Nuscale SMR costs jump to $119/MWh

From IEEFA

Last week, NuScale and the Utah Associated Municipal Power Systems (UAMPS) announced what many have long expected. The construction cost and target price estimates for the 462-megawatt (MW) small modular reactor (SMR) are going up, way up.

From 2016 to 2020, they said the target power price was $55/megawatt-hour (MWh). Then, the price was raised to $58/MWh when the project was downsized from 12 reactor modules to just six (924MW to 462MW). Now, after preparing a new and much more detailed cost estimate, the target price for the power from the proposed SMR has soared to $89/MWh.

Remarkably, the new $89/MWh price of power would be much higher if it were not for more than $4 billion in subsidies NuScale and UAMPS expect to get from U.S. taxpayers through a $1.4 billion contribution from the Department of Energy and the estimated $30/MWh subsidy in the Inflation Reduction Act (IRA).

It also is important to remember that the $89/MWh target price is in 2022 dollars and substantially understates what utilities and their ratepayers actually will pay if the SMR is completed. For example, assuming a modest 2% inflation rate through 2030, utilities and ratepayers would pay $102 for each MWh of power from the SMR—not the $89 NuScale and UAMPS want them to believe they will pay.

The 53% increase in the SMR’s target power price since 2021 has been driven by a dramatic 75% jump in the project’s estimated construction cost, which has risen from $5.3 billion to $9.3 billion. The new estimate makes the NuScale SMR about as expensive on a dollars-per-kilowatt basis ($20,139/kW) as the two-reactor Vogtle nuclear project currently being built in Georgia, undercutting the claim that SMRs will be cheap to build.

NuScale and UAMPS attribute the construction cost increase to inflationary pressure on the energy supply chain, particularly increases in the prices of the commodities that will be used in nuclear power plant construction.

For example, UAMPS says increases in the producer price index in the past two years have raised the cost of:

• Fabricated steel plate by 54%
• Carbon steel piping by 106%
• Electrical equipment by 25%
• Fabricated structural steel by 70%
• Copper wire and cable by 32%

In addition, UAMPS notes that the interest rate used for the project’s cost modeling has increased approximately 200 basis points since July 2020. The higher interest rate increases the cost of financing the project, raising its total construction cost.

Assuming the commodity price increases cited by NuScale and UAMPS are accurate, the prices of building all the SMRs that NuScale is marketing—and, indeed, of all of the SMR designs currently being marketed by any company—will be much higher than has been acknowledged, and the prices of the power produced by those SMRs will be much more expensive.

Finally, as we’ve previously said, no one should fool themselves into believing this will be the last cost increase for the NuScale/UAMPS SMR. The project still needs to go through additional design, licensing by the U.S. Nuclear Regulatory Commission, construction and pre-operational testing. The experience of other reactors has repeatedly shown that further significant cost increases and substantial schedule delays should be anticipated at any stages of project development.

The higher costs announced last week make it even more imperative that UAMPS and the utilities and communities participating in the project issue requests for proposal (RFP) to learn if there are other resources that can provide the same power, energy and reliability as the SMR but at lower cost and lower financial risk. History shows that this won’t be the last cost increase for the SMR project.

The problem with this analysis is that renewable costs have also risen (see chart from Lazards' latest LCOE calculations below).  Supply chain difficulties because of Covid, the Ukraine War, China's Covid lockdowns, "onshoring" (returning manufacturing to your own country, to reduce supply chain difficulties) and rising interest rates have increased wind and solar costs for the first time in decades.   And, presumably, as we improve the supply chain, these costs will fall.   Also, if more NuScale's SMRs can be built, unit costs will fall, in a classic learning curve feedback loop.

We may well need SMRs at high latitudes, while SMRs even in lower latitudes will add to grid security, because the more different sources of electricity available to the grid, the more balanced and secure it is.  It would be a pity not to at least try NuScale's SMRs, given the strong possibility that component prefabrication will cut costs compared to the hugely expensive giant nuclear power plants which are a decade behind schedule everywhere.  

I have said before that if nuclear is necessary for de-carbonising the world's electricity grid, I would grit my teeth and support it, because the climate emergency is so severe.  But the problems with nuclear remain:  expense and delay.  This SMR will only start operating in 2030, if there are no further delays.  By then, if we are to avoid an increase in global temperatures since pre-industrial times of more than 1.5 degrees C, we will need to have increased the share of renewables in the grid to 80%.  The last 20% will be the hardest to de-carbonise.   SMRs may be necessary for that.   

Source: Lazards
Click on graphic to see clearer image

The ill-fated Petra Nova carbon capture project

Source: ResearchGate

From IEEFA

NRG Energy Inc. just sold its 50 percent stake in the world’s largest carbon capture plant for only about $3.6 million, less than a half-percent of the Texas project’s roughly $1 billion construction costs. The sale leaves JX Nippon Oil & Gas Exploration Corp. as the sole owner of the 240-MW coal-fired Petra Nova power plant.

S&P Market Intelligence described the deal as “a setback for supporters of carbon-capture projects at existing fossil fuel plants.” It is far more.

The U.S. Department of Energy (DOE) sank $195 million into the carbon capture and storage (CCS) plant, hoping to demonstrate the potential for the technology to counteract greenhouse gas emissions of coal plants. The NRG fire sale of its half of the project is a declaration that the taxpayer investment was a technological failure and a financial loss.

The U.S. government needs to ask hard questions about investing more taxpayer dollars in CCS for coal plants. The CCS technology used in the Petra Nova project was not new. The DOE called it “proven.” But it did not work as well as promised. Other CCS projects attempted at power plants have failed, as well.

The Petra Nova facility began operations in 2017. The CCS equipment was installed to capture CO2 from a slipstream of the W.A. Parish Unit 8’s flue gas. The captured CO2 traveled via 80-mile pipeline to an oilfield near Houston for use in enhanced oil recovery (EOR) operations to increase extraction. Petra Nova’s target CCS capture rate was 90 percent. NRG claims it met the target.

But Petra Nova’s owners have never provided the actual data behind that claim. Emissions data for Parish Unit 8 reported to the EPA suggests the actual CO2 capture rate was substantially lower than 90%, perhaps as low as 65% to 70%. And the average capture rate does not include emissions from the gas-fired combustion turbine used to power the facility. Adding those emissions lowers the overall on-site capture rate to perhaps as low as 55% to 58%.

