FGD and DeNOx
NEWSLETTER
January – February 2021
No. 513
Table
of Contents
REGULATORY
·
Drax Could Be Reducing
Net CO2 By 16 Million Tpy And Will Be Carbon Negative By 2030
·
No Change to Particulate
Ambient Air Standards
INDUSTRY NEWS
·
SCR Systems for Cruise
Ships
·
Catalytic Combustion Has
Co Catalyst Options
·
Advanced Class Gas
Turbine SCR and CO Catalyst System Operating Challenges
·
B&W Environmental
Awarded $10 Million Contract to Supply Advanced Ash Handling System
·
Consol is Considering a
300 MW Plant to Burn Waste Coal and Biomass
·
New Turbine With 15 ppm
NOx Emissions Installed in Germany
·
Power Plant on Reunion
Island to Be Converted to Biomass
·
Idemitsu Breaks Ground
on 50 MW Biomass Plant in Japan
·
B&W Thermal Announces
$10 Million in Service Contracts
·
Wheelabrator
Technologies Inc. Signs Definitive Agreement for Sale of Wheelabrator
Technologies U.K. to First Sentier Investors
REGULATORY
Drax Could Be
Reducing Net CO2 By 16 Million Tpy And Will Be Carbon Negative By
2030
The proceeds from the sale of the CCGTs are expected to be used to support the
development of the Group's biomass strategy, through which Drax aims to build a
long-term future for sustainable biomass. Drax aims to do this by expanding its
supply chain to five million tonnes of self-supply capacity by 2027 (1.5 million
today, plus 0.5 million tonnes in development) and reducing the cost of biomass
to £50/MWh.
These savings will be delivered through the optimization of existing biomass
operations, greater utilization of low-cost wood residues and an expansion of
the fuel envelope to incorporate other low-cost renewable biomass across the
Group's expanded supply chain.
Drax believes that the additional capital and operating cost investment required
to deliver this supply chain expansion is in the region of £600 million, which
the Group expects to invest ahead of 2027. Drax remains alert to sector
opportunities for both organic and inorganic growth.
The Group has identified three models through which it believes it can deliver a
long-term future for sustainable biomass, all of which are underpinned by the
delivery of its supply chain expansion and cost reduction plans. These options,
which are not mutually exclusive, are summarized below. The delivery of one or
more of these models by 2027 would enable Drax to continue its biomass
activities when the current UK renewable schemes for biomass generation end
in March 2027.
1) Merchant biomass generation at Drax Power Station
Drax believe that biomass has an important role to play in the UK as a flexible
and reliable source of renewable energy, supporting increased utilization of
intermittent and inflexible generation across the UK power grid. In March 2027,
when the current CfD and ROC renewable schemes end, Drax believes that through a
combination of peak power generation, system support services, Capacity Market
income and a low-cost operating model for Drax Power Station (including low-cost
biomass), this site can continue to operate as a merchant renewable power
station.
2) BECCS
The UK's Climate Change Committee (CCC) has set out what is required for the
country to achieve its legally binding objective of being net zero by 2050. This
includes an important role for BECCS to remove CO2 from the
atmosphere, creating negative emissions. BECCS is the only large-scale solution
for negative emissions with renewable electricity and system support
capabilities. Through combining BECCS with its existing four biomass generation
units at Drax Power Station, Drax believes it could remove up to 16 million
tonnes of CO2 per year - over two thirds of the CCC's 2035 target for
BECCS. In doing so Drax aims to become a carbon negative company by 2030.
The technology to deliver post-combustion BECCS exists and is proven at scale.
In September 2020, Drax commenced a trial of one such technology provided
by Mitsubishi Heavy Industries (MHI). In addition, Drax is developing innovative
technology options, including C-Capture, a partnership between Leeds University,
Drax, IP Group and BP, which has developed an organic solvent which could be
used for BECCS.
3) Third party biomass supply
Drax expects global demand for wood pellets to increase in the current decade,
as other countries develop decarbonization programs which recognize the benefits
of sustainable biomass for generation. Whilst there is an abundance of
unprocessed sustainable biomass material globally, there remains limited
capacity to convert these materials into energy dense pellets, which have a
low-carbon footprint and lower cost associated with transportation. As a result,
Drax expects the global market for biomass to remain under supplied. Drax is
therefore exploring options to service biomass demand in Europe, North
America, and Asia alongside the UK. Establishing a presence in these markets
could offer the potential for long-term offtake agreements, providing
diversified revenues from other biomass markets.
