FGD and DeNOx
NEWSLETTER

June 2020
No. 506

 

 

Table of Contents

MARKETS

 

INDUSTRY NEWS

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MARKETS

 

World Coal-fired Power Generation Has Not passed 2013 Peak but Is Growing in India, Vietnam and Indonesia

 

There was a strongly upwards trajectory of 4-5 percent annual growth established from 2000-2013. However, the market was entirely unprepared for global thermal coal generation to peak in 2013. After a decline from 2014-2016, some growth resumed from 2017-2018. However, overall global coal power generation in 2019 was lower than that evidenced in 2013.

 

Given the huge investment in new coal-fired power capacity across China, India and Asia, this has been problematic; significant capacity additions have driven capacity utilization rates down to a decade low of just 51 percent in 2019.

 

The unexpected global peak of thermal coal demand back in 2013 reflects a number of factors.

 

India is the third largest electricity market globally. It too has seen an unexpected electricity sector disruption. Installation rates of thermal power net new capacity have fallen from some 20 GW annually over 2010 – 2016 to just 3-4 GW annually over the following four fiscal years, a 75 percent deceleration in growth. A surge in renewables investment followed a halving of the required tariffs for both solar and wind to just US$30/MWh, some 20 - 30 percent below existing, domestic coal-fired power tariffs (and half the cost of new imported thermal power). Prime Minister Narendra Modi has ambitiously targeted 450 GW of renewable installs by 2030 — a fivefold expansion on the current installed base of 86 GW. Further, electricity demand growth has been consistently below the optimistic assumptions of the International Energy Agency (IEA) and the Indian Central Electricity Authority. This has left average coal plant utilization rates at a decade low of just 55 percent, and stranded asset losses across the thermal power sector have reached US$60 billion. India’s goal is to become a $5 trillion economy by 2024, in part by investing heavily in infrastructure, which will boost energy demand for industry and electricity production.

 

Although India has succeeded in bringing some form of electricity access to almost all its citizens, the country’s per-capita power consumption is still low, allowing it to still grow significantly. Despite power generation from renewables expected to increase fourfold between 2018 and 2024, the IEA expects India’s coal power generation will increase by 4.6 percent per year through 2024, and for India’s coal demand to grow by more than that of any other country in absolute terms over the five-year forecast period. Pakistan has recently commissioned more than 4 GW of new coal power plants and has a similar amount under construction. Bangladesh is about to commission the first unit of 10 GW it has planned.

 

The IEA expects coal demand in Southeast Asia will grow by more than 5 percent per year through 2024, led by Indonesia and Vietnam. The region’s strong economic growth is expected to drive electricity and industrial consumption, which will both be fueled in part by coal. Southeast Asia countries are also using coal to provide electricity for their growing populations.

 

Coal’s future is primarily in the electricity generation markets in Asia, with China, India, and Southeast Asia continuing to build coal-fired generating capacity. The IEA expects generation from coal-fired power plants in Asia will exceed the drop-in coal-fired generation in the U.S. and Europe so that coal remains the world’s largest generation fuel over the next five years.

 

IEA Forecasts a Coal-fired Power Peak in China in 2022

 

China is the world’s biggest producer and consumer of coal. IEA expects China’s coal consumption will plateau around 2022 due to a decline in coal use in the residential, small industrial, and heavy industrial sectors, driven by structural changes in the economy and the need to reduce local pollution.

 

Residential use of coal is a major contributor to localized pollution because it is largely burned in an uncontrolled environment, without the technologies and modern pollution reduction capabilities of larger users. China’s coal power generation, however, is expected to continue to grow, just at a slower rate, dropping its share of the power generation market from 67 percent in 2018 to 59 percent in 2024. It is believed that coal is needed to sustain China’s economic growth and guarantee energy security in the future.

 

China’s reliance on coal helped it become the world’s second-largest economy, pulling nearly a billion people out of poverty. Based on recently released official economic data found that 65 percent of the annual growth in energy consumption in 2019 came from fossil fuels, with coal accounting for 57.7 percent of China’s energy use. Coal plants, which burn approximately 54 percent of all coal used in the country, provide 52 percent of generating capacity and 67 percent of electricity output.

 

Despite China’s generation sector being at overcapacity, China added about 40 GW of coal-fired power capacity in 2019 — a 4 percent increase. As a result, the coal fleet’s average utilization rate fell below 50 percent on average. Even so, China is still building new supercritical coal-fired generators with 100 GW under construction, which would raise current coal capacity by nearly 10 percent.

 

 

INDUSTRY NEWS

 

Increasing Consistency and Transparency in Considering Benefits and Costs in the Clean Air Act Rulemaking Process

 

The Environmental Protection Agency (EPA) is proposing processes that it would be required to undertake in promulgating regulations under the Clean Air Act (CAA) to ensure that information regarding the benefits and costs of regulatory decisions is provided and considered in a consistent and transparent manner. This proposed rulemaking addresses, among other things, issues raised in the June 13, 2018 advance notice of proposed rulemaking, ‘‘Increasing Consistency and Transparency in Considering Costs and Benefits in the Rulemaking Process,’’ and proposes how the concepts described in that advance document would be implemented in rulemakings conducted by the EPA using its authorities under the CAA. The EPA is proposing to establish procedural requirements governing the development and presentation of benefit-cost analyses (BCA), including risk assessments used in the BCA, for significant rulemakings conducted under the CAA. Together, these requirements would help ensure that the EPA implements its statutory obligations under the CAA, and describes its work in implementing those obligations, in a way that is consistent and transparent.