Petra Nova also was expected to be in operation some 85% of the time but failed to meet its target because so many technical problems and so much downtime were experienced—not just in the CCS facility and in Parish Unit 8, but also in the CO2 pipeline and the oilfield where the captured CO2 was injected. Similar problems can be expected to affect any carbon capture project, especially at an aging coal plant.

The unit was taken offline in May 2020 and remains down. JX Nippon now says it anticipates bringing Petra Nova back online in the second quarter of 2023 but has not provided an exact schedule or cost estimate.

Methane emissions from the mining of coal, which have received too little attention to date, also weren’t reported. Using the coal-fired San Juan Generating Station as an example, IEEFA found that even if a CCS system could achieve 95 percent capture rate from the plant—which based on IEEFA’s research is not at all likely—taking the coal mining methane emissions into account would drop the actual capture rate to 72 percent.

IEEFA observed in a 2020 report that NRG Energy recorded three impairment charges related to the plant and to Petra Nova Parish Holdings, a subsidiary. The charges, recorded in 2016, 2017 and 2019, totaled $310 million. NRG Energy had written off essentially all its investment in the project. This is striking, given that Petra Nova not only benefitted from the U.S. Energy Department’s $195 million grant but also had received $250 million in concessionary lending from the Japan Bank for International Cooperation (JBIC) and Mizuho Bank, Ltd.

The actual costs of carbon capture at Petra Nova have never been officially released. An assistant DOE secretary for fossil energy said at a June 2020 webinar that the cost of carbon capture would need to drop by half, to $30 per metric ton, to be commercially viable. Since Petra Nova was the department’s flagship carbon capture project at the time, the comment may be an indication that the cost of carbon capture may have been $60 per ton, but it is not clear. Also, the figure did not include the costs to compress the CO2 for pipeline transport, or the pipeline transport and underground injection costs.

Southern Co.’s Kemper CCS project was designed to gasify lignite (a soft coal formed from peat) and capture the carbon before combustion. The cost initially was estimated at $3 billion, but it ballooned to $7.5 billion. Also, the project’s coal gasification process did not operate reliably during pre-operational testing, and the CCS capture portion of the project was scrapped. The unit now runs solely on natural gas with no CO2 controls.

IEEFA’s recent review of carbon capture efforts in other countries found similar problems abound. It concluded that using carbon capture to extend the life of fossil fuels power plants is a significant financial and technical risk.

Recommendation: Stop taking U.S. taxpayers for a ride on a CCS money guzzler

The U.S. government must sharply scrutinize all claims made by applicants for federal dollars to promote CCS technology. IEEFA research indicates that the technology is far from proven. Claims of high capture rates are meaningless when:The claimed high capture rates for CCS have not been sustained on an annual and multi-year basis;
The data needed to verify Petra Nova’s claim of a 90% capture rate at any point has not been made public;
The technology does not capture all air pollution emission streams from the site;
The upstream extraction or mining emissions are not taken into account; and
The downstream emissions from the plant and from the use of captured CO2 for EOR are not considered.

Given the amount of funds involved and the exposure of taxpayer dollars to risk, the U.S. government must implement robust due diligence and get beyond the advertising hype to the actual facts about carbon capture technology. It should not tolerate any more wasteful Petra Nova debacles.

Global offshore wind investment up 52% in H1 2022

From IEEFA

Investment in the offshore wind sector in the first half of this year amounted to USD 32 billion, 52 per cent more than in the same period in 2021, according to BloombergNEF (BNEF).

The financing of the 1 GW China Three Gorges (CTG) Yangjiang Yangxi Shapa Qingzhouwu Offshore Wind Farm for USD 2.1 billion was the largest deal during this period, BNEF’s report says.

The increase in offshore wind investment comes on the heels of newly approved projects and a rise in governmental efforts to up the share of renewable energy in national energy mixes.

“Investments in 2022 will flow into projects coming online in the next few years as the offshore wind installed base is set to grow tenfold from 53GW in 2021 to 504GW in 2035. Offshore wind projects enable companies and governments to make progress towards their decarbonization goals at scale”, said Chelsea Jean-Michel, offshore wind analyst at BNEF.

“The United Kingdom, France and Germany are just a few of the countries that have increased their offshore wind targets in the first half of 2022, signaling further support for investment in the technology”.

In the renewable energy sector, global investment reached USD 226 billion in the first half of 2022, an 11% year-on-year rise, setting a new record for the first six months of a year, according to BNEF’s Renewable Energy Investment Tracker 2H 2022.

[Adrijana Buljan]

More: Global Offshore Wind Investment Up 52 Pct in First Half of 2022

 

Offshore wind is less variable than onshore wind, but is also more expensive.

A 50% increase is substantial, yet overall investment in renewables rose only 11%.  And emissions/temperatures continue to rise.

California reaches record renewable output

 From IEEFA

California's solar and wind farms generated record volumes of renewable energy in the first half of 2022, producing at times more carbon-free electricity than the world's fifth-largest economy could consume.

Cutbacks [curtailments] of available wind and solar output on the California ISO transmission network, covering most of the Golden State and a sliver of Nevada, surged 79% in the first six months of the year to a record 2,063 GWh [2.1 TWh], according to an S&P Global Commodity Insights analysis of grid operator data.

The nearly 2.1 TWh of wind and solar curtailments in this year's first half, compared with roughly 1.2 TWh in the first half of 2021, mark a return to fast-expanding periodic excesses of CAISO-connected renewable energy after tighter market conditions in 2021 interrupted their rapid growth in 2020 and 2019.

The six-month total was 30% more than the prior annual high of 1,587 GWh curtailed in 2020. The first-half volume of idled renewable energy was also more than the combined net output of California's single largest solar and wind farms in 2021, according to S&P Market Intelligence data. Berkshire Hathaway Energy's 586-MW Topaz Solar Farm in San Luis Obispo County, Calif., and Pattern Energy Group Inc.'s 265-MW Ocotillo Wind Energy Facility in Imperial County, Calif., together generated about 1,740 GWh last year.

[Garrett Hering]

What could California do with its excess renewable electricity?  