No Change to
Particulate Ambient Air Standards
Based on the Environmental Protection Agency's (EPA's) review of the air quality
criteria and the national ambient air quality standards (NAAQS) for particulate
matter (PM), the Administrator has reached final decisions on the primary and
secondary PM NAAQS. With regard to the primary standards meant to protect
against fine particle exposures (i.e., annual and 24-hour PM2.5 standards),
the primary standard meant to protect against coarse particle exposures (i.e.,
24-hour PM10 standard), and the secondary PM2.5 and PM10 standards,
the EPA is retaining the current standards, without revision.
This final action is effective December 18, 2020.
Federal Register / Vol. 85, No. 244 / Friday, December 18, 2020 / Rules and
Regulations
INDUSTRY NEWS
SCR Systems for
Cruise Ships
MAN PrimeServ Augsburg has developed a selective catalytic reduction (SCR)
solution that will be retrofitted aboard the cruise ship MS Amadea.
Also known as Das Traumschiff, the Amadea is well-known in Germany as the main
filming set for a popular television series.
The retrofit devised by MAN PrimeServ Augsburg calls for the integration of two
of MAN’s SCR systems, one each into both of the Amadea’s four-stroke MAN 7L58/64
propulsion-engines, to ensure maximum performance. The installation will begin
in September 2021.
The retrofit reflects a general desire by the charter operator Phoenix Reisen
GmbH to enhance its environmental friendliness and, more immediately, will
enable the vessel to meet emission standards in the key Norwegian Heritage Fjord
market. For the project, MAN PrimeServ prioritized keeping hazardous emissions
to a minimum while maintaining engine performance and propulsion efficiency.
“The concept of clean cruising is a major, coming trend within the cruise
industry and the Amadea therefore runs on high-quality marine diesel-oil alone,”
said Alexander Schäfer, head of MAN PrimeServ Turbocharger & Exhaust Gas
Treatment.
“We are currently experiencing an increasing number of requests from cruise and
ferry companies that want to improve their green credentials and who desire to
become sustainable without the need for legislation. We want these companies to
know that we can support them, regardless of whether they intend to enter the
Norwegian Heritage Fjords or not.”
MAN PrimeServ Augsburg has previously retrofitted the Amadea’s turbochargers —
in the process improving engine efficiency and significantly reducing CO2 emissions
— and also introduced MGO instead of HFO injection nozzles in order to minimize
black-carbon emissions. The combined work carried out on the vessel reflects MAN
Energy Solutions’ desire to increasingly become a supplier of complete
propulsion solutions.
The MAN SCR solution will bring the Amadea’s engines from Tier 0 status to Tier
3 emission level, and will reduce NOx emissions by 90%, equivalent to savings of
600 tons per annum. MAN’s SCR system is the greenest solution available on the
market with the highest operational readiness and safety: the SCR will be
available from just 15% engine load, enabling clean operation, also during
slow-sailing in the fjords as well as close to port and populated areas.
The fully modular SCR solution will be integrated into the Amadea’s
engine-control system. With its closed-loop system and a weather station that
uses environmental data, the NOx-reduction rate is maximized, and
ammonia-slip minimized to just 10 ppm, comparable to that of a car. Low ammonia
slip is not just good because ammonia is a greenhouse gas and affects the
climate, but also because it reduces urea consumption, enabling the urea-tank
size to be reduced.
A feasibility study run by MAN PrimeServ at the beginning of the project
confirmed the suitability of the compact, modular SCR system for the limited
space available aboard the vessel. Its integration into the narrow funnel is
only possible due to the special 87cpsi honeycombs and their high reactivity in
a two-layer slim reactor design.
Catalytic Combustion Has
Co Catalyst Options
Catalytic Combustion Corporation designs, engineers, and manufactures Oxidation
Catalysts for Natural Gas Turbines and Heat Recovery Steam Generators.
Conventional Co Oxidation Catalyst:
Sulfur-Resistant:
Catalyst Reclaim Services:
Advanced Class
Gas Turbine SCR and CO Catalyst System Operating Challenges
According to Environex one of the tradeoffs for the higher
efficiency of new advanced class gas turbines (namely the G-, H-, and J-class
machines) is increased thermal NOx, which is caused by higher firing
temperatures in the gas turbine combustors. The result is GT exit NOx
concentrations in the 25 – 35 ppmvdc range for the advanced class turbines,
which is significantly higher than the 9 – 20 ppmvdc range for their F-class
predecessors.