 

Federal Register / Vol. 85, No. 113 / Thursday June 11, 2020 / Proposed Rules

 

Eight WTE Plants for Kazakhstan

 

Central Asia’s largest country is planning to launch the ‘‘Waste-to-energy’’ project to tackle the growing mountain of trash, according to Ramazan Zhampiissov, who chairs Kazakhstan-based International Green Technologies and Investment Projects Center (IGTIPC).

 

“The problem of municipal solid waste management is relevant for Kazakhstan and requires a systematic solution based on the use of international best practices,’’ Kazakhstan-based Kazinform news agency quoted Zhampiissov as saying.

 

As of today, nearly 85 percent of all solid waste in Kazakhstan does not get sorted and recycled, according to the official.

 

“It is impossible to recycle all solid waste, so part of the waste — between 30 and 50 percent — should be recycled using waste-to-energy technology with the further generation of electric and thermal energy at stations that use solid household waste as a source,’’ Zhampiissov added. 

 

Stretching between China and the Caspian Sea, Kazakhstan measures over 2.7 million square kilometers (1.05 million square miles), making it the world’s ninth-largest country. 

 

With a population of nearly 19 million, the country annually generates an average of 4-5 million tons of municipal solid waste (MSW). Over 120 million tons of waste have already piled up at more than 3,000 landfills across the country, of which only 623 comply with environmental and sanitary requirements. At the same time, more than 9,000 unauthorized solid waste landfills have been found last year in Kazakhstan, of which 2,700 have already been liquidated, according to the data compiled by the country’s ecology, geology and natural resources agency.

 

“If we do not deal with the problem of municipal waste disposal right now, in a few years it will lead to the inevitable consequences for Kazakhstan’s ecology,” the head of IGTIPC believes.

 

Officials in Nur-Sultan are now working to launch the ‘Waste-to-energy’’ project which is expected to help prevent existing ecology challenges. The project involves the study of solid waste, as well as geotechnical surveys for the construction of waste-to-energy plants. These plants burn municipal solid waste to produce steam in a boiler that is used to generate electricity and are of high popularity in countries that have little open space for landfills and have few energy resources.

 

Finland, Sweden, Denmark and Norway had the most efficient material waste management system as of 2018, according to a report issued by the Confederation of European Waste-to-Energy Plants. For example, Danish Copenhill waste-to-energy plant, launched in 2017, is capable of incinerating 440,000 tons of waste to deliver electricity and district heating for 150,000 homes annually.

 

Zhampiissov said Kazakhstan is eager to partner with the European countries, to outline best practices for the launch of local waste-to-energy plants, but the project requires attracting investors.

 

‘‘In general, the creation of an effective solid waste management system in the country and the modernization of existing infrastructure require significant investments,’’ the Kazakh official said, adding that the government will create competitive conditions for investors.

 

Currently, government officials in what is Central Asia’s largest country are developing the bill that will set specific requirements for the operation of waste-to-energy facilities in Kazakhstan and introduce mechanisms to support these facilities, as well as create conditions for investors to engage in the industry.

 

Last year, Kazakhstan’s ecology, geology, and natural resources agency announced that the country would launch up to eight waste-to-energy plants, which are expected to bring at least $500 million to the industry over the next few years. In addition, the government designed a document —the Environmental Code — which is expected to increase the attractiveness of waste disposal activities for both local and foreign investors.

 

Saltworks Treats FGD and Coal Ash Pond Wastewater

 

Saltworks developed a solution that removes up to 90 percent of chlorides from FGD wastewater, meaning that the water can be re-used rather than discharged. The solution uses Saltworks’ Flex EDR product—with proprietary monovalent-selective membranes — enabling up to 50 percent cost savings over alternative methods.

 

The same technology is now being tested by a major international mining company to remove chlorides and boost production from what would normally be a waste product.

 

The site pilot work — proving the performance of Flex EDR as a chloride kidney — was made possible thanks to the foresight of the Electric Power Research Institute (EPRI) and the support of the Department of Energy’s National Energy Technology Laboratory, as well as Canada’s Industrial Research Assistance Program.

 

 

 

The combustion of coal in thermal power plants generates large volumes of coal combustion residuals (CCR), such as fly ash, bottom ash, boiler slag, and flue gas desulfurization (FGD) materials. These CCRs are collectively referred to as coal ash. For decades, coal ash has been managed using river or lake water to sluice it into a large surface water impoundment (also called “coal ash pond”) for its final settlement. Coal ash contains substances such as arsenic, boron, selenium, and heavy metals (cadmium, copper, chromium, lead, mercury, among others). As a result, coal ash pond water, if released into the environment through embankment breaches and seepage of the water through the pond bottom as leachate, may contaminate soil, rivers, lakes, and groundwater. Several U.S. power plants are currently required by the regulators to clean up their coal ash ponds and to treat coal ash pond waters as soon as possible.

 

Prior to designing a coal ash pond water treatment plant, it is important to know its water chemistry. This will identify the constituents of concern for treatment and the potential scaling risks. A single treatment method unlikely removes every pollutant to meet all requirements. 

 

Rather a plant should be designed to meet the treatment objectives and be cost optimized for the project. This will involve an integration of multiple treatment methods. We hereby provide a “toolbox” of treatment methods for the most common pollutants of concern in coal ash pond waters.

 

Arsenic:  Arsenic may exist in coal ash pond waters as inorganic As (III), arsenate As (V) or organic methylated arsenic compounds. The species of arsenic present in the water will determine the treatment method. There are three options for removing inorganic arsenite and arsenate:

 

 

The phys/chem precipitation method is often preferred as it can reduce arsenate down to 0.01 mg/L. When arsenite is the predominant species in the water, an oxidation step is required to convert arsenite into arsenate prior to the phys/chem precipitation process.