1. Sell it to neighbouring states.  But their economies and populations are much smaller than California's.  The largest relatively close market is Texas, but for political reasons, Texas refuses connection to the US grid.
2. Store it using batteries.  California's battery banks are growing fast, but not fast enough to absorb this quantity of electricity.
3. Use it to make green hydrogen which can then be exported to other countries, either as Hydrogen, or, more effectively as methane or ammonia.
4. Live with curtailment.  Renewables are so cheap that we can afford excess capacity.

Terra-Gen’s 560MWh Valley Center Battery Storage Project, San Diego, California, which came online last month. Image: Terra-Gen.
Source: Battery storage load shifting up to 6GWh a day on CAISO grid

One terawatt of renewables waiting for connection

 From IEEFA

There was almost 1TW of renewable energy capacity and an estimated 427GW of storage active in US interconnection queues at the end of 2021 according to a Lawrence Berkeley National Laboratory (LBNL) analysis, which also showed that queues were growing year-on-year.

In total, over 930GW of zero-carbon generating capacity is currently seeking transmission access. Solar accounts for a record 676GW of this generation – beating the previous record of 462GW at the end of 2020 – and wind power makes up 247GW. Fossil fuels looking to connect are on the decline, however, with 75GW of natural gas and less than 1GW of coal currently proposed.  

Solar and battery storage are by far the fastest growing resources in the queues – together accounting for 85% of new capacity entries in 2021 –  but have some of the lowest completion rates, LBNL said. Clean energy organisations have long been calling for system reform to help more solar and storage get connected.

Meanwhile, hybrid projects comprise a large and growing share of proposed capacity, particularly in CAISO and the non-ISO West, LBNL said, adding that 286GW of solar hybrids (primarily solar-plus-battery storage) and 19GW of wind hybrids are currently active in the queues.

“Nearly half of the battery storage capacity in the queues is paired with some form of generation (mostly solar),” LBNL said.

[Sean Rai-Roche]

Solar and storage have some of the worst interconnection rates, while wait times for all forms of power generations are on the rise. Image: Unsplash.

Private sector driving renewables in India

 From IEEFA

Climate change – witnessed increasingly in extreme weather events – is now the biggest risk threatening energy and financial markets, and vulnerable people and communities.

The International Panel on Climate Change (IPCC) Sixth Assessment Report, Climate Change 2021 warns that to maintain the trajectory of 1.5 degrees Celsius by 2040, immediate urgent action must be taken.

To mitigate this climate risk, India has set ambitious targets for renewable energy.

The government has recognised that free solar and wind energy, backed up by batteries, and other clean technologies such as electric vehicles and green hydrogen, are necessary alternatives to increasingly obsolete high emitting fossil fuel generation plants – coal, LNG and gas.

At COP26 in Glasgow, Prime Minister Narendra Modi announced 500 gigawatts (GW) of non-fossil fuel capacity and 50% of energy from renewable sources by 2030 coupled with a net zero target of 2070.

The response has been promising, and has brought forward increased competition in the traditionally coal-dominated energy market.

As a result, India’s energy supply growth is now being led by renewable energy capacity additions.

Further, that supply growth is being led by private sector players, despite initially being led by the public sector. Large power producers with coal constituting a large part of their portfolios, including Adani Group, Jindal and Tata Power, have announced big renewable energy targets and investment to match.

What caused the private sector to shift their focus to renewables?

India faced coal shortages from August to October 2021 which led to high prices at the power exchange. Then in January 2022 Indonesia announced a coal export ban. The crisis exposed price volatility and energy security risks for India, showing imported coal as an unreliable source of electricity generation that is heavily dependent on a long supply chain.

The largest business houses in the country responded by changing tack, turning their attention to cheaper, cleaner, reliable renewable energy. It shows economics are driving such decisions, coupled with the return on investment being much higher for renewable energy projects.

Globally, there has been significant global capital momentum away from thermal coal and coal-fired power generation in the last few years. In total, IEEFA has tracked 193 globally significant banks, insurers, and asset managers/owners that have implemented substantial formal coal exit policies since 2013. The year 2021 saw 51 new or updated policy statements.

This capital flow is a reflection of the rapidly diminishing economic merits of thermal coal and the growing understanding that alignment with the Paris Agreement and 1.5 degrees Celsius invariably leaves many coal projects as stranded assets, unable to deliver a viable return over their useful life. A flood of international capital is vying for renewable energy assets and the pool of economic, social and governance (ESG) led investors is growing rapidly.

While India has the potential to attract a large part of this capital, the flows have not been sizeable to date due to concerns about “greenwashing” and the overhang of legacy thermal assets on the books of major players such as NTPC and Tata Power. That trajectory however is changing following recent big announcements for renewable energy deployment in the next few years.

In July 2021, Tata Power announced it would not build new coal-fired generation projects and is aiming for carbon neutrality by 2050. One week later JSW, another leading thermal power producer, announced 20GW of solar, wind and hydropower plants by March 2030 and an investment of Rs750 billion (US$10 billion) with the aim of also becoming carbon neutral by 2050.

In fact, 2021 saw a sharp increase in renewable energy investment domestically and globally. India attracted about ~US$18.8 billion of that investment in renewable energy – three times the investment seen in 2020.

The share price performance of these companies indicates they are making the right moves by turning to renewables. Over a five-year period, Adani Green Energy Limited has risen massively by 6,000% and Reliance by 350% vis-à-vis a 110% rise in Sensex.

Private players are now building the ecosystem by increasing domestic manufacturing of solar modules, cells, wafers, and polysilicon, while reducing reliance on imports.

In October 2021, Reliance acquired REC Group of Norway for US$771 million. REC is a long-established solar module manufacturer with two facilities in Norway for making solar grade polysilicon and one in Singapore making PV cells and modules. Reliance has further invested US$29 million in German solar wafer manufacturer NexWafe GmbH and is entering a strategic partnership to commercialise NexWafe’s product in India.

Private players are now also betting big on green hydrogen (the only ‘renewable’ hydrogen) which will assist in decarbonising other sectors like refining, fertiliser, and steel.

Reliance has partnered with renewables pioneer Henrik Stiesdal to develop and manufacture hydrogen electrolysers. And Adani Group and Ballard Power Systems have joined hands to evaluate a joint investment in hydrogen fuel cells manufacturing in India. Green hydrogen is considered to be the fuel of the future and IEEFA notes fuel cell manufacturing will likely be a game-changer in India’s energy transition.

Private capital and power producers reeling under the burden of non-performing thermal assets are driving a course correction. Apart from the 30GW already under construction, no new thermal projects are likely to come online in India.

