World Regions

$466m CHP investment planned for eastern Europe

Diarmaid Williams — Fri, 14 Jun 2013 15:52:00 GMT

A Czech Republic-based private equity company plans to invest in cogeneration plants in central and eastern Europe as policy changes in the region make renewables less attractive.

EnerCap Capital Partners plans a new fund to raise as much as $466m for the technology, Shane Woodroffe, a partner at the Prague-based company, told Bloomberg that EnerCap may also sell assets in its 98 million-euro renewables fund with wind farms in Poland, Romania and the Czech Republic “in one piece, or in two or three pieces.”

EnerCap decided to focus on gas and biomass-fired CHP projects rather than on renewable power because of “current uncertainties” about government support for wind and solar in countries such as Romania and Poland, Woodroffe told the news agency.

Those nations are seeking to reduce financial support for clean power to stem costs to consumers.

The company has secured a pipeline of CHP projects in the region, it said in a separate statement.

For more combined heat and power news

Study finds New England distributed generation could triple

Diarmaid Williams — Thu, 13 Jun 2013 11:13:00 GMT

A study by Synapse Energy Economics, entitled, “Forecasting Distributed Generation Resources in New England: Distributed Generation Must Be Properly Accounted for in Regional System Planning” forecasts growth in distribution generation for the US state.

The study predicts New England distributed generation could roughly triple in the next decade – but advised that regional electric grid operator ISO New England Inc. needs to account for distributed generation in its planning.

In the past decade, New England ratepayers have spent approximately $5bn on transmission additions and expansions and the study suggests that ISO New England may be underestimating the extent to which non-transmission alternatives like distributed generation can satisfy demand at a lower total cost than transmission line development.

According to Synapse, ISO is “ignoring likely transmission and reliability benefits and overestimating electricity load—with ratepayers being asked to pay for larger, more expensive transmission upgrades than are needed.”

ISO New England predicts that about 800 MW of solar photovoltaic generation will be installed in New England by 2021, but excludes other types of distributed generation from its projection.

Synapse’s report concludes, “It is essential that the ISO stop ignoring the impacts DG resources have on system planning—both their benefits and their challenges. This report provides a reasonable estimate of what the future holds for these resources and makes one thing very clear: assuming that these resources do not exist is unacceptable.”

For more North American CHP news

World’s largest cooling unit launched at Burj al Arab

Diarmaid Williams — Wed, 12 Jun 2013 16:02:00 GMT

The WCT 6000 cooling unit was launched this week at the iconic Burj Al Arab building in Dubai by Daikin Middle East.

Proclaimed as “the largest commercial capacity district cooling chiller in the world” the WCT 6000 is expected to find a huge market across the MENA region.

Daikin McQuay installed the original air conditioning chillers for the Burj al Arab and Jumeirah Beach Hotels, which have a capacity of 12,800 tonnes of refrigeration as well as the One & Only Royal Mirage and the Business Bay district cooling plant.

The unit was launched at the Al Falak ball room on the 27th floor of the Burj Al Arab, around 200 guests were taken through the full specification of the new chiller

Claudio Capozio, Europe, Middle East & Africa CEO said: “As energy demands and costs rise, district cooling plants for offices, industry and homes needs to be increasingly efficient, reliable and sustainable.”

The units can be installed in series to meet specific air conditioning and cooling needs.

For more district cooling news

Ireland positive about CHP potential

Diarmaid Williams — Tue, 11 Jun 2013 16:20:00 GMT

A workshop held in Dublin last week brought national energy stakeholders together to discuss the development of an Irish Cogeneration Roadmap.

The workshop identified potentials for energy efficiency improvements in line with the framework of the CODE2 project.

Industrial cogeneration emerged as a key element in reaching the national energy savings target.

“My country is well on its way to implementing a cogeneration friendly framework”, MEP SeÃ¡n Kelly said. “With such a policy we can kill two birds with one stone: improving the competitiveness of industries hosting cogeneration units while reducing their climate footprint. If Europe wants a way out of its economic crisis, this kind of approach should be replicated.”
Ireland’s energy challenges are exacerbated by the specific situation of being an island. The need to lower primary energy imports for industry and power, which is a major issue in Europe as a whole, is particularly acute in Ireland. Finding a way to provide industrial and commercial heat in the most effective way is one of the focus topics of the workshop.

For more European CHP news

Capitol Hill’s power plant to switch to gas-fired cogen

Dr. Heather Johnstone — Mon, 10 Jun 2013 16:11:00 GMT

The District Department of the Environment (DDOE) in Washington D.C. has given a green light to the Architect of the Capitol’s (AOC) plans to convert the coal-fired Capitol Power Plant to 100 per cent natural gas.

The plant, which currently supplies heat to the Capitol campus – including the United States Capitol, the Supreme Court, the Library of Congress and 19 other buildings in the complex - is not currently equipped to run solely on natural gas.

The AOC had to seek permission from regulators to expand operations for the new cogeneration plant, which allows the switch from coal.

“After more than 100 years in operation, significant investment is needed to replace aging infrastructure and equipment. Cogeneration is an environmentally-friendly, cost effective and highly efficient technology,” AOC Stephen T. Ayers said in a statement.