 

Reverse osmosis has the benefit of being able to remove both inorganic and organic arsenic. Phys/chem precipitation or physical adsorption is not effective for organic methylated arsenic compounds. Although work is being done on advanced oxidation processes to target only organic arsenic removal (for example, Fenton oxidation), these are not yet commercial and may be expensive.

 

Boron: Two options for boron-removal are commonly used:

 

Both IX and RO options will generate a waste brine.

 

Selenium: Selenium may exist in coal ash pond waters as selenite Se(IV) or selenate Se(VI). Selenite is more reactive and easier to remove than selenate. Phys/chem precipitation using ferrous or ferric reagents is effective in removing selenite but not for selenate. Existing selenate removal processes are based on converting selenate into elemental selenium through biological reduction. Although electrochemical reduction processes have been studied to remove selenate, they are not yet commercialized and generate a large volume of solid waste requiring disposal. Reverse osmosis will remove both selenite and selenate, management of the reverse osmosis brine needs to be considered. In some cases, the brine can be returned to the coal ash pond, however this will increase the pond salt contents over time.

 

Heavy metals: Heavy metals (cadmium, copper, chromium, lead, mercury, and zinc) are generally removed by phys/chem precipitation as metal oxides or metal hydroxides. The phys/chem process may not meet stringent discharge requirements, depending on the specific metal and its precipitate solubility. To further reduce heavy metal concentrations after the phys/chem process, a polishing step with reverse osmosis or scavenging agents that reacts and binds with metals may be required. 

 

Most metal scavenging agents are toxic so care must be taken to ensure that they do not end up in the treated water.

 

Saltworks has the experience and product solutions to treat coal ash pond waters. Our modular advanced desalination technologies (BrineRefine, Xtreme Reverse Osmosis) can achieve ultra-high brine volume reduction and evaporator crystallizers (AirBreather, SaltMaker) for minimal liquid discharge (MLD) / zero liquid discharge (ZLD) can help economically treat coal ash pond waters for discharge and manage residuals for end of life disposal. 

 

Saltworks has the experience and product solutions to treat coal ash pond waters. Our modular advanced desalination technologies (BrineRefine, Xtreme Reverse Osmosis) can achieve ultra-high brine volume reduction and evaporator crystallizers (AirBreather,  SaltMaker) for minimal liquid discharge (MLD)/zero liquid discharge (ZLD) can help economically treat coal ash pond waters for discharge and manage residuals for end of life disposal.

ChemTreat has Improved Method for Selenium Removal

 

An advanced physical chemistry technique is now available to remove selenium from power plant FGD, ash-sluicing, ash pond, and landfill leachate wastewaters. The process also reduces the concentration of other priority pollutants in these water streams and represents an alternative from capital intensive biologically based methods. The equipment needed is not exotic and is, in large measure, standard to many wastewater systems, i.e., clarifiers, reaction tanks, and filter presses. It may allow some plants to remain in operation, where the costs of biological treatment processes would have tipped the balance in the other direction.

 

ChemTreat’s patent-pending process SeQueste offers a physical-chemical alternative to the biological method of selenium removal. The process utilizes an enhanced adsorptive matrix along with process adjustments to remove selenium, which employs conventional wastewater treatment equipment such as holding tanks and settling & de-watering apparatus. The configuration can be designed to treat not only direct discharge from wet scrubbers, but also stored ash pond water and collected landfill leachate, at potentially much lower cost than the current BAT methods. Furthermore, pilot test results indicate that the technology will lower the concentrations of other priority pollutants, including arsenic, mercury, and nitrate. https://www.power-eng.com/2020/03/06/coal-fired-om-a-novel-non-biological-process-for-selenium-removal/#gref

 

Duke Will Use Reclaimed Wastewater in Gas Turbine Plant in Florida

 

A solution is on the table to increase the flow of Crystal River’s reused wastewater to Duke Energy’s energy complex, keeping the city from paying a penalty and polluting its watershed. Duke representatives told City Council at its meeting Monday, June 8, 2020, their engineers could pipe the water to the power company’s Citrus Combined-Cycle Natural Gas Plant. Crystal River already pumps reclaimed water to Duke’s two coal units, where it’s used for pollution control, but Duke’s demand for city water is decreasing as it uses those facilities less, company spokeswoman Dorothy Pernu told the council.

 

“We are pursuing a cleaner energy solution for power generation,” Pernu said. “We have made a commitment nationwide to reduce our carbon emissions.

 

Crystal River has been sending Duke between 750,000 and 800,000 gallons a day (GPD) of reclaimed water since a $8 million, joint-funded project came online in July 2015 for the city to pump semi-treated water from a storage tank at its sprayfield off of North Citrus Avenue. This project helped Duke reduce the amount of groundwater it pumped from the aquifer and kept the city from spraying onto its 200-acre field and pollutants to runoff into nearby water systems.

 

Duke committed to taking reclaimed water for 20 years, with a goal to possibly receive up to 1.5 million GPD, according to its 2010 agreement with the city

However, Pernu told council on June 8 Duke expects to lower its need for reused water down to 350,000 GPD over the next five years, but “is committed to helping the city find a solution.”

 

City Manager Ken Frink said the city agreed with Southwest Florida Water Management District (SWFWMD) to pump at least 750,000 GPD to Duke, or else Crystal River would have to refund SWFWMD for its investment loss.

 

According to Crystal River, SWFWMD contributed $2.555 million toward the city’s reclaimed water project; the city paid $2.325 million, FDEP paid $1.118 million and Duke paid $2.1 million. Frink said SWFWMD is willing to wait for the city to find a remedy.