Renewable energy momentum is continuing and with the increasing competitiveness of ever-cheaper battery storage and unfolding new energy technologies, that momentum will likely escalate to a two-threefold increase in the growth of renewable energy by 2024.

[This article was published by ET Energyworld.com.]

So far as I can make out, these are gross not net additions.
Taking  retirements into account, total coal capacity is therefore prolly falling.

Renewables to reach 30% by 2026

 From IEEFA

Data for the first eight months of 2021 show that wind generation has risen more than 25 percent since 2019 (pushing its market share to almost 9 percent) while utility-scale solar generation has jumped 55 percent (pushing its market share to nearly 3 percent). Combined, wind and utility-scale solar generation has gone up by 76 million megawatt-hours (MWh)—a 31 percent increase—while coal and gas generation has fallen by 1.6 percent since 2019, reflecting the ongoing transition of electricity markets to renewable energy and away from fossil fuels.

But an even bigger surge in renewable generation is coming soon. IEEFA estimates that by the end of 2026—just five years from now—wind and utility-scale solar will generate roughly 850 million MWh of electricity annually, equal to more than 21 percent of total 2020 demand.

The increase in utility-solar generation in the past two years was driven by the installation of roughly 22,500 megawatts of new capacity. The Solar Energy Industries Association now expects utility-scale installations to average more than 21,000MW a year through 2026, with a peak of 25,000MW in 2023.

These new solar projects could be generating an additional 283 million MWh of power a year by the end of 2026—more than triple the full-year 2020 level of 90.1 million MWh—for a total of 374 million MWh. Assuming that total U.S. electricity demand remains essentially flat, as it has since 2010, this would push solar’s share of overall demand to about 9.3 percent. In terms of capacity, the buildout will add roughly 129.5 gigawatts (GW) of utility-scale solar generation to the U.S. grid

Continued growth is also expected in U.S. wind generation, with 37.7GW of new capacity already under construction or in advanced development, which would be added to 127.8GW in existing installed capacity. The new wind power could add 138.7 million MWh of electricity a year, an increase of 41 percent by 2026, and pushing wind’s total to 476 million MWh.

For these generation estimates, IEEFA assumed conservative capacity factors of 25 percent for new utility-scale solar and 42 percent for new wind. Capacity factors reflect how much of the maximum potential generation is actually produced. Every type of power source, including fossil fuels, has its own unique limitations, and most operate in response to variable demand and competitive markets.

For anyone that doubts such a wind and solar buildout is possible, consider what happened between 2001 and 2006—even before the huge volumes of cheap gas from the fracking boom arrived. In that short period of time, the U.S. added close to 200GW of gas-fired capacity to its then much-smaller grid, with about 133GW of that being combined cycle gas turbine facilities.

The current boom in utility-scale solar and wind is similar—but probably bigger and more durable. Solar projects are being built in nearly every corner of the country, by a multitude of independent developers, utilities and communities, and can range in scale from a megawatt in power covering a few acres to those in the hundreds of megawatts covering a square mile or more. Likewise, major wind projects continue to be built across the Great Plains from Texas to Wyoming, but the enormous potential of offshore wind from North Carolina to Massachusetts is just beginning to be developed.

30% renewables by 2026 is better than nothing.  But it's still not enough.  To halve emissions by 2030, renewables need to provide more than 80% of electricity generated by then. 

Price tag for Vogtle reactors surges past $30 billion

 From IEEFA

Once estimated at more than $14 billion, the price tag for two new reactors at Georgia Power Company’s Plant Vogtle site has now climbed past $30 billion, and both units will be more than six years late in coming online, according to a report by the Institute for Energy Economics and Financial Analysis.

The Georgia Public Service Commission staff and its nuclear consultants have attributed the project’s massive cost overruns and repeated delays to Georgia Power’s adoption of unreasonable and unachievable construction schedules, as well as its attempts to achieve the schedules at any cost. The issues have been blamed on a corporate culture that values production over quality; poor or non-existent quality inspections; high personnel turnover; and high testing failure rates for an unproven reactor design.

“The company was warned back in 2008 that using a new unproven reactor design from Westinghouse for the new Vogtle reactors was likely to lead to cost overruns and major schedule delays,” said David Schlissel, the report’s author and IEEFA’s director of resource planning and analysis. “However, the company challenged and the commission disregarded these warnings.”

Last year was difficult for the Vogtle project. Even though the project costs have risen rapidly, the projected online date has slipped over the last year at a rate of roughly one month per calendar month of work. As of January 2021, Georgia Power estimated it would need $2.5 billion more to finish building the new reactors. However, after spending $1.9 billion during the first nine months of the year, it increased its estimate for completing the job to almost $2.7 billion.

“There is clear evidence that Vogtle 3 and 4 will be very expensive sources of power,” Schlissel said. “Our analysis found the costs of power from Vogtle 3 and 4 will be five times as expensive as the same amount of electricity obtained from renewable sources, such as a solar-plus-battery-storage facility.”

But Georgia’s utility customers won’t only be paying for the new Vogtle units for the 60 years after they go into service. Customers have already paid more than $3.5 billion in financing costs for the project since 2011, or more than 11 years before either of the new units will produce any electricity for them. The public service commission staff expects the figure will grow to $4 billion by the time the two units are completed.

“Georgia Power has repeatedly misled the public service commission and its staff about the project’s likely cost and schedule and the costs to customers will be extremely high,” Schlissel said. “The commission denied rate recovery for $951 million of the cost overruns at Vogtle 1 and 2; it should deny rate recovery for a much larger share of the far more expensive Vogtle 3 and 4.”

It isn't just Vogtle 3 & 4.  Large GW-scale nuclear power stations are everywhere over budget and delayed.

What we can learn from South Australia's renewables revolution

 From WEForum

It’s one-and-a-half times bigger than the US state of Texas, almost as big as Egypt and has a population of 1.7 million people. The state of South Australia is also a global leader in the use of renewable energy.

The use of renewable energy will play a crucial part in helping the world hit the targets set at the Paris Climate Agreement to tackle climate change, including halting the increase in the global average temperature to well below 2C above pre-industrial levels and working to limit the temperature increase to 1.5C above pre-industrial levels.