However, local activists and environmental groups raised concern because the permission to proceed from the regulators did not come with a stipulation that the plant completely stopped firing coal.

The AOC has stated that during times of high energy demand, it might be necessary to use coal as a last resort to make sure energy needs are met. The plant will also have coal on hand to meet demand until the cogeneration plant is completed.

The US EPA signed-off on the plans in January, and the DDOE approval, granted late last week, marked the final hurdle to starting construction.

For more Cogeneration/CHP news.

US CHP system maker’s IPO aims to raise US$25m

Dr. Heather Johnstone — Mon, 10 Jun 2013 15:19:00 GMT

Tecogen, the Massachusetts-based, modular CHP system manufacturer, has reportedly filed for an IPO on NASDAQ, and is seeking to raise $25m.

Tecogen began in the early 1960s as a research division of Thermo Fisher Scientific. And since its spin-off 13 years ago, the company has shipped in the region of 2000 cogen units.

Over the past year, Tecogen has reportedly booked around $16m in sales of its core CHP products, which include cogeneration units, such as its InVerde Ultra 100 CHP module (pictured) that supply electricity and hot water, chillers that provide air-conditioning and hot water and high-efficiency water heaters.

Its traditional customers include hospitals and nursing homes, colleges and universities, health clubs and spas, hotels and motels, office and retail buildings, food and beverage processors, multi-unit residential buildings, factories, municipal buildings and military installations.

For more Business news.

For more Cogeneration/CHP news.

Texas’ policy clarification removes barriers to cogen

Dr. Heather Johnstone — Mon, 10 Jun 2013 15:03:00 GMT

The Texas Legislature (pictured) in the US recently passed House Bill 2049, which removes regulatory barriers and improves the business climate for cogeneration facilities by clarifying language in the Texas Utility Code.

The change now enables CHP facilities to sell electricity and heat to the same customer within the proximity of the facility, thereby maximising efficiency and minimising financial risk.

Prior to the change, cogeneration facilities could sell electricity to only one customer.

"Texas legislators understand the need to remove regulatory barriers, and HB 2049 is one example that will help usher in new cogeneration project opportunities”, says Paul Cauduro, executive director of the Texas Combined Heat and Power Initiative.

Research has determined that by raising CHP from 20 to 35 per cent of total electricity generation, Texas could add 14,000 MW to the state's grid by 2025.

For more Policy & Regulation news.

For more Cogeneration/CHP news.

E.ON makes investment in distributed energy tech

Dr. Heather Johnstone — Thu, 06 Jun 2013 14:58:00 GMT

E.ON’s interest in distributed and smart energy solutions is continuing, with the German utility giant recently making a number of strategic co-investments in startup companies.

E.ON (FWB: EOAN) has become an investor in Munich-based Orcan Energy GmbH, a spin-off from Munich Technical University.

Orcan is the technology leader in small-scale modular Organic Rankine cycles, a technology for using waste heat to generate electricity. The modularity of its product (pictured) combined with its highly differentiated cost structure gives it the potential to dramatically alter the waste heat recovery market.

E.ON sees the partnership as a significant opportunity to supplement its broad range of different-sized CHP units, to provide solutions for industrial customers and to increase the output of its biogas-fired power plants.

Fuel cells are gaining an increasing share of the distributed generation markets in the US and Japan, so E.ON is taking a stake in Bloom Energy, a California-based provider of solid oxide fuel cell technology.

In addition, E.ON has become a limited partner in The Westly Group, an American venture capital firm that focuses on cleantech companies in areas such as e-mobility, renewable energy, smart grids, and energy efficiency for buildings.

“With our newly established venture-capital activities we make targeted investments in companies with technologies or business models that could improve or expand E.ON’s portfolio of products and services.

“Our investments focus on business models for distributed energy, smart grids and renewables”, said Urban Keussen, senior vice president for Technology & Innovation at E.ON SE.

For more Business news.

For more World news.

Huge scope for the DPG market in Mexico

Diarmaid Williams — Fri, 31 May 2013 16:20:00 GMT

A new report from Frost and Sullivan claims the potential for the distributed power generation (DPG) market in Mexico is very promising.

The market will witness strong demand from oil, gas and mining companies in Eastern Mexico, a region not served by the national grid.

New analysis from Frost & Sullivan -Analysis of the Mexican Distributed Power Generation Market, finds that the market earned revenues of more than $217.6m in 2012 and estimates this to reach $370.2m in 2017 at a compound annual growth rate of 11.2 per cent.

Insufficient centralized electricity, which has compelled several consumers to generate their own power, along with incomplete grid facilities in large isolated areas, offer huge scope for the DPG market in Mexico, according to Frost & Sullivan Energy and Environmental Industry Analyst Martin Cataife.

"Recent net metering regulations in the country have encouraged the assembly of new DPG units in households and small commerce consumers. Net metering of expensive tariffs in the industrial segment has also sustained overall DPG installed capacity growth rates."

However, DGP providers' reliance on electricity subsidies coupled with grid integration issues in isolated areas make market development uncertain. Energy subsidies have added to the challenge, as artificially low electricity prices for most consumers in the country reduce opportunities for DPG technologies, which have become a costly alternative to grids.