Since regulators tend to view all gas turbines as being the same, they assume
that the same stack emissions levels can be met regardless of the turbine
technology. Because of this, the advanced class turbines are expected to achieve
the same stack emissions levels as F-class machines without giving
consideration to the differences in combustion dynamics between the different
classes of turbines.
Modern day F-class machines are expected to achieve stack limits of 2.0 – 2.5
ppmvdc NOx and 2.0 – 5.0 ppmvdc ammonia slip through the use of
selective catalytic reduction (SCR) systems, which use ammonia as the reducing
agent to convert NOx across a catalyst. These systems provide 72 –
90% NOx reduction while being allowed to slip 22 – 25% excess ammonia
(2 ppm NH3 slip/9 ppm inlet NOx to 5 ppm NH3 slip/20 ppm inlet NOx).
By contrast, the advanced class machines must provide 90 – 94% NOx conversion while
only being allowed to slip 7 – 8% excess ammonia to achieve the same stack
emissions levels.
This is increase in required NOx reduction accompanied by the
decrease in allowable excess ammonia results in increased SCR system performance
requirements that are by no means trivial. As NOx conversion
requirements increase to 90% and above, the systems have much less tolerance for
non-ideal performance, particularly with such low levels of allowable excess
ammonia. As a result, SCR systems for advanced class turbines require higher SCR
catalyst volumes, near-perfect ammonia-to-NOx distribution, and
air-tight seals around the SCR catalyst perimeter and all catalyst modules. In
order to reliably meet stack emissions requirements, these sites will
need pro-active SCR management plans that include proper ammonia injection grid
design and tuning, a catalyst testing program that takes into account all plant
operating modes, thorough catalyst system maintenance, and proper design and
selection of replacement catalyst that adapts to changing SCR system needs.
Additional challenges for advanced class turbine SCR and CO catalyst systems are
the requirements for low turndown operation, fast start-ups, and frequent
cycling. Historically, gas turbines have only been required to operate down to
50% of baseload. Many of the new, advanced class sites are being asked to
operate at loads as low as 20%, start up and achieve emissions compliance within
shorter timeframes, and to cycle frequently between low loads and baseload.
These requirements put additional stress on catalyst systems, primarily
attributed to sub-optimal operating temperatures and elevated gas turbine NOx and
CO emissions under these operating conditions.
Babcock & Wilcox (B&W) announced that its B&W Environmental segment will design
and supply advanced ash-handling equipment to a U.S. power plant customer. The
contract is valued at more than $10 million.
The project scope includes the design and supply of eight innovative, patented
Allen-Sherman-Hoff® Submerged
Grind Conveyors (SGC), a transfer conveyor, blowers, and other equipment.
As the U.S. Environmental Protection Agency implements new effluent limitation
guidelines (ELG) and combustion residuals (CCR) requirements, B&W
Environmental’s SGC systems offer plant owners an affordable and reliable option
to manage ash and protect the environment.
“We’re seeing significant demand for our SGC technology from plant owners
looking to comply with new environmental standards,” said B&W Chief Operating
Officer Jimmy Morgan. “Our advanced ash handling system offers a simplified,
flexible design for effective bottom ash transport and dewatering, and
eliminates the need for ash ponds altogether.”
B&W Environmental’s SGC is strategically designed and sized so that it does not
require the removal or displacement of bottom ash hoppers or slag tanks, ash
gates, clinker grinders, transfer enclosures and other existing equipment.
Installation can be accelerated to save time at a lower cost than other bottom
ash conveyance systems.
Consol is Considering a
300 MW Plant to Burn Waste Coal and Biomass
Consol is doing the costing on a 300 MW plant which would burn waste coal and
biomass. It would sequester the CO2. So, the plant would be a
net reducer of CO2 and therefore better than wind or solar which are
just carbon neutral
It has been seven years since the last major new coal-fired power plant started
making electricity in the United States.
The U.S. Energy Information Administration, in its most recent annual outlook,
forecast that zero new coal-fired power plants will be built in the country
through 2050.
But Consol Energy Inc., whose underground coal mining complex in Greene and
Washington counties is the largest in North America, is working to design a
power plant and have it operating by 2027.
Not just any coal-fired power plant. One that can run on wet waste coal from
Consol’s mining operation, capture its climate-warming emissions and spur the
development of a deep underground carbon dioxide storage hub in southwestern
Pennsylvania.
The Cecil-based company said it could begin construction by 2024.