The progress made by South Australia could help the rest of the world find a faster route to a successful energy transition, according to a report from the Institute for Energy Economics and Financial Analysis (IEEFA).

Called A Grid Dominated by Wind and Solar Is Possible, South Australia: A Window Into the Future, here are seven takeaways from the report.

1. Most - and sometimes all - annual demand can be met by wind and solar.

The South Australia state government set a 2020 target of getting 26% of the state’s energy from renewables. It smashed that goal, with renewables delivering 60% of its energy needs. In October of that year, 100% of the state’s energy came from solar sources – just for one hour, but it marks an impressive turnaround for a region that was 100% reliant on fossil fuel as recently as 2006.

Key to its success has been a commitment to a mix of renewable sources, the IEEFA says. “South Australia therefore provides valuable lessons for the rest of the world, showing what is possible with variable renewable energy (VRE) and distributed energy resources (DER) integration.”

2. Renewables adoption can be driven by government policy and market features.

South Australia is known for its sunshine and reliably strong winds. But having a lot of sun doesn’t automatically mean a lot of solar power. For that, there needs to be the right legislative processes in place. The Australian federal government introduced its Renewable Energy Target (RET) in 2001, along with a Renewable Energy Certification scheme aimed at encouraging new installations. “Many early projects incentivized by [RET] were installed in South Australia as the market was attractive to investors and developers,” the IEEFA report says.

3. Ambitious plans can spark economic growth.

The South Australian government has set its sights on producing 500% of its energy from renewables by 2050 and becoming a net exporter of greener power.

The neighbouring states of New South Wales and Victoria are among its intended targets, IEEFA says, with additional plans to export “green hydrogen, green steel and other low emissions products internationally”.

Such a goal lead to new investments grid transmission capacity, renewable energy infrastructure and green manufacturing capability, spurring change.

4. Renewables can help deliver sub-zero wholesale electricity prices.

Wholesale electricity prices for South Australia were the lowest in the Australian National Electricity Market in the final quarter of 2020. So low that the price of electricity fell to minus-$9 per megawatt hour (MWh) between 10am and 3.30pm during the first quarter of 2021. Not only has this enabled renewable companies to undercut traditional coal and gas generating businesses, it has “rapidly driven down wholesale electricity spot prices in line with the merit order effect (due to lower-cost electricity being available in the wholesale market), especially in the middle of the day when prices are often negative,” the report says.

5. Renewables grids can deliver system reliability and security.

“Overall South Australia has met its reliability standard for the past 15 years,” IEEFA says. The only exception was in 2008-09 when “extreme temperatures in Victoria and South Australia reduced the availability of the interconnector between the two states”.

Continuing to maintain supplies will mean having an infrastructure that can accommodate a larger number of generators and the distributed nature of energy resources, the report says. It cites 253 occasions when the Australian Energy Market Operator had to intervene in the market during 2019-20 (compared to 153 times in 2018-19) to direct “synchronous generators to maintain the system in a secure operating state”.

6. Batteries can support system reliability and energy security.

South Australia has four grid-scale batteries on-stream and two more being built. This includes the world’s largest battery energy storage system, according to IEEFA – the Hornsdale Power Reserve, which was installed in 2017 by Tesla and Neoen.

The report describes the Hornsdale battery as “a technical success, helping to keep the lights on when faults have occurred in the grid”. IEEFA also points out that the site has recouped its capital cost in just over two years of operation.

7. Distribution networks can adapt to support rooftop solar.

An estimated 40.3% of households in South Australia have rooftop solar panels. To ensure their safe and effective incorporation into the grid, the ebb and flow of electricity across the distributed network must be carefully managed.

Last year, South Australia introduced a regulation to enable operators to remotely disconnect rooftop solar inverters. This is not an approach favoured by IEEFA, the report points out. Instead, the organization recommends the use of dynamic operating envelopes or DOEs. “DOEs allow distributed energy resources to import and export within the constraints of distribution networks on a five-minute basis, set 24 hours in advance,” IEEFA says.

India new solar up 335%

 From IEEFA

India added over 7.4 gigawatts (GW) of solar power capacity in the first nine months of 2021, a 335 per cent year-on-year (y-o-y) increase compared to the 1.73 GW installed in the same period last year, according to a recent report.

While in the third quarter (Q3) of 2021, India added 2,835 megawatts (MW) of solar power capacity, up 14 per cent compared to 2,488 MW installed in Q2 2021. Y-o-y installations in Q3 surged 547 per cent, according to the report titled ‘Q3 2021 India Solar Market Update’ released by Mercom India Research.

“Despite supply challenges, the Indian solar market is headed towards one of the best years on record, and a complete turnaround from 2021, which was one of the worst years for solar due to COVID-19,” said Raj Prabhu, CEO, Mercom Capital Group.

The report further said that India added close to 11.6 GW of power capacity in the first nine months of 2021. Solar dominated capacity additions accounting for close to 60 per cent, followed by thermal power, which contributed 21 per cent. Renewables, including large hydro, made up 79 percent of total power capacity additions in the January-September period of 2021.

Source: Our World in Data
Solar provides just a small proportion of India's electricity generation
(note that the data are only up to 2019)
But the growth rate of that percentage is high: 5-fold in the 4 years to 2019.

Rooftop solar to meet 3/4 of demand by 2026

Rooftop solar, Australia

 From IEEFA

Rooftop solar systems are going to have such an impact in coming years that they will meet up to 77 per cent of total grid demand on occasions within five years, sending minimum operating [i.e., net] demand down to levels that had never been contemplated until recently.

The Australian Energy Market Operator says the pace of rooftop solar is increasing beyond its own expectations and homes and businesses will likely add at least another 8.9GW by 2025, on top of the existing capacity of 14GW.

This will have a major impact on prices, demand and the operations of the grid. These solar systems alone could supply up to 77% of total electricity demand at times by 2026 in the four mainland states that are part of the National Electricity Market (South Australia, Victoria, NSW and Queensland).

“As a result, minimum operational demand across the NEM mainland is expected to drop to a record low of 4 to 6GW by 2025, down from 15GW in 2019,” AEMO says.

This is a real Ozzie success story, which has happened despite the Right's slavish devotion to their fossil fuel masters.  And it happened because a leftish government introduced subsidies for small-scale/rooftop solar.    The subsidies drove rapid take-up, and this in turn drove down the before-subsidy costs in a classic learning curve virtuous cycle.  These days, one can put 5 kW of panels on one's roof for ± A$5000 (US$3500). It also made people aware of renewables; so much so, that when one talks about solar, everybody thinks one means rooftop solar.