In fact, although DPG technologies reduce transmission costs and provide the benefit of local energy management and economies of scale, their startup costs are higher than that of centralized electricity production, further affecting adoption.

For more Latin American CHP news

KBR wins USAF on-site power contract in Qatar

Diarmaid Williams — Wed, 29 May 2013 10:44:00 GMT

A joint venture between KBR and CH2M Hill has successfully bid for a contract to provide, operate and maintain power plants to the US Air Force at its Al Udeid Air Base in Qatar.

The $17.9m deal is for two years, with the option to extend for a further two years and has been awarded under the Air Force Contract Augmentation Program (AFCAP).

The work will include electrical power production and distribution to various base facilities on Al Udeid Air Base and the airfield lighting system.

Andy Summers, president of KBR's infrastructure, government and power division, said: "This award marks the 40th task order award to our joint venture under AFCAP and shows the continued trust and confidence our client places in us to support their mission-critical, overseas operations.

For more on-site power generation news

E.ON’s entry into European micro-CHP market ‘timely’

Diarmaid Williams — Fri, 24 May 2013 14:07:00 GMT

German power generation business, E.ON (FWB: EOAN), is entering the European small scale gas combined heat and power (CHP) market at just the right time, according to the director of Edinburgh-based energy consultancy,Delta-ee.

Michael Brown, Director at the consultancy says the company is correct to enter the European market for CHP systems under 1MWe,

Delta-ee's projections see annual deployment of around 1.5 – 2.0 GWe for CHP projects in the 0.4 – 5.0 MWe size, and up to 1.5 GWe for projects in the 10 – 400kWe size by 2020.

E.ON has recently struck a partnership with METRO Cash & Carry to distribute energy under which it will install gas-fired small scale CHP units at two Metro Cash & Carry wholesale stores in Germany, as well as two more in Russia.

"If E.on is to compete effectively, it's going to have to be great at what many utilities are traditionally not always great at – being very customer-oriented and knowing their customers really well," Brown told Gas to Power Journal. "It will also need to ensure it can keep its transaction costs or its project acquisition costs down at levels which the other smaller players have [already] achieved."

Brown pointed out that E.ON will have a competitive advantage in some areas due to its role as a major gas supplier and electricity trader.

"Acquiring one or more existing players might also be an effective strategy. [Still], we reckon this is a growth market over the medium-term so there's room for new entrants like E.ON without necessarily driving out existing players."

E.ON has recently created a new company called E.ON Connecting Energies to handle distributed energy solutions, energy efficiency, and renewables.

For more European CHP news

Green light expected for Serbian biomass CHP project

Dr. Heather Johnstone — Thu, 23 May 2013 08:33:00 GMT

A project to build a biomass-fired cogeneration plant to meet the needs of a remote heating system in the northern Serbian town of Senta, as well as produce low-carbon electricity, is one step closer to being implemented.

At a recent meeting in the town attended by the state secretary of the Energy Ministry, Dejan Novakovic, details of the project were presented.

It will be built in two phases. The first phase, which is valued at EUR15.2m (US$m), will produce 8.4 MW of heat and 4.9 MW of electricity, with a second phase scheduled to be completed in 2015-16.

The plant will require 35,000 tonnes of biomass a year, which will be supplied by agricultural manufacturers in neighbouring municipalities.

Also present at the meeting were representatives of Belgium’s renewable energy project developer WindVision and Synvalor of the Netherlands, which will design the plant.

In February, the Serbian government announced that it aims to add 1092 MW of renewable energy capacity by 2020.

For more Cogeneration/CHP news.

For more Europe news.

Cogeneration taking centre-stage in China

Wed, 22 May 2013 19:51:00 GMT

Shanghai is the city thought to offer the best opportunities for overseas equipment makers to bid for industrial-scale cogen projects

China's new administration has ambitious cogeneration plans, with a target of 30 GW of new gas-powered plants, many of which will be CHP-based, by 2015. David Green scrutinizes the plans and highlights the opportunities for foreign manufacturers.

With the once-in-a-decade handover of power within China's Communist Party government complete, the country's new administration is beginning to find its feet. It is a process that has profound implications for the cogeneration/CHP sector in the world's most populous nation.

At the heart of the opportunities related to cogeneration is a government plan entitled Guiding Opinions of the Deployment of Gas-Fired Distributed Energy. The document, jointly released by the National Development and Reform Commission (NDRC), National Energy Administration and Ministry of Finance, sets goals to develop 5 GW of gas-fired combined cooling, heating and power (CCHP) by 2015, and a total 50 GW by 2020.

While this document was released in 2011, it is only very recently that these notional goals have begun to manifest themselves as tangible projects for which companies have been invited to bid.

Importantly, these cogen targets are under pinned by detailed energy policies in China's 12th Five-Year Plan for Energy Development, which notionally runs from 2011 to 2015, but essentially is a three-year programme. It includes a number of overarching policy targets with an indirect bearing on the market for cogeneration, and was unveiled in January by China's State Council.