“We’re not inclined to stand still in light of the trends that you are seeing,”
said Daniel Connell, Consol’s senior vice president of strategy. “We’re inclined
to get out in front of it and innovate and transform. We know that we need to do
that in an overall sustainable way.”
The proposed plant is far from certain, but the ambitious — some say unrealistic
— vision is laid out in detail in early design studies that Consol has performed
with federal grants meant to boost the outlook for coal.
The company’s project is one of four that will split an estimated $80 million in
federal funding, the U.S. Department of Energy announced in late October, to
advance the design to a stage where an investment decision is possible.
Consol’s idea is to build a 300-megawatt plant in the vicinity of the
Pennsylvania Mining Complex using a modular, high-efficiency, low-air pollution
technology called pressurized fluidized bed combustion.
A benefit of the technology is its ability to run on a range of fuels —
including the 3 million tons of fine wet waste coal that Consol sends to
disposal ponds each year after it washes and processes its mined coal at its
central preparation plant in Greene County.
For the company, using coal waste means turning an environmental liability into
free fuel.
The proposed plant could also run at least partially on wet biomass — chopped up
grasses and young trees — so Consol is anticipating a large-scale agricultural
operation on land it owns or neighboring farms. Because vegetation pulls carbon
dioxide from the atmosphere as it grows, burning it for electricity in a
facility that captures its carbon emissions means the full
planting-to-power-generation cycle could take in more greenhouse gases than it
puts out.
Consol intends to outfit the plant with a system to remove about 97% of the
carbon dioxide from the exhaust that goes up the smoke stack, compress it and
pipe it to wells that would inject the gas into deep underground rock layers for
permanent storage.
No such transportation and storage network exists in the region — or any nearby
state — at the moment.
But Consol says in the project studies that “several parties are interested in
exploring options for establishment of a ‘regional sequestration hub” in
southwestern Pennsylvania, including an undisclosed “major company” that could
accept CO2 from the region’s concentration of industrial facilities
with Consol’s power plant potentially serving as the anchor tenant.
Mr. Connell said Consol’s geological research as part of its design study will
provide a broader public benefit by helping to define the possibilities for
underground carbon storage in the region.
Those environmental attributes — carbon capture and storage, biomass fuel,
beneficial reuse of waste — would put Consol in a position to qualify for
substantial state and federal subsidies that would be necessary if the pilot
plant is to make any financial sense.
A federal carbon storage tax credit, known as 45Q for its section in the tax
code, is worth $50 per ton of CO2 sequestered underground if the
plant can begin construction prior to January 1, 2024.
Consol expects the plant to capture — and need to store — 2.4 million tons of CO2 per
year.
Consol could also be a major buyer of the on-site electricity that the plant
generates. The mining complex has an energy demand worth about half of the
plant’s proposed output, and the rest would be fed into the regional grid.
Still, the company acknowledges, “Capital costs are expected to present the
greatest commercial hurdle.” The plant’s “overnight” price tag is estimated at
$2 billion.
There is another reason Consol is in a hurry: The majority of its current coal
output goes to feed domestic power plants, and the fleet of U.S. coal-fired
power plants is retiring.
In Pennsylvania, for example, six power plants still burn conventional coal —
down from 23 in 2004, according to the state Public Utility Commission. The
youngest of the plants is 48 years old. Two of the six have already committed to
switching to cheaper, cleaner natural gas, and the others are expected to retire
by the end of the decade.
As the world moves to zero out greenhouse gas emissions by midcentury in an
attempt to avert the most catastrophic effects of climate change, Consol has a
strong incentive to come up with ideas to preserve a role for its product.
A new generation of coal-fired power plants “must have a relatively fast
timeline to commercialization,” the company said, “so that new plants can be
brought online in time to enable a smooth transition from the existing coal
fleet without compromising the sustainability of the coal supply chain.”
‘Foot in the door’
Edward Rubin, an engineering professor at Carnegie Mellon University and a
prominent expert on carbon capture and storage, called Consol’s proposal “a foot
in the door” for future coal development.
The Department of Energy funds a wide array of research and development so the
future electricity system has plenty of fuel and technology options to ensure it
is both cost-effective and resilient.
“We’re basically building an insurance policy, a portfolio of things that may or
may not be useful in the future — though they try to choose things that look
most promising,” Mr. Rubin said.
Consol’s proposal “certainly looks as interesting and credible as lots of other
things that have been done in the past,” he said.