 

“What they want to see is progress,” he told council members, adding the city isn’t violating any terms yet.

 

Jeffrey Swartz, Vice President of Duke power operations in Florida, told council a pipe could connect with existing reclaimed-water piping to pump water into Duke’s natural gas and coal plants, before discharging it into the Gulf of Mexico. With this system in place, Duke could receive 750,000 GPD or more of reclaimed water from the city. City council members were happy with Duke’s proposal.

 

“We’re very thankful and happy you’re able and willing to work with us and take care of this,” Councilman Pat Fitzpatrick said.

 

Swartz said the natural gas plant already pumps 30,000 gallons of drawn water into the Gulf every minute so the added 750,000 GPD, or roughly 500 gallons per minute, will have minimal impact to the Gulf.

 

There are two obstacles with making this happen: funding and permitting.

 

“Everything we do at the site is regulated by various environmental permits,” Swartz said. Swartz said it could take between six and 12 months before Duke’s application for a National Pollution Discharge Elimination System permit is approved, designating the city’s reclaimed water as safe to be dumped into the Gulf.

 

“Depending on what the permit says, we may need to do some more treatment,” he said. “Then we can finalize the cost and figure out funding sources.”

 

Coal-fired Power Plant Retirements Chronicled by S&P

 

Duke Energy plans to retire 862 MW of coal capacity by 2024. This includes Units 1, 2 and 3 at the 1130-MW G.G. Allen coal-fired power plant in Gaston County, NC, and the 280-MW R. Gallagher coal-fired power plant in Floyd County, IN

 

The utility also has revealed plans to move up the retirement of other coal units, including Units 4 and 5 at G.G. Allen and units at its Cayuga and Gibson coal-fired power plants in Indiana.

 

AEP recently ceased operations at the last 780-MW unit at its Conesville coal-fired power plant in Coshocton County, OH. The plant's official retirement is set for May 31.

 

SNL Image

 

Michigan-based Consumers Energy Co. spokesman Brian Wheeler said this early into the pandemic, the company's long-term planning has not changed, but the utility does continue to monitor industry and economic trends closely. The company's Clean Energy Plan already called for eliminating coal from its generating portfolio on the way to achieving net-zero emissions by 2040.

 

"We don't share information publicly about the status of individual power plants, but we do forecast we will continue to move over time away from coal as an energy source, including eliminating it altogether by 2040," Wheeler said, noting total sales were down 10 percent in April.

 

Consumers Energy projects 2 million tons fewer carbon emissions from its coal plants in 2020, a dip of about 12 percent from original projections, due in part to the economic slowdown caused by the pandemic.

 

NiSource Inc. subsidiary Northern Indiana Public Service Co. plans to retire all of its coal capacity in Indiana within the next 10 years as part of the utility's transition to cleaner energy resources.

 

A new Indiana law designed to pause coal plant retirements is not expected to "materially change" this generation strategy and it appears the coronavirus pandemic will not either.

 

"Regarding our future generation plans, including our announced coal retirements, we don't see significant changes in that direction," NIPSCO spokesman Nick Meyer said in a May 1 email.

 

The long-term impact of the pandemic on the service area of the Tennessee Valley Authority is still unclear, said TVA public information officer Jim Hopson. For now, the majority of TVA's power is being generated by nuclear, natural gas and hydroelectric facilities, due to scheduled outages already making most of its fossil generating units unavailable during this period.

 

TVA's long-term plans include the retirement of the Bull Run coal-fired power plant in 2023. Hopson said the TVA will wait until the timing and nature of economic recovery is better understood before making additional determinations

 

Dominion Energy Inc. subsidiary Dominion Energy Virginia plans to retire the remaining units at its 1032-MW Chesterfield coal plant in 2023 as modeled in the utility's 2020 integrated resource plan, or IRP, filed with the Virginia State Corporation Commission.

 

A new Virginia law requires Dominion Energy Virginia, known legally as Virginia Electric and Power Co., and AEP utility Appalachian Power Co. to "retire all generating units principally fueled by oil with a rated capacity in excess of 500 [MW] and all coal-fired electric generating units operating in the Commonwealth" by December 31, 2024. The Virginia Clean Economy Act, which takes effect July 1, provides an exception for coal plants co-owned with a cooperative utility and for Dominion Energy Virginia's 624-MW Virginia City Hybrid Energy Center. Still, Dominion models the tentative retirement of the 881-MW Clover coal plant, which it co-owns with Old Dominion Electric Cooperative, in 2025 under all four scenarios in its IRP. The company said it could not provide an immediate comment on how the coronavirus pandemic has impacted its coal usage or generation planning.

 

South Carolina state-owned utility Santee Cooper, known legally as South Carolina Public Service Authority, still plans to retire all four units at its 1,150-MW Winyah coal plant starting with units 3 and 4 in 2023, according to spokesperson Mollie Gore.

 

SNL Image

 

"This pandemic gives a lot of validity to our new power supply plan, which replaces the Winyah coal units and addresses future energy needs by adding renewables, storage and natural gas in smaller, modular units," Gore said in an email. "That flexibility is critical in allowing utilities to adjust when plans and forecasts are turned upside down, whether that is by a pandemic — or a more positive development like rapidly changing technology."

 

Tri-State Generation and Transmission Association Inc., composed of members and public power districts in Colorado, Nebraska, New Mexico and Wyoming, said it is waiting to see the full impact of the virus and sharp drop in oil prices. Mark Stutz, a public relations specialist with Tri-State, said the association had not changed plans to retire its Escalante generating station in New Mexico by the end of the year or its Craig coal-fired power plant in Colorado by 2030.