At its heart this plan is a blueprint for greater energy security and reduced energy intensity, just the kind of priorities that favour cogen. The latter aim is perhaps best encapsulated by a stated goal of reducing energy consumption per unit of GDP by 16%, and CO₂ emissions per unit of GDP by 17%.

More specifically, there are a number of important targets related to the role of natural gas in the energy mix, primarily doubling its share of the total by 30 GW to 8%, but also that of raising proven conventional gas reserves by 3.5 trillion m³ and building 44,000 km of natural gas pipelines, as well as the production of 6.5 billion m³ of shale-sourced gas per year by 2015, increasing to 80 billion m³ by 2020.

These targets dovetail neatly with the explicit cogeneration goals made by the NDRC, National Energy Administration and finance ministry.

China has also tied these two policy goals in a policy paper released last June (2012) entitled the 12th Five Year Plan for the Development of City Gas, which notes that every 10,000 m³ of natural gas consumed in China saves annually the consumption of 12.7 tonnes of coal equivalent and 33 tonnes of CO₂ emissions.

And while restrictions on gas supply and the high price of imported gas (relative to coal) have presented a major barrier to the accelerated construction of even mid-scale gas-fired power plants, China has already made significant moves to diversify its access to the fuel via the signing of agreements to import liquefied natural gas from neighbours overseas and pipe in supplies from Central Asia, Myanmar and, most recently, Russia.

In March, Moscow and Beijing signed an historic deal for Russia to pipe 38 billion m³ of natural gas to China each year starting in 2018, with an option for this to increase to as much as 60 billion m³ annually. In 2011, China consumed about 130 m³, which gives an indication of the importance of the agreement in terms of securing future supplies.

Foreign maunfacturers set to benefit

These aims and agreements are important because it is the gas-fired arena that offers the most enticing and realisable cogeneration opportunities, particularly for foreign equipment suppliers.

And with the new administration in place, all these energy policies are starting to translate into action.

'From late last year China began opening the door to cogen. Several projects have been issued tenders but they did not fit our portfolio, but it's a nice change to have people come knocking on the door asking for bids,' says Luca Febbraio, north east Asia regional director and vice president for Power Plants at WÃ¤rtsilÃ¤ China.

The Finnish company, which specialises in 30 MW to 100 MW trigeneration projects, has its eye on a couple of proposals but the relevant feasibility and cost-benefit studies have yet to be granted approval by the local authorities, in part a consequence of the lack of a clear policy framework for how this kind of industrial-scale cogeneration project should work.

'There's a plan from the Shanghai government to give an allowance per kWh of CHP. But it takes a clear price and a sustained policy framework for an investor to put his hand in his pocket,” says Tim Scott, commercial marketing manager for Caterpillar's Electric Power division.

However, that landscape is now starting to change.

The Shanghai government has released a draft plan seen by Cogeneration & On-site Power Production that stipulates gas-fired CHP projects will be offered a subsidy of CNY1000 (US$162) per kWh of installed CHP capacity, and have priority when it comes to supplying power to the national grid. hat incentive rises to an additional CNY2000 if after two years the project can prove it has been operating at more than 70% efficiency.

Moreover, such CHP projects will also benefit from receiving a preferential price for the gas they use, although the details of how this might work have yet to be determined by the Shanghai authority.

In March, the State Grid Corporation of China, the country's largest state-owned utility, provided a further indication of the momentum in this area by saying that it would permit easier access to the power grid for small distributed energy resource (DER) power projects of no more than 6 MW that are fuelled by natural gas, wind and solar energy, and which could also be cogeneration plants.

At present, experts estimate there is no more than several hundred MW of installed gas-fired cogen capacity that fits the type of DER project called for by the government's plan, indicating the scale of potential opportunity in the field as the market begins to open up.

Opening up of market

At the time of going to press that is exactly what was happening in Shanghai, where foreign and local players were in the process of bidding for a project at the Shanghai Disneyland site, the details of which are not available to the public as they are commercially sensitive.

Elsewhere in the city, the Caterpillar-owned MWM brand recently secured orders for two sets of its super-efficient TCG 2032 V16 natural gas engines for running a CCHP plant at the Shanghai Expo Convention Centre.

In Beijing, GE announced in January that it had won the contract to supply China National Petroleum Corporation with five Jenbacher cogen systems to power a 16.7 MW on-site CCHP plant for a new data centre in the city, the largest gas-engine CCHP project in the country. The project is something of a coup for GE, as it will likely be used as a model for similar facilities going forward.

The US company is particularly well placed to benefit from the development of the gas-fired cogeneration sector, after it signed an agreement to create a $100 million joint venture developing aeroderivative gas turbines, core devices used in distributed energy systems, with the China Huadian Group. This in turn helped the US firm secure a contract from Huadian to supply a 100–120 MW cogeneration system for an industrial park in Fujian.

Slow on policy front

But such examples of concrete projects are still few and far between due to the slow progress on the policy front. In Beijing, there is another set of draft guidelines circulating, but according to WÃ¤rtsilÃ¤'s Febbraio it is very light on detail, though there is apparently mention of dropping a current 10% tax levied on imported power equipment.