Still, a defining feasibility factor for any carbon capture project is cost, and
unless government policy establishes a price on carbon emissions, it will be
hard for the technology to take root.
“There is no market for any carbon capture technology without a policy driver to
reduce carbon emissions,” Mr. Rubin said. “No matter how cheap you can make a
carbon capture system, it will always be more expensive than not having to use
one at all.”
Rob Altenburg, director of the statewide environmental nonprofit PennFuture’s
Energy Center, was more skeptical about Consol’s proposal.
“My bet is this plant never gets built, not without serious government
subsidies,” he said. “Investors are not going to line up behind this deal.”
The capital costs are exorbitant compared to competing energy sources, Mr.
Altenburg said, and other financial projections are unrealistically optimistic.
For example, Consol expects that once it is up and running, the plant will
operate at full capacity 85% of the time. But existing coal plants with proven
technology have historically only run about 65% of the time.
Even assuming that one demo plant could be built in a Goldilocks spot where all
of the pieces fall into place, he doubted the technology could be scalable.
“The thing is, there just isn’t any need,” Mr. Altenburg said. “In a lot of
places in the nation, it is cheaper to build new solar than run existing gas,
and gas is already cheaper than coal.”
The next step
Consol’s next step is to develop a detailed front-end engineering and design
study. The recently announced federal funding will cover about 80% of the cost,
Consol CEO Jimmy Brock said during the company’s most recent call with
investors.
The study will take 2½ years and focus on both honing the design of the power
plant and better characterizing the geological opportunities for storing carbon
nearby, said Mr. Connell, the senior vice president.
Part of the process will include selecting a site for the plant and preparing
the volumes of environmental information that will be necessary for permits.
At the end of the 30 months, the company hopes to have enough definition of the
project and its economics to decide whether it is worth an investment.
New Turbine With
15 ppm NOx Emissions Installed in Germany
MTU Power installed the first LM2500 DLE (15 ppm NOx) gas turbine in
Europe on behalf of long-term partner Stadtwerke Erfurt.
The 22 MW LM2500 DLE, which emits 15 ppm NOx, has just entered
commercial operation at the Stadtwerke Erfurt, a municipal energy provider in
Thuringia, Germany. The new turbine is significantly more efficient and helps
the customer go above and beyond federal emissions requirements.
“The turbine produces a mere 20% of the emissions of its predecessor,” said
Janko Matheussik, project manager, MTU Power. “This goes above and beyond the
necessary reduction in emissions mandated by the German federal government and
is significantly more efficient.”
Because of the German government’s emissions and efficiency targets, the
Stadtwerke Erfurt exchanged a LM2500 SAC engine after just 20 years, although
gas turbines typically have a much longer lifetime.
“In order to be as sustainable as possible, we decided to replace the turbine,
but keep as much of the package as possible,” said Marco Tuerke, head of power
generation, Stadtwerke Erfurt. The power plant provides over 40,000 households
with heat energy in the surrounding region.
“Old systems that were no longer needed, such as the water injection system and
liquid fuel system, had to be removed,” said Christian Zierold, project buyer
MTU Power.
Further, the control system was upgraded to the state-of-the-art Woodward
control Micronet+ system. The gas turbine compartment was also completely gutted
and modified to suit the new turbine.
Beyond this, the gas system was also renewed: a new fuel metering skid was
added, shut off valves and gas relief valve exchanged and repositioned, as well
as gas piping renewed and rerouted and a calorimeter for gas analysis installed.
Additionally, by-pass ducts on the filter house needed installation to reduce
inlet pressure losses. Then the new turbine had to be installed and the new
model be made to fit the space the older turbine had occupied.
A second turbine is due to be exchanged during Summer 2021, when MTU Power will
be carrying out an installation and remodification project for the sister unit.
Both LM2500 DLE turbines significantly surpass current emissions requirements
and are an investment in the future for the Stadtwerke Erfurt, the company said.
The MTU Power team will be supporting their valued customer with all
maintenance, repair and overhaul needs for the coming 10 years.
Power Plant on
Reunion Island to Be Converted to Biomass
A 108-megawatt (MW) coal-fired power plant located on an island in the Indian
Ocean located approximately 500 miles east of Madagascar will soon be converted
to biomass, according to France-based power producer Albioma.
Albioma announced on December 8 that its Bois-Rouge power plant located on
Reunion Island will be converted to take in biobased fuel. Conversion work will
begin as early as 2021 with the facility expected to run on 100 percent biomass
by the second half of 2023.