 

"We do know that recent events will have a downward pressure on demand in the short term, but we are in a strong position financially and operationally to deal with those impacts," Stutz said.

 

PacifiCorp spokesman David Eskelsen said they have not determined any changes are necessary to their current action plan, which involves retiring 2800 MW of coal-fired generation by 2030 and nearly 4500 MW by 2038 to make way for renewable energy and battery storage capacity.

 

"It is too early to be certain, because much depends on how long the public health crisis persists," Eskelsen said.

 

U.S. Coal Negatively Impacted by COVID

 

The latest downturn in coal started in the autumn of last year as the U.S. went into an unusually mild winter, and it has been exacerbated this year by the coronavirus pandemic. As power demand has fallen, it has been coal-fired power plants that have borne the brunt of the reduction in output.

 

U.S. power generation was down 5 percent in total in April compared to the same month of 2019. Within that, gas-fired generation was up 1 percent and renewables up 8 percent, but coal-fired generation was down 32 percent. In many parts of the U.S., coal-fired power plants are a more expensive technology for power generation than gas, wind or solar, meaning that many generation companies will look to shut them off first.

 

The way that utilities have begun to operate their coal-fired power plants has also changed, according to Matt Preston, Wood Mackenzie’s research director for North America coal markets. Previously, many utilities, particularly in the Midwest, chose to self-dispatch their coal units even when they were not the lowest-cost generation available, on the grounds that cycling the units’ output up and down increased maintenance costs. Recently that has changed, and coal plants are operating much more as the marginal units on the grid.

 

Global demand for all energy sources, including coal, is already starting to recover as lockdowns are eased. But in the U.S. and Europe, at least, it looks as though the pandemic has accelerated the decline of coal. The outlook for coal demand now depends on policy decisions in large emerging economies, and particularly in China.

 

U.S. EPA Moves to Curb Ability of States to Reject Coal and Other Energy Infrastructure

 

The US Environmental Protection Agency (EPA) has issued a rule amending Section 401 of the Clean Water Act to limit the ability of state governments and authorized tribes to block energy infrastructure such as coal and gas terminals and pipelines. The change, which was endorsed by the peak coal lobby group the National Mining Association, sets a one-year timetable for decisions and limits consideration of projects only to the “point source” impacts on water quality, not broader impacts. In 2017 Washington State refused a water permit for Millennium Bulk Terminals proposed Longview coal export facility on grounds including that it would involve the destruction of wetlands and damage to tribal fishing rights. Legal analysts have suggested the EPA’s change is likely to be vulnerable to legal challenge.

 

Siemens Energy Will Be Independent Company

 

“Turning Siemens’ energy business into an independent company is a key milestone in the successful execution of our Vision 2020+ strategy program,” said Joe Kaeser, President and CEO of Siemens AG. “The considerable increase in the value of our health care business shows the huge potential we can tap by further sharpening the focus of our company. This applies to both, Siemens Energy and the ‘New Siemens AG,’ which is concentrating on our Industrial Businesses. We’ve now reached a major milestone in the overall realignment that is preparing the Siemens companies for the massive technological transformations that we are anticipating.” 

 

The planned public listing of Siemens Energy will create a strong, focused, global company with operations spanning the entire energy value chain, including the service business. Thanks to its unique setup, Siemens Energy can react quickly to customer needs and thus help meet the globally rising demand for energy while significantly reducing carbon emissions. In the future, Siemens AG itself will concentrate on Digital Industries, Smart Infrastructure and Siemens Mobility. Siemens Healthineers, the company’s healthcare technology business — which has a sharp focus on diagnostic and therapeutic imaging, laboratory diagnostics, molecular medicine and health services — has been publicly listed as a separately managed company since March 2018.

 

The new Siemens Energy will have about 91,000 employees worldwide (as of March 31, 2020). Its products will include, among other things, combined cycle turbines, generators, transformers and compressors. In the area of wind turbines, Siemens Energy will be a world-market leader in renewable energies due to its 67 percent stake in Siemens Gamesa Renewable Energy. As of September 30, 2019, Siemens Energy’s order backlog stood at €77 billion. In fiscal 2019, Siemens Energy generated revenue of about €29 billion according to the Combined Financial Statements of Siemens Energy AG as of September 30, 2019, which were prepared on a voluntary basis. If severance charges of around €0.3 billion had been excluded, the adjusted EBITA would have been about €1.3 billion.

 

At its launch, Siemens Energy will be very solidly financed: the new company will have a large amount of capital and liquidity at its disposal right from the start. The aim is to meet the requirements for a solid investment-grade credit rating. According to the Combined Financial Statements of Siemens Energy AG as of March 31, 2020, which were prepared on a voluntary basis, equity totaled about €17.3 billion (IFRS), corresponding to an equity ratio of 37.8 percent. Siemens Energy has been provided with liquidity equivalent to about €6.2 billion. Of this amount, around €4.1 billion will be used to settle liabilities during the period leading up to the spin-off. In addition, a bank consortium has confirmed a revolving credit facility of €3.0 billion.

 

After the spin-off, Siemens Energy will be managed separately and independently. A so-called deconsolidation agreement signed with Siemens AG ensures this status. Under the terms of this agreement, Siemens AG has obligated itself to refrain from exercising any direct or indirect controlling influence over the new company. Among other things, the agreement requires that the Supervisory Board of Siemens Energy AG include no more than three representatives of Siemens AG. In addition, voting rights will be limited to the extent that no decisions on certain topics—in particular, on the election of Supervisory Board members—can be implemented unilaterally against the wishes of the other shareholders of Siemens Energy AG.