'Every municipality is looking at a different policy. That's why so far there is no private investment – people are waiting for these drafts to be finalised, but it's not fast enough,' explains Febbraio. 'There is momentum but I doubt this is going to result in 50 GW by 2020.'

Even so, Japan's Mitsubishi Heavy Industries (MHI) just last month moved to take advantage of any openings by signing an agreement to license its KU gas engine technologies to ZGPT Diesel Heavy Industry, a Chinese manufacturer of stationary and marine engines. MHI has said that the licensing agreement envisages the manufacturing and marketing of its 14KU30GSI 4450 kW-class gas engine, which is widely used for DER projects in Japan, but would probably be expanded to include other models and would also probably be used in cogeneration projects.

China favours the use of domestically-produced equipment over imports. Against this background, MHI's agreement with ZGPT gives the Japanese company greater scope to sell its products in the Chinese market.

Interest in large-scale cogen/CHP

Febbraio also suggests that because it is imperative, at least in terms of saving face, for the government to meet the stipulated 50 GW target, there is a very strong possibility that incentives may be widened to apply not just to small-scale DER projects, but also larger gas-fired cogeneration plants, as this will have the effect of ratcheting up relevant installed capacity figures.

'All the current DER projects are officially pilots, so the government can assess the economics,' Febbraio says. 'Yet the assessment process is bound to take at least two years, leaving precious little time for the government to meet its 50 GW installed capacity target via DER alone.' This potentially opens the policy incentives to larger gas-fired cogeneration plants, and with it a broader spectrum of equipment and suppliers, he explains.

Alstom has sold five of its E-class gas turbines into China since the start of FY 2012–13 for a combined contract value of about €100 million Credit: Alstom

Irrespective of how this pans out, and it is impossible to say with so much still on the drawing board and each local government rolling out its own polices, there has already been a substantial amount of recent project approval activity for larger gas-fired cogeneration plants on the scale of several hundred to >1000 MW.

'There is a phenomenal amount of new gas-fired combined-cycle capacity coming on line, beyond what you would expect to be supported by the economics,” says Gavin Thompson head of Wood Mackenzie's China Gas and Power research team in Beijing.

Almost all of this is in coastal provinces and is a response to rising peak demand, which power suppliers are finding it difficult to meet when relying on electricity transmitted from interior provinces and seasonal hydroelectric power. The CCGT plants are a lot more flexible and allow the power suppliers greater leeway to regulate their power supply, Thompson said.

'So there are a number of non-pure economic factors driving this, as well as subsidies. These come in the form of preferential pricing when selling to the grid, though the way this works varies from province to province.'

Major foreign equipment suppliers must leverage their official and unofficial agreements with Chinese counterparts to get a look in on these projects, which represent a substantial policy shift that has drawn the attention of a wide selection of companies.

'The reality was that China used to be a very small market, as there were restrictions on gas availability,' says Pascal Radue, Alstom's Singapore-based area vice president for Gas. “But with the increased environmental concerns the mindset changed and suddenly there was an opening of the market – it opened at the same time as we started to be more aware of it.'

Since the start of the FY 2012–13, Alstom has sold five of its E-class gas turbines worth about €100 million ($130 million) into China, all via a project-specific relationship with Harbin Turbine, which in turn is a supplier to leading power utility Huaneng Power.

Alstom is keen to formalise the arrangement, which it deems essential to doing further business in China. This will bring the company into line with the other major suppliers of gas-fired equipment, all of which have signed similar agreements. Aside from the aforementioned tie-up between GE and Huadian, other examples include MHI and Dongfang Electric, as well as Germany's Siemens with the Shanghai Electric Group.

Access to projects led by Huaneng would be a boon for any overseas gas turbine supplier, as in a little over a year the company has signed off on three cogeneration plants, the largest of which is a massive 1500 MW facility in Chongqing, and aims to raise this to five projects in the near future.

'There's no specific plan yet, but gas-fired cogeneration is encouraged by the government,' says a Huaneng spokesman surnamed Zhou. The company has already worked out cooperation agreements with gas suppliers, and is positioning itself to move away from coal and towards gas. However, the scenario remains a nightmare for potential investors, as there is again something of a policy vacuum at the center of the projects.

'The tariff level [of the generated electricity] has not been determined,' says Zhou. 'Each project will have a different tariff based on the local price of gas and the profitability of the plant.'

While this presents obvious problems, power companies appear content to push on, safe in the knowledge that the government will construct policy around their projects in a way that makes them economically viable.

As a case in point, GE, which is the largest supplier of heavy-duty gas turbines to China with an installed capacity of 15,000 MW, in September last year was commissioned to supply three of its 9FB gas turbines for the Datang Gaojing combined-cycle cogen power plant under construction in Beijing. The plant, which is scheduled to start commercial operation in stages beginning October 2013, will generate more than 1.3 GW of electricity and operate in tandem with a district heating solution provided by Harbin Electric Corp.

The confidence to proceed with such projects without the necessary financial details is in part borne of a firmly held belief that the government is serious about its stated commitments to improving the environment, and air quality in particular. 'I was surprised because for the first time meetings started with officials citing environmental concerns – I don't know if it's their own drive or they expect policy support to come from that direction, but it was a significant change,' notes Alstom's Radue.