The tremendous growth of rooftop solar (3 GW in 2020 alone) has meant that some aging poles-and-wires street infrastructure is stressed on sunny days, and the grid operators, ever alert for more cash, are trying to get a "solar charge" introduced because "it's not fair".  Ignoring of course that the wholesale price of electricity has been driven down by the jump in renewables in the system, reducing electricity costs for everyone, not just those with rooftop panels.   Meanwhile, on hot, sunny days, local solar actually saves the wider grid from being overloaded (and shutting down) when all the aircon units on individual houses are run., because typically, it's sunny when it's hot.  Duh.      

The obvious solution to overloading the poles and wires, which in fact existed when I put in my first set of solar panels a decade ago. is a smart meter, which disconnects the solar panels from the grid when the voltage on the local grid rises too high, stopping the grid from burning out.   

The key point I want to make though, is this: Australia went from zero solar to 77% (on sunny days) in little over a decade.  Similar subsidies and targets could drive behind-the-meter household storage to high enough levels to stabilise the grid; and also EVs to 100% of sales.  Within 15 years.  Subsidising/incentivising a technology which has a steep learning curve drives very rapid increases in installations.  Not gonna happen in Oz, given our troglodytic backward LNP government, so don't hold your breath.

Why Australia's coal subsidy was cooked up

 I talk here about the proposed "capacity payment" which is really just a horribly expensive coal subsidy.

The authors of the report I mention also wrote this article, which points out that most coal power stations will be loss-making by 2025.  The response of the government was the new coal subsidy plan.  There is a case for capacity payments, but they should only go to generators that can supply "dispatchable electricity", in other words, electricity supplies which can be rapidly ramped up and down, like gas, hydro and batteries, and unlike coal.

Coal-fired power stations in Australia’s National Electricity Market (NEM) will confront grave financial difficulties within the next 5 years due to extra competition from a large influx of renewable energy supply. 

The analysis detailed in this report suggests that the financial viability of several coal generators in the NEM will become severely compromised by 2025 such that closure becomes an attractive or even unavoidable choice for at least one power plant owner. An additional 28 gigawatts (GW), or 70,000GWh (annualised) of renewables is expected to be installed by 2025, compared to our 2018 baseline year. 

By 2025, it is forecast that the installed renewables capacity will be 8GW of utility scale solar, 12GW of wind, and 22GW of rooftop solar. Renewables is forecast to provide 40-50% of NEM 2025 demand. The additional renewable energy generation coming online from 2018 to 2025 will be enough to supply 99.9% of the Australian Energy Market Operator’s (AEMO) expected demand growth and 98% of the gap expected to be left from the Liddell power station retirement. Even after filling the demand growth and Liddell gap there will be surplus renewable generation of approximately 57,000GWh. 

As a result, coal and gas generators will be displaced in the wholesale market, due to the merit order effect. Renewable generators have extremely low operating costs (economically defined as short run marginal cost or SRMC) largely due to having no fuel costs (as wind and solar resources are free). Renewable generators can therefore bid into the market at prices close to zero, undercutting other generators on price. Increasing amounts of renewable installations therefore reduce the output of other generators with higher operating costs. 

We expect around three-quarters of gas generation and one-quarter of coal-generation to be replaced by renewable energy generation in the seven year period. The incoming renewables will also have a deflationary impact on wholesale electricity prices, further decreasing the profitability of existing plants. Coal plants will see a double hit to their electricity sales: both volume and price is forecast to decrease out to 2025. The considerable reduction in coal generation and wholesale electricity prices is expected to drive reduction in coal plant wholesale spot market earnings (Earnings Before Interest and Taxes or EBIT). 

Coal plants could suffer an estimated EBIT reduction of up to 119% comparing 2018 to 2025. In a scenario where prices in 2025 are the same as NEM-wide 2020 prices (Scenario A in our study), Eraring, Mt Piper and Vales Point B would be expected to be losing money. In a scenario where price reduces down below 2015 prices (Scenario B), Eraring, Mt Piper, Vales Point B, Gladstone and Yallourn W be making a loss. This is based on EBIT estimations in the case that the generators are, theoretically, fully spot market exposed (i.e. does not include contracts) and excludes revenue from other services such as FCAS.

With this magnitude of reduction in EBIT, coal generator exits are likely to occur far sooner than AEMO has planned for in its Integrated System Plan (ISP). Once a coal generator exits the market, the dynamics outlined in this study will change: prices are likely to then increase near term and other coal generators that remain online may benefit from increased revenue. Electricity sector investors are recognising that the plunging cost of solar, its rapid speed to deploy, and its vast popularity with investors and Australian householders has led to an irrevocable change in the shape of the electricity supply-demand curve and market that leaves inflexible and high fixed cost baseload coal plants ill-suited to the future grid. 

Unfortunately for investors in coal plants, while there remains plenty of evening demand after the sun sets, the amount of daytime demand is becoming so small that coal plants are left in a battle amongst each other to remain online. This is a serious problem for aging coal plants because once they switch off, it typically takes several hours to start back up again and then several more hours to be capable of reaching full output, and by then the evening peak demand window of opportunity has passed. In addition, such modes of operation place considerable stress on the components of a coal plant, increasing maintenance costs and reducing their life. 

Other dispatchable power plant technologies are much better suited to this new future, dominated by solar and wind, because they can ramp their output up and down more quickly and with less stress on their components. Given this context, the New South Wales Government’s Electricity Infrastructure Roadmap (2020) provides an essential and timely response to ensure coal plant capacity is replaced in advance of their exit. 

Supporting the findings in our report are that several energy market corporations have already substantially written-down the value of their generation assets or cancelled upgrade plans, as announced over February 2021: 

 Origin Energy has downgraded its energy market full year EBITDA by 8.6% (earnings before interest, taxes, depreciation, and amortization), blaming low wholesale prices and the drop in demand due to the pandemic 

 AGL has written down over $2.7 billion of value, due to reduced wholesale power prices, a failure to account for coal closure site rehabilitation and government plans to underwrite plants 

 More than $1 billion has been wiped off the value of Queensland government-owned fossil fuel generators as falling wholesale electricity prices slash generator profits. Profits generated by Queensland government-owned generators, including those controlled by Stanwell Corporation, CS Energy and CleanCo, fell by 88% in the 2019-20 financial year.  