 

Indian Utility Fined for Breaching Pollution Deadline

 

The Central Pollution Control Board will fine the Haryana Power Generation Cooperation Limited (HPGCL) 1.8 million rupees (US$23,780) per month for each of its 10 coal units that continue to operate in breach of pollution control standards first announced in December 2015. When the new standards for sulfur dioxide, oxides of nitrogen and mercury emissions were first announced the Ministry of Environment, Forest and Climate Change set the compliance deadline as December 2017. Despite the deadline being deferred after lobbying by utilities until December 2019, HPGCL has still not met it. HPGCL said it will appeal against the fine.

 

India Abandons Coal Washing as Most Plants to Miss Deadline for Scrubbers

 

The Ministry of Environment, Forests and Climate Change has amended the Environment Protection Act to delete the requirement that any coal to be supplied to a customer over 500 kilometers away must be washed. The requirement to reduce the ash content of coal transported long distances was introduced in 2015. One of the justifications recently floated for the change was that new pollution control standards on power plants would reduce the need for coal washing. However, a new study by the Center for Science and Environment finds that almost 70 percent of the country’s coal plants will not comply with emission standards by the end of 2022. The compliance deadline for the new standards was first introduced in December 2015 with the initial compliance deadline set as December 2017, then extended to December 2019 and more recently many plants won a further extension until December 2022.

 

Eskom Bid to Avoid Pollution Controls on Medupi Hits Legal Hurdle

 

The South African Dept. of Environmental Affairs has stated that there is a legal process that would allow Eskom’s plan to avoid the installation of flue gas desulfurization equipment on the six 800-MW units of its Medupi plant. Eskom originally agreed to install the equipment, which would cut deadly sulfur dioxide emissions, in return for a US$3.75 billion loan from the World Bank for the plant.

 

Court Rules U.S. Environment Agency Must Protect States from Upwind Air Pollution

 

A federal appeals court ruled that the U.S. Environmental Protection Agency violated the law when it denied a request from Maryland and Delaware to tighten air pollution controls at power plants in upwind neighboring states.

 

The decision by the three-judge panel of the United States Court of Appeals for the D.C. Circuit could force the EPA to impose new curbs on some coal-fired power plants, even as the administration of President Donald Trump seeks to help the industry by slashing environmental regulations.

 

The EPA is reviewing the decision, said spokeswoman Enesta Jones.

 

Maryland and Delaware had filed their petition to the EPA in 2018 asking for tougher pollution limits on some 36 coal-fired power plant units in Indiana, Kentucky, Ohio, Pennsylvania and West Virginia.

 

The states had argued that those power plants were in violation of the Clean Air Act’s “good neighbor provision” for the release of nitrogen oxides into the air. The majority of Maryland’s ozone pollution originates from upwind states.

 

The EPA rejected the petition, arguing that requiring upwind power plants to add more pollution controls to protect downwind states was not cost-effective for the plant owners.

 

Richard Revesz of NYU’s School of Law and director of the Institute for Policy Integrity filed the amicus brief on behalf of Maryland and Delaware. He said the ruling made clear the EPA is obligated to prevent states from harming the air quality of their neighboring states when emissions travel downwind and “can’t cite cost as a reason to ignore the law altogether.”

 

Convert Coal Plants to Biomass

 

FutureMetrics LLC on May 6 published a whitepaper discussing how converting existing coal-fired power plants to be fueled with wood pellets offers a low cost, easy-to-deploy way to generate low-carbon electricity.

 

William Strauss, President of FutureMetrics and author of the paper, noted coal-to-biomass conversions has been the topic of previous whitepapers published by the company. “However, given the current COVID-19 induced disruption to our global economy and how that may impact energy policies, it’s important to remember that there is a relatively low-cost, easy-to-deploy, and highly carbon beneficial energy source solution for power generation,” he wrote.

 

The whitepaper discusses the conversion of the Drax and Lynemouth power stations in the U.K., and their use of wood pellets sourced from renewing working forests. The power produced at those stations is not intermittent and variable, Strauss stressed. Rather, biomass power plants produce baseload power that is impossible to achieve with solar or wind.

 

“Wood pellets produced from sustainably managed forestry operations, when used to produce power, do not increase the net stock of CO2 in the atmosphere,” Strauss wrote. “The basic necessary condition for an area of managed forests is if forest growth rate equals or exceeds the harvest rate then the net stock of carbon held in the forest is constant or growing. Thus, the CO2 released in combustion is contemporaneously absorbed by the new growth and no net new CO2 is added to the atmosphere.”

 

Within the paper, Strauss describes arguments made by those who oppose the use of wood pellets for power generation and debunks their claims. “There is no rational logic that can show the use of materials from responsibly and sustainably managed forests can result in a net addition of CO2 to the atmosphere,” he said. “As climate change consequences exponentially increase even nations like the United States will see the value in converting some existing high-efficiency coal fueled power stations to use wood pellets.

 

“That strategy avoids stranding some coal power station assets,” he continued. “And the strategy is complimentary to a rational and pragmatic transition to a more decarbonized future by providing renewable, reliable baseload on-demand power.”

 

Note that McIlvaine has written extensively of the advantages of carbon capture and sequestration. Drax is pursuing this initiative very actively

 

ANDRITZ to Supply Flue Gas Desulfurization Plant to NTPC, India

 

ANDRITZ has received an order in cooperation with its partner Tata Projects Limited  to supply the technology and critical components for wet limestone flue gas desulfurization (FGD) to be installed in thermal power plants Talcher (6 x 500 MW) and Vallur (3 x 500 MW) operated by National Thermal Power Corp. (NTPC), India.