While the increase in gas-fired cogeneration plant approvals is primarily a consequence of the government's desire to shift away from dependence on heavily polluting coal and hence improve air quality in major cities such as Beijing and Shanghai, there is also another factor at play, suggests Yang Fuqiang, senior adviser on Climate, Energy and Environment at the US-based Natural Resources Defense Council's China Programme.

'During the recent economic slowdown and consequent weaker demand for power, utilities believed that cogeneration projects would be protected and have first access to power sales on the grid,' Yang says. Under a long-standing policy to encourage CHP development, cogeneration projects are guaranteed a smoother approval process but also priority to sell their power to the grid, prompting utilities to back such projects to ensure they can sell their power even during lulls in economic and industrial activity.

Yang also provides a useful perspective on how the cogeneration landscape will probably develop going forward. 'At the moment about 95% of installed cogeneration capacity in China is thermal coal. The gas projects have been slow to catch up for the simple reason that there have been restrictions on gas supply,' he says. 'But in the major cities that are suffering from air pollution there is now a shift to gas for environmental reasons. It is also a lot easier to regulate the use of gas-fired cogeneration facilities to match demand for both heat and power, making these systems more attractive.'

Asked about the outlook for coal, Yang suggests new capacity is no longer approved near major cities, but that it would remain cost effective to develop coal cogeneration projects in China's regional mid- to lower-tier cities. Under an ongoing government drive to phase out smaller, less efficient coal plants, only those coal CHP plants in the range of 200 MW to 300 MW or larger now receive the necessary local government approvals, wherever they may be.

China aims to have 30% of its coal-fired power capacity operating as cogeneration by 2015, against Yang's estimate of about 27% currently, allowing scope for the approval of such projects in smaller cities to make up the gap. However, Yang is quick to point out that the big five Chinese power companies (Huaneng, Datang, Guodian, Huadian and the China Power Investment Corporation) dominate this area, and that they are experiencing a number of operational difficulties that have yet to be resolved.

'There are problems in terms of distributing the heat from these projects: Who will pay for the pipe networks? Who is responsible for maintenance and quality of heat supply, and who is responsible for collecting the payments for the heating?' he asks, adding that a major benefit of the smaller gas-fired DER projects is that having only one consumer eases the logistics of pricing and payment.

In Yang's view, it is Shanghai and the southern manufacturing hub of Guangdong province that will offer the largest opportunities in terms of small-scale DER. 'The [local] governments there are much more open to foreign involvement in such projects,' he says. 'On the other hand, it is harder to secure the gas supply than in Beijing, where political factors often restrict foreign competition from entering the market.' Yang also highlighted that the warmer climate in China's south will probably ensure that the majority of projects there will require trigeneration, or CCHP, systems.

Meanwhile, although secondary in importance to the other major policy drives, another significant plan found its way into the public domain just last month, when the Ministry of Industry and Information Technology released its own Five-Year Plan for Industrial Energy Saving.

While it is again light on crucial detail on how sticking points like grid and heating connection issues might be overcome and paid for, the plan shines a light on the next step for the promotion of CHP in China. The plan calls for the development of cogeneration in the iron and steel, nonferrous metals, chemicals, light industry and others.

It also references the development of urban infrastructure to support the production and distribution of the generated heat and electricity, and promotes the use of back-pressure and exhaust-condensing steam turbines, micro turbines, screw expansion generators and other equipment.

Given the lack of policy progress in the more highly favoured area of gas-fired cogen, it is tempting to label such calls as specious. However, as World Resources Institute senior associate Sarah Forbes suggests, China has a strong precedent in integrating waste products produced from industrial process in coal-to-chemical plants, where it is a world leader, suggesting that doing similar with industrial cogeneration may not be such a remote possibility.

'There's more coal-to-chemical going on in China than anywhere else in the world, and it is all incredibly integrated. The growth in the energy sector here presents an opportunity to truly integrate energy across the board.'

David Green is a China-based freelance journalist, who writes on energy matters.

More COSPP Articles Past COSPP Articles

Reaching the summit

Wed, 22 May 2013 19:30:00 GMT

for off-grid renewable

The world's largest off-grid renewable energy initiative in Ladakh consists of 28.3 MW of solar PV, small hydro and solar thermal in North India's Jammu and Kashmir province. Duncan McKenzie finds out how this remote place came to be the focus of this initiative.

Leh, in Ladakh, India, is benefitting from a major government-backed renewable energy initiative Credit: D. McKenzie/LREDA

Ladakh, a remote district set in India's northern-most state, is enjoying the benefits from the largest off-grid renewable energy project in the world.

The Ministry for New and Renewable Energy (MNRE) is spending a jaw-dropping INR473 billion (US$88.8 million) on decentralized solar and hydro technologies to bring energy security to this remote mountain region. The obvious question is: Why Ladakh?

'Because we Ladakhis are closer to God,” smiles Jigmet Takpa, project director of the Ladakh Renewable Energy Development Agency (LREDA). “Our sunshine is high quality. We have an average of 320 sunny days every year and the mountain air is thin and cold, making the operation of photovoltaic systems highly efficient. Ladakh is a solar paradise.'