 Delta Electricity, the owner of Vales Point coal plant, dropped its bid for an $8.7m publicly funded upgrade. 

This report has chosen to focus its analysis on coal plant profitability, as exit of coal plants has substantial implications for energy security, price and emissions outcomes but gas power plants will also suffer substantial deterioration in profits (exacerbated by recent dramatic hikes in gas prices). Yet this is partly mitigated by the fact that gas power plants tend to have lower fixed costs and much greater ability to ramp output up and down quickly. Peaking gas will thus play a role into the future, however the high short run marginal cost compared to renewables and batteries is likely to drive significant reduction in gas generation. 

Energy storage technologies such as batteries or pumped hydro have a feature that gas does not possess; they can take advantage of periods of plentiful sun or wind to replenish their storages at very low cost. This is in addition to having significantly faster ramping capabilities than gas plants, let alone coal power plants. Furthermore, for short peaks in demand batteries are already the lowest cost option for providing dispatchable capacity.  

It is expected batteries will play a growing role into the future due to ongoing technology improvements that have been characterised by double-digit percentage annual cost reductions. These physical and economic realities mean that efforts to keep inflexible coal plants afloat, let alone build new plants, are likely to be counter-productive in terms of both energy affordability and reliability as well as being contrary to both Federal and State Government’s commitments to address climate risk. Rather than seeking to delay or even deny the inevitable exit of coal, governments, as well as investors, need to be planning to replace them. 

Solar deployment to top one terawatt in 2022

 From IEEFA

Global solar installations could break the 1-terawatt mark in 2022, industry group SolarPower Europe said in its “Global Market Outlook” on July 21, despite rising raw-material costs that could create headwinds for the renewable energy industry. [ Offset by rises in fossil fuel prices: Coal price is up 3-fold over the last year; gas up 70%. ]

Capacity stood at 773.2 GW at the end of 2020 with the addition of 138.2 GW — a new record-high figure for annual installations, and 18% higher than the capacity added in 2019.

SolarPower Europe expects global solar capacity to pass 900 GW in 2021, 1.1 TW in 2022, 1.3 TW in 2023, 1.6 TW in 2024 and 1.8 TW in 2025. This would translate into new capacity additions of 163 GW in 2021, 203 GW in 2022, 225 GW in 2023, 239 GW in 2024 and 266 GW in 2025.

Under optimal conditions, the world could operate a solar fleet as large as 2.1 TW by the end of 2025, SolarPower Europe said.

China was the top solar market in 2020, adding 48.2 GW of new installations, followed by the U.S. with 19.2 GW, Vietnam with 11.6 GW, Japan with 8.2 GW and Australia with 5.1 GW.

[Selene Balasta]

Source: Wikipedia

The blue square shows the 2020 data.  Note that the long-term trend line is unchanged.   Log scale chart shows constant growth rate as a straight line.  Note more or less unchanged growth rate over 30 years.  Now that solar is so much cheaper than coal, there is no reason to expect the growth rate to fall.  Annual growth rate since 2010 is 22%, slightly less than doubling every 3 years.

India coal costs wildly understated

 IEEFA has already done a piece on Ozzie coal capacity utilisation.  This extends the analysis to India.

From IEEFA

India’s future coal-fired power project pipeline carries a massive stranded asset risk due to the collapse in the average utilisation rate of its coal-fired power fleet leading to an underestimation of financial risk for new projects, finds a new report from the Institute for Energy Economics and Financial Analysis (IEEFA).

There are currently 33 gigawatts (GW) of coal-fired power plants under construction and another 29GW of proposed projects under various stages of regulatory approval in India.

Author of the report, energy finance analyst Kashish Shah says the LCOE (levelised cost of energy) is the required tariff at which the net present value of the investment is zero.

“In other words, LCOE is the minimum required average tariff for a power asset to reach a breakeven return at the end of its life. Anything less than that suggests the asset is unviable.”

Shah found that the average utilisation rate of India’s coal-fired fleet has collapsed to a financially unsustainable low of 53% in financial year (FY) 2020/21 from a high of 78% a decade ago in FY2011/12.

For most coal plants in India, the LCOE is calculated with an assumption of utilisation factor of 85-90% throughout the life of the project. However, the [actual] LCOE turns out to be 64% higher with India’s [actual] average capacity utilisation factor sitting at ~55% for the last few years.

“The aspiration for further builds of coal capacity stems from the notion that coal is still ‘cheap’,” says Shah. “However, with tariffs now below Rs2/kilowatt hour (kWh) (US$27/MWh), solar power is cheaper than even the variable cost of coal-fired power and is ready to absorb incremental daytime demand.”

IEEFA’s report highlights that utilisation factors of coal-fired power plants have declined not just in India, but across major electricity markets including China, the United Kingdom (UK) and the United States (U.S.).

“With zero fuel costs, the marginal cost of generation for renewables is practically zero,” says Shah. “On the other hand, with increasing inflation in Indian domestic coal prices and railway transportation costs for coal, the gap between cost competitiveness of renewables versus coal is widening.

“This raises a serious concern about the viability of coal-fired power plants.

“Debt servicing for underutilised coal-fired power assets becomes extremely difficult and creates a liquidity crunch in the whole value chain. The financial stress then spills over to the power distribution sector as well as affecting India’s financial lending institutions. This further inhibits growth in other important segments of the power industry such as renewables and transmission infrastructure, which are extremely critical for India’s electricity sector transition.”

The report concludes that the financial viability of India’s proposed and under construction coal-fired power projects should be re-evaluated based on the right estimation of utilisation factors including LCOE and capacity factor to avoid further bloating of India’s non-performing assets.

IEEFA points out that the cost of new-build solar is below the variable (operating) cost of coal.  It's cheaper to build new solar farms than to dig out, ship, and burn coal to make electricity.   Yet coal power stations are stuill being built because they are "cheap".

Boom in new US renewable capacity

 From IEEFA

Following record capacity additions in 2020, U.S. developers of large-scale wind farms, solar plants and battery stations started 2021 with a bang, bringing online a combined 3,859 MW in the first quarter, 10% more than in the same period a year ago, according to a new report underscoring the country’s accelerating clean energy transition.