 

The ANDRITZ scope of supply includes the plant’s complete basic engineering as well as detailed engineering for the absorber and other critical supplies.

 

Limestone flue gas desulfurization systems are well-proven and cost-effective and have been used in power stations since the 1970s to convert the main acid gas SO2 into gypsum. They are one of the most important sources of gypsum for the global gypsum industry (gypsum board, drywall, and so on). Over the years, ANDRITZ has created an advanced scrubber design with outstanding reliability and excellent availability. Plant economics have also been optimized, ensuring low capital and operating costs.

 

Eskom Wants to Cancel FGD Project

 

Eskom Holdings Ltd., South Africa’s biggest air polluter, is seeking to have the terms of a $3.75 billion World Bank loan changed to avoid spending money to cut emissions from one of its largest power plants. The 2010 loan is being used to partly fund the construction of the 4764- megawatt Medupi coal-fired power plant east of Johannesburg. It contains a “legal covenant” that Eskom must install flue-gas desulfurization, or FGD, equipment at the plant by 2025 to curb emissions of sulfur dioxide, according to the World Bank.

 

“Any changes to FGD on Medupi would require consent with the World Bank,” the lender said in a reply to questions. “We understand that Eskom may be investigating alternative solutions, however the World Bank has not received a proposal.” Sulfur dioxide pollution causes respiratory illnesses and acid rain.

 

Eskom argues that in addition to being expensive, the equipment would increase water consumption, necessitate the use of large quantities of limestone and produce additional carbon dioxide, a greenhouse gas. Some of the money saved could be used to adapt some older, coal-fired plants to use other fuel, it said. “Installing FGD at Medupi may reduce the impact on health by a small margin, but it will result in other negative environmental impacts,” Eskom said. Switching older plants away from coal would reduce emissions of “sulfur dioxide, nitrous oxide, particulates and carbon dioxide emissions.” The utility would also need permission from the government to change its plans.

 

Sefar Filter Bags Used in Australia, Europe and Around the World at Coal-fired Power Plants

 

Sefar produces Pura-Tex dust filter bags and tubing made from high-quality felts. Depending on the application, they can be designed with snap rings or felt collars, metal bands, or drawstrings. The firm manufactures bags according to order and clients' specifications. Their vast range of available felts in various weights and with different surface treatments combined with their local state of the art manufacturing facilities allow them to offer their clients the best solution for their applications. Leading in technical fabrics for around 190 years, Sefar operates weaving mills in Switzerland, Romania, and Thailand. With Monosuisse, the Sefar Group has its yarn production with locations in Switzerland, Poland, Romania, and Mexico.

 

According to the company, "With our extensive experience in the process filtration industry and using our local test lab facilities, we have the ability and equipment to design a system for our clients to suit their process application needs," commented the company spokesperson. "Our local manufacturing facilities enable us to adapt existing designs to provide clients with a tailor-made solution and custom-made designs to suit many other applications. We can also integrate custom-made labels, color coding, or other designs."

 

Pura-Tex Sefar sells the media in Australia. One of the OEMs is BWF Enviroec.

 

Hamon Orders Up in First Quarter 2020

 

€130 million of orders were received in the 1st quarter. This is a net increase compared with the same period last year (€66.2 million).

 

The Deltak unit received a large order for three recovery boilers for a cogeneration plant in Alabama. As for the environmental business activities, the order backlog was bolstered by a refurbishing contract for a very large electrostatic precipitator at a copper refinery in Arizona and by another contract in Michigan for a very high-performance wet electrostatic precipitator for a thermal and acoustic insulation materials production line.

 

The majority of the orders received in Asia this quarter involve cooling systems, including an air-cooled condenser in China and cooling towers in Indonesia, Bangladesh and Thailand for various industries (textiles, petrochemicals, fertilizer). On the environmental side, a new wet gas scrubber order for catalytic cracking units confirms the appeal of the Group’s technology and its commercial potential in the highly specialized field of oil refineries.

 

In terms of product lines, Hamon’s leading position in the cooling tower market was confirmed by the large number of orders received by this unit. EMEA Hamon technology was chosen for the air-cooled condenser for the first next-generation combined cycle power station in Italy and in Greece, for a cooling tower which uses seawater. Hamon has developed unique expertise with this technology, which reduces freshwater use and avoids releasing waste heat into the ocean. Hamon was also awarded a major contract for the renovation of two large natural draft cooling towers in France, once again reasserting its technological expertise and leadership.

 

Hamon Group is continuing to monitor, on a daily basis, the effects the global pandemic is having on its activities. There are two main potential impacts:

 

The fact that the energy sector is considered essential by many countries allows customers to maintain a certain level of activity at their most important facilities, notably for maintenance and upkeep projects, an area in which Hamon is very active. The effects of the coronavirus on the Hamon Group’s global business are limited by the geographical diversification of its activities and, especially, by the fact that the Group is active in countries that are at different stages of confinement or easing. Furthermore, the Group has taken advantage of the various support systems implemented by the governments of the countries in which it is active to ensure the continuity of its business activities. It isn’t possible to quantify the effects of COVID-19 on the Group’s financial results at this stage of the pandemic given the many uncertainties which persist about the current crisis and, in particular, its expected duration

 

B&W Consolidated Revenues Were $148.6 Million in the First Quarter of 2020

 

Babcock & Wilcox announced a 1st quarter 2020 GAAP loss from continuing operations of $33.5 million, an improvement of $16.3 million compared to a loss of $49.9 million in 1st quarter 2019. Adjusted EBITDA was a positive $0.7 million, an improvement of $5.1 million compared to negative adjusted EBITDA of $4.4 million in the prior year period, resulting in the company's fourth consecutive quarter of profitability on an adjusted EBITDA basis.