Ladakh, known as the Land of High Passes, is a high-altitude cold desert region in Jammu and Kashmir state, neighbouring China to the east and Pakistan to the north. It is a focus of the 3.5 year Ladakh Renewable Energy Initiative (LREI), a 28.3 MW energy revolution, now in its final year.

Ladakh is taking a flagship role in national renewable energy policy. Although only small, with a sparse population, its rugged geography means that many dispersed communities are beyond the viable reach of the regional grid system. Stand-alone renewables are the obvious solution. 'The harsh environment makes it the perfect test case for the technology itself, and for future policy: to prove to the government and the public that renewables have a valid role to play,' says Dr. Parvind Saxena, director of MNRE in Delhi.

Electrifying rural areas is a prime government concern, and Prime Minister Manoman Singh has given his personal commitment to electrifying every Indian household by 2017. The 2005 programme, Rajiv Gandhi Grameen Vidyutikaran Yojana (RGGVY), has pursued grid electrification of villages, and the 2009 Remote Village Electrification Programme makes off-grid provision.

Conditions in the mountains make the operation of solar PV systems extremely efficient Credit: D. McKenzie/LREDA

Displacing diesel

However, 400 million Indians still lack access to modern forms of energy, and 20,000 villages are too remote, realistically, ever to be grid-connected. Beyond the social expectations, there is also a financial incentive to this initiative. 'We noted that, bar a couple of small hydro projects, almost the entire region, including the Border Defence Force, was using diesel generation for electricity and kerosene for space heating, and due to Ladakh's remote location, fuel is imported by road at a very high cost. Harsh winters close those roads for at least five months of the year, exacerbating energy vulnerability and deprivation, says Saxena.

Prior to the LREI, Ladakh generated a total of 25 MW electricity. Of some 240 villages, 187 received electrification by microgrid for a few hours each day, 75% by diesel and the remainder by small hydro. A few remote communities entirely lacked electricity.

'The high cost of diesel generation in Ladakh – currently INR25–28/kWh – makes renewable energy very competitive,' says Takpa.

'Off-grid solar PV-generated electricity worked out over a 20 years' system-life in Ladakh currently comes to INR16–18/kWh And the cost of solar keeps falling due to technological development and scalability.'

The November 2012 report by the International Renewable Energy Agency (IRENA) confirmed renewable energy as the default option for off-grid electricity provision, with solar PV now a cheaper option than diesel in many locations.

LREI's use of dispersed hydro and solar PV have rapidly replaced diesel to a large extent and avoided unnecessary extension of long, expensive grid lines. According to LREDA figures, the total expected saving of diesel in Ladakh from hydro and PV generation is 35 million litres per year – or approximately INR1.6 billion annually – a substantial saving for the government.

Ankur Agarwal, the CEO of Advanced Renewable Energy Technologies, says: 'The increasing cost of diesel will be a key demand driver for solar PV installations in India,' a country that has an estimated 60 GW of diesel power capacity. Recent cuts in government subsidy for diesel will encourage this trend.

Initiative's background

At LREDA's offices in Leh, Takpa is consulting with senior project engineer, Reuben Gergan, a Cornell-educated Ladakhi. The dynamic team has strong links with India's main tech providers, collaborating on R&D and international scientific exchanges. LREDA is a state nodal agency of MNRE, born in 2000 from the Ladakh Autonomous Hill Development Council. Takpa joined in 2001 and oversaw the Remote Villages Electrification Project, the first of its kind in India. It supplied solar home lighting systems to 200 hamlets in the region, and its success led to the setting up of a nationwide programme.

LREDA's 2005 Ladakh Vision 2025 document highlighted the massive untapped solar, geothermal, hydro and wind energy potential of the region, from which Takpa successfully proposed the LREI as a catalyst for development.

Takpa's engineering and conservation background, and his role as conservator of forests, make Ladakh's fragile ecosystem his concern. Growing tourism and a cash economy have affected local ecology and living practice. He promotes rural livelihoods, ecotourism and ecosystem management, and the LREI complements these needs through renewable energy and conservation techniques for housing and agriculture.

Funding/Investment

Central government funding came from MNRE's financing arm, the Indian Renewable Energy Development Agency (IREDA), a non-banking finance agency that funds mainly rural projects. Over half of IREDA's sanctions are for the wind energy sector, with the rest for small hydro, biomass and solar projects.

As an Autonomous Border Region, Ladakh receives Special Area Status (strategic, remote, underdeveloped) and the highest funding – hydro and solar PV hardware are 100% funded.

Electricity is then charged from users. According to Gireesh Pradhan, secretary for MNRE: 'Upfront costs of renewable energy access systems is the key barrier, and therefore complementing subsidies with funds is a practical way to solve the first-cost capital financing problem. Subsidies for energy access projects are generally justified as a response to inequality and social expectations in energy provision.'

Ladakh nonetheless suffers barriers to large investment. The lack of initial grid connectivity, the region's remoteness and the small population's limited growth potential discourage large-scale solar projects. The small capacity of projects has so far restricted developers from benefiting from Renewable Energy Certificates, although a revision for hydro is proposed.