Priority will be given to locally produced biomass, including bagasse, forest
wood, and pruning wood, and supplemented with sustainably certified imported
wood pellets.
According to Albioma, the conversion will increase the island’s renewable power
mix to 51 percent, up from a current 35 percent. A power purchase agreement for
the facility has been extended until 2043.
Idemitsu Breaks Ground
on 50 MW Biomass Plant in Japan
Japanese energy company Idemitsu Kosan Co. Ltd. announced on November 30 a
groundbreaking ceremony for its 50 megawatt (MW) Tokuyama biomass plant, a
facility under development in Shunan City, Yamaguchi Prefecture.
The facility is scheduled to be complete in June 2022 and begin commercial
operations by December 2022. The plant will be fueled with imported wood pellets
and palm kernel shells (PKS), requiring approximately 230,000 metric tons of
fuel annually.
Idemitsu announced plans to proceed with the development of the plant in
mid-2019. The project is being developed at a former refinery site and will use
existing infrastructure.
B&W Thermal Announces
$10 Million in Service Contracts
Babcock & Wilcox (B&W) announced today that its B&W Thermal segment has booked
new service projects valued at more than $10 million. These contracts, for
utility and industrial facilities, are in addition to more than $30 million in
construction services bookings recently announced by B&W.
“B&W Thermal’s service capabilities are a cornerstone of our growing business,”
said Jimmy Morgan, B&W Chief Operating Officer. “Customers turn to B&W Thermal
to ensure their energy and industrial plants continue to operate efficiently and
reliably, or when they need service or upgrade work to improve performance.”
“B&W Thermal is known for providing reliable service and exceptional engineering
expertise,” Morgan said. “The service agreements we’re announcing today
represent a broad spectrum of the markets we serve, including utilities, natural
gas, petrochemical facilities, iron and steel manufacturing and more.”
B&W Thermal responds to and solves customers' toughest boiler and environmental
equipment challenges. Its highly skilled field service engineers, service
specialists, and resident service engineers are strategically located in offices
worldwide to provide technical assistance whenever the need arises.
Wheelabrator Technologies Inc.
Signs Definitive Agreement for Sale of Wheelabrator Technologies U.K. to First
Sentier Investors
Wheelabrator Technologies Inc. ("Wheelabrator Technologies") announced that it
has entered into an agreement to sell WTI / EFW Holdings ("Wheelabrator U.K.")
to the European Diversified Infrastructure Fund III SCSp ("EDIF III"), an
infrastructure fund managed by First Sentier Investors ("FSI"). The transaction
is expected to complete in early 2021.
Wheelabrator U.K. is the largest pure play waste-to-energy business in the U.K.
and is a developer, owner, and operator of strategically located waste-to-energy
facilities, with seven waste-to-energy facilities in operation and advanced
development. Wheelabrator U.K. is an integral part of the U.K.'s environmental
infrastructure, diverting waste from landfills or export to continental Europe
to provide residents and businesses with local, sustainable disposal of
non-recyclable solid waste while creating renewable energy.
Wheelabrator Technologies was acquired by Macquarie Infrastructure Partners
IV ("MIP") in February 2019. MIP operates within the Macquarie Infrastructure
and Real Assets division of Macquarie Group, the world's largest infrastructure
manager.
In the past 12 months, Wheelabrator U.K. reached commercial operations at
Wheelabrator Kemsley, a combined heat and power facility that provides steam to
the DS Smith paper mill located in Sittingbourne, Kent and reached commercial
operations at two new waste-to-energy facilities in North Wales and West
Yorkshire, Wheelabrator Parc Adfer and Multifuel Energy Limited Ferrybridge 2.
The business continues to progress the advanced development of three further
waste-to-energy facilities, Multifuel Energy Limited Skelton Grange in
Yorkshire, Wheelabrator Kelvin in West Bromwich, and Wheelabrator Kemsley North
in Sittingbourne.
Robert Boucher, President & CEO of Wheelabrator Technologies, said, "I am
incredibly proud of the U.K. team and what we have achieved as One Team to grow
the Wheelabrator U.K. business over the last 11 years. I look forward to the
business continuing to execute on their strategy for continued development of
critical waste infrastructure in the U.K. with their new shareholder and
partner. The buildout of the largest, pure play waste-to-energy business in the
U.K. is the result of many years of commitment, hard work, and strong
partnerships with our customers and partners, and our ability to leverage our
operational excellence from the U.S. and embed it into the U.K."