector, including insights on the evolving U.S. grid response to COVID-19 from peer utilities. FortisAlberta will also continue to invest in and empower its communities by contributing to organizations that offer programs and services aligned with the greatest needs in the communities it serves.

With the Alberta Government's recent announcement to provide relief to eligible Albertans by deferring electricity and gas charges for up to 90 days, similar to some B.C. relief measures being implemented, FortisAlberta is committed to working with stakeholders and retail partners to ensure this option is available to customers quickly and efficiently, and to learn from initiatives like the Hydro One relief fund that support customers.

Related News

• Electricity Forum News

• Utility Operations News