The new capacity added in the first three months of 2021 pushed U.S. cumulative wind, solar and battery storage capacity over 173,000 MW, twice as much as just five years ago and enough to power more than 50 million U.S. homes [40% of the total], the American Clean Power Association, or ACP, said in a May 13 report.

Texas added the most new capacity in the first quarter, with 791 MW, followed by Oklahoma with 555 MW, California with 519 MW, South Dakota with 462 MW and North Dakota with 299 MW.

Meanwhile, more than 84,000 MW of renewable energy and energy storage capacity is moving toward the finish line, with 37,719 MW under construction and 47,731 MW in advanced development, according to the Washington, D.C.-based trade group.

[Garrett Hering]

The charts below show the EIA's projection 

Renewables touch 50% of grid in Oz

 From IEEFA

Output from wind and solar have surged to two new record highs in the National Electricity Market over the past 24 hours, with sunny and windy conditions combined to push their combined output towards 12 gigawatts, or nearly 50 per cent of total demand.

The Australian Energy Market Operator, which recently released its 20-year blueprint mapping a path to up to 94 per cent renewables by 2040, celebrated the first record with a Tweet that noted the combined output of wind farms, and small and large-scale solar generation, exceeded 11,700MW for the first time. That smashed a record set back in November 2019, where combined wind and solar output hit 11,300MW.

But it has taken less than 24-hours for the record to be broken yet again.

According to OpenNEM, the combined output from wind and solar sources surged to a new high shortly before 11am, pushing past 11,830MW of combined output. It might have been even higher, given the delays and constraints that have had a heavy impact on wind and solar developers, and by industry estimates has reduced the anticipated output by an average of more than 700MW.

At noon on Friday, renewables (including hydro) supplied 48.6 per cent of all electricity generated in the National Electricity Market, which covers New South Wales, Victoria, Queensland, South Australia, Tasmania and the ACT. The prevailing conditions could see the market share of renewables surpass 50 per cent for the first time since 2019 over the coming weekend as demand reduces.

Renewable energy output across the entirety of the NEM has averaged more than 33 per cent over the last 24-hours, with windy yet sunny conditions prevailing across Australia’s eastern states, and is approaching a new daily record, which was set on 12 November 2019 at 34.3 per cent.

Source: AEMO

BHP coal assets fall $1 billion in 2 years

 From IEEFA

Another global investor, the UK’s biggest public pension fund NEST, has withdrawn funds from BHP this week because the company is profiting “from digging coal”.

This follows BHP being put on a watch list by the Norwegian Sovereign Wealth Fund as a firm not adopting business strategies aligned with the Paris Agreement.

Pressured by investors to commit to global decarbonisation, BHP has put its last two loss-making Australian and Columbian thermal coal operations up for sale at a time when buyers are wary and global financial institutions are increasingly refusing to fund thermal coal.

Both Adani Australia and Yancoal made offers well below expectation for BHP’s Mt Arthur mine in Australia, signalling a dramatic change in market expectations and the realisation of stranded asset risk in the coal sector, and growing rehabilitation liabilities.

Tim Buckley, director of energy finance studies at the Institute for Energy Economics and Financial Analysis (IEEFA) and author of a new report: Divestment vs Sterilisation: What to Do With BHP’s Stranded Coal Assets, says the deterioration of the thermal coal market coupled with increasing stranded asset and climate risk has put BHP into a tight spot.

“Investor pressure of leading companies to align with the Paris Agreement has encouraged BHP to put its last two thermal coal assets on the market, yet buyers are coming in under expectations,” says Buckley.

“Reading the rapidly deteriorating fundamentals of the gas market, BHP sold its U.S. shale gas for US$10.6bn in July 2018, taking an asset write-off of US$2.94bn in the process.

“Although it signalled a consideration of exit from the declining coal sector in 2018, BHP failed to divest its thermal coal mining operations quick enough.

“Any buyer of its thermal coal assets would be well aware of previous optimistic valuations suggesting a price tag could reach over $2bn just for Mt Arthur just 2-3 years ago.

“Today, the market could be well under $1bn, even if a strategic buyer with a strong balance sheet can be located. Net of a sinking fund for rehabilitation costs, this figure could be halved.”

Buckley says coupled with the massive but necessary cost of mine rehabilitation due at each mine’s end of life, BHP faces a choice between retaining, selling or spinning-off the mines.

Texas: As oil wanes, wind ascends

 From IEEFA.

The wind industry in West Texas continues to create jobs, increase local tax revenues and drive economic development in an area known historically for its boom-and-bust oil cycles, concludes a report published today by the Institute for Energy Economics and Financial Analysis (IEEFA). 

The report—As Oil and Gas Wane, Texas Wind Industry Ascends—details how rising corporate demand, strong investor interest, and bipartisan political support have turned the Lone Star State into a world-class center for profitable wind-powered electricity generation.

“Texas is the wind-savviest state in the nation, and its growing number of wind farms are widely and correctly perceived as good investments, job creators, tax-base solidifiers, and engines of economic growth,” said Karl Cates, an IEEFA analyst and lead author of the report.

The report includes a case study of Nolan County, a community of 15,000 at the edge of the troubled oil and gas-driven Permian Basin, and a prime example of how the renewable energy industry has buffered some local economies from the devastating effects of a declining fossil fuel industry.

The report details also how wind remains a high-growth segment of the Texas energy sector, estimating that Electricity Reliability Council of Texas (ERCOT), the state’s main distributor of electricity, will see at least a 45% increase in its wind-generation capacity over this year and next, to 34,648MW by the beginning of 2022. ERCOT controls most of the state’s electricity market.

The industry’s impact in Nolan County:

• Tax revenues have increased, driven significantly by the wind industry, which today makes up 6 of the top 10, and 11 of the top 20 property taxpayers.
• More jobs and higher wages have come to the county, where the unemployment rate has dropped with the rise of wind and where wind-energy workers are paid on par with oilfield employees.
• The county seat of Sweetwater has drawn a range of wind-energy service businesses and is home to Texas State Technical College, which graduates 50 to 75 wind technicians per year.
• Knock-on utility-scale solar is emerging as a companion industry to wind farms.
• Lease payments that typically range from $10,000 to $20,000 annually per tower are keeping longtime property owners on the land and creating significant community cash flow.

Full report here: As Oil and Gas Wane, Texas Wind Industry Ascends