 

On May 14, 2020, the company amended its Credit Agreement, which amendment replaces and supersedes the previously disclosed agreement to refinance the company's senior debt by May 15, 2020, among other things. Under the terms of the amended Credit Agreement, and as agreed between the company, its senior lender syndicate, and B. Riley Financial, Inc., the company's current revolving credit facility and availability for letters of credit will be extended for two years with a maturity date of June 30, 2022.

 

"As we've discussed before, many of our projects are delayed or deferred due to the global COVID-19 pandemic and the measures taken by local and national governments to control its spread, and we are not able to fully predict the extent of this impact at this time," said Kenneth Young, B&W Enterprises Chief Executive Officer. "We have implemented work-at-home mandates in many locations, and where necessary have furloughed some employees. However, we are an essential business, and are committed to supporting our customers in critical infrastructure industries such as power generation, pulp and paper and hospital facilities. Despite all of these challenges, our bookings in the first quarter roughly matched those of the prior-year period, and we are seeing our pipeline increase as many new projects are emerging, including renewable or green energy projects.

 

"Despite an operating loss on a GAAP basis, we closed the first quarter of 2020 with positive adjusted EBITDA despite the combined effects of COVID-19 and our industry's historically weak first quarter spending patterns. This is due to the determination and experience of the management and employee team that engineered the turnaround of our business, and their efforts to plan and implement changes throughout our operations in response to the unprecedented impacts of COVID-19," said Louis Salamone, B&W Enterprises Chief Financial Officer. "With our financing agreement in place, we continue to focus on managing our costs and cash flow through this crisis, while continually evaluating its effects on our business, to support our customers in the long-term. As we evaluate the impact of COVID-19, while it is impossible to fully predict, we expect deferrals and delays of certain projects to affect our performance in the second quarter of 2020 and anticipate the majority of deferred projects to re-mobilize in late 2020 and through 2021."

 

Babcock & Wilcox segment revenues were $122.0 million in the 1st quarter of 2020 compared to $188.6 million in the prior-year period, primarily attributable to lower volume related to the periodic nature of large construction new build projects. Adjusted EBITDA in the 1st quarter 2020 was $10.7 million, an increase of 17.2 percent compared to $9.1 million in last year's quarter, primarily due to higher parts margins and the results of costs savings and restructuring initiatives partly offset by the decrease in revenue volume; adjusted EBITDA margin was 8.7 percent in the quarter as compared to 4.8 percent in the same period last year. Adjusted gross profit in the Babcock & Wilcox segment in 1st quarter 2020 was $32.9 million, a 5.7 percent increase compared to $31.1 million in the prior-year period, primarily related to the benefits of cost reductions, partially offset by the effects of decreased volume as described above; gross profit margin was 27.0 percent, compared to 16.5 percent in the same period last year, primarily due to higher parts margins and the benefits of costs savings and restructuring initiatives partly offset by the decrease in revenue.

 

SPIG segment revenues were $11.3 million in the first quarter of 2020 compared to $28.9 million in 1st quarter 2019, mainly due to the ongoing wind-down of the SPIG U.S. operation, the impact of worksite COVID-19 restrictions on services volume, and more selective bidding and focus on core geographies and products to improve profitability. Adjusted EBITDA was negative $1.2 million, down $1.9 million compared to positive $0.7 million in the same period last year, driven by the decrease in revenue and lower margins due to changes in product mix described above, as well as a $0.7 million settlement on a legacy dry cooling project expected to facilitate the collection of related outstanding receivables, partly offset by lower overhead fixed costs. Adjusted gross profit declined to $0.9 million in first quarter 2020, compared to $3.7 million in the prior-year period, primarily due to the decrease in revenue, changes in product mix and legacy dry cooling project settlement described above. At March 31, 2020, SPIG's U.S. entity had two remaining significant loss contracts; the first was 100 percent complete at the end of the first quarter 2020 with only performance testing remaining, which is expected be completed in the 3rd quarter of 2020; the second was 89 percent complete at the end of the 1st quarter of 2020 and is expected to be completed in the 3rd quarter of 2020. No additional charges were recognized on these contracts in the 1st quarter of 2020.

 

Vølund & Other Renewable segment revenues were $15.3 million for the first quarter of 2020, compared to $29.5 million in first quarter 2019. First quarter revenues were lower compared to the prior year quarter mainly due to the divestiture of Loibl, a materials handling business in Germany, that contributed $7.2 million of revenue in the first quarter of 2019 and a lower level of EPC project activity due to the completion of the European EPC loss contracts, partially offset by the startup of two operations and maintenance contracts in the U.K. that followed turnover of the EPC loss contracts to the customers.

 

Adjusted EBITDA in the quarter improved to negative $3.3 million compared to negative $8.8 million in the first quarter last year, primarily due to the absence of losses on the European EPC loss contracts; in the first quarter of 2020, the segment recorded a gain of $0.1 million on the European EPC loss contracts as compared to $4.1 million of losses recorded in the first quarter of 2019, inclusive of warranty expense. The improvement also reflected the benefits of restructuring, including lower levels of direct overhead support, warranty expense and SG&A. The segment's adjusted gross profit was positive $1.5 million in the 1st quarter 2020, an improvement of $4.3 million compared to negative $2.9 million reported in first quarter 2019, primarily driven by the absence of losses on the European EPC loss contracts and lower levels of direct overhead support and warranty expense as described above, partially offset by the absence of adjusted gross profit from Loibl due to its sale.

 

FGD and DeNOx Newsletter No. 506