LREDA has encouraged incentivisation, including removal of entry tax on solar products and provision of district-level simple clearances.

The LREI undoubtedly sets new standards for rural electrification, development and energy conservation. Its broad initiative takes holistic approach and amounts to a flagship for distributed renewables at a timely m,oment in India's energy story. Further remote regions seem likely to follow, with the MNRE currently funding a second off-graid Special area Project in Arunachal Pradesh, a remote north-eastern state, well suited to small hydropower.

Duncan McKenzie is a freelance journalist, who writes on the energy sector.

More COSPP Articles Past COSPP Articles

Czech biogas plant commissions waste heat-to-power system

Dr. Heather Johnstone — Wed, 22 May 2013 16:10:00 GMT

US-based ElectraTherm’s patented Organic Rankine Cycle system has been commissioned at a biogas plant in Slapanov, Czech Republic, representing its second collaboration with biogas plant constructor EnviTec.

ElectraTherm, a specialist in small-scale waste heat to power generation, and its distributor, GB Consulting installed an ElectraTherm Green Machine to generate additional on-site power and increase overall energy efficiency.

To-date the machine has demonstrated greater than 98% availability.

The biogas power facility already has a GE Jenbacher 700 kWe engine, fuelled by manure and corn biogas.

The Green Machine gets its heat from a water loop extracted from the Jenbacher’s jacket water and exhaust gas at 100Â°C.

The machine produces 25-35 kWe, and excess heat is further utilized to supply heat to local buildings, assist in the digestion process and to dry wood.

This latest installation marks ElectraTherm’s ninth in the Czech Republic.

For more Cogeneration/CHP news.

For more Equipment & Technology news.

For more Europe news.

Warming for new Europe

Tue, 21 May 2013 21:35:00 GMT

Long after the Iron Curtain was lifted, Europe's ex-Soviet nations remain reliant on combined heat and power (CHP) plants feeding district heating schemes for which renewables could make an attractive fuel source, writes Rachada Raizada.

District heating (DH) is a leftover of the centralized economic plan- ning, guided by the objective of providing universal access to housing and utilities, that traditionally played the starring role in urban heating systems in the planned economies behind the Iron Curtain. The first Soviet electrification plan of 1920, and successive five-year plans, emphasized cogeneration and waste-heat recycling from turbine steam for district heating of urban residential areas and industrial facilities. Fuel savings at electric power stations, the major producer of waste heat, were an important performance indicator for the Soviet Ministry of Power and Electrification.

With a domestic oil economy devastated by civil conflict, many of Russia's first power plants used peat, for lack of alternatives. But growing urbanisation and the development of the oil and gas industry after World War II led to the dominance of fossil fuels for DH across the communist bloc.

With the transition to market economies after the collapse of the Soviet system, these same countries – some of which have since joined the European Union (EU) – must grapple with the task of modernising these networks without neglecting ambitious environmental targets amid difficult economic times and rising energy prices.

Euroheat & Power (E&P), a major European industry association for the CHP and district heating and cooling sectors, estimates in its 2011 survey that in 2009 the share of citizens served by DH totalled 64% in Latvia, 60% in Lithuania, 53% in Estonia, 50% in Poland, 41% in Slovakia, 38% in the Czech Republic, 23% in Romania, 17% in Slovenia and 10% in Croatia.

The share of recycled heat in these systems ranges from a high of 92% for Romania to a low of 38% in Slovakia and Estonia. Recycled heat is defined as: CHP, including from combustible renewables; waste-to-energy plants; industrial processes independent of the fuel used for the primary process; and two thirds of the energy delivered by heat pumps.

Cogeneration is less common in Estonia since most of its electricity came from oil shale plants in one region. Meanwhile, mother Russia's DH system boasts a trench length for the pipeline system of some 173,000 km.

Direct use of renewables – in heat-only boilers and non-CHP installations – ranges from a high of around 14% in Estonia, Latvia and Lithuania to 2% or less in the Czech Republic, Poland, Romania and Slovenia.

In the EU-27 countries, the share of recycled heat in DH increased from 70% in 1990 to 80% in 2006, with most from the 'others' category. The share derived directly from renewables increased negligibly. In Germany, which along with Poland is the biggest DH market within the EU, the share of recycled heat is 89.5% (mainly from coal, oil and natural gas, with 10% from combustible renewables and waste).

From E&P's viewpoint, a modern DH system should be based on capturing waste heat, and phasing out direct use of fossil fuels for heating. Johannes Jungbauer of the European Affairs Office of E&P, says fuel source is not an accurate indicator of efficiency. Cogen greatly increases primary fuels' efficiency compared with condensing power production and heat-only boilers.

Europe pushes for energy efficiency

With the EU seen as trailing in its goal of reducing primary energy consumption by 20% by 2020, and heat losses from the EU-wide energy system estimated at as high as 50%, energy efficiency is now at the heart of EU policy. In July 2012, the EU Parliament's Energy Committee unanimously voted in a new Energy Efficiency Directive (EED), repealing Directives 2004/8/EC and 2006/32/EC, and enshrining the 20% efficiency target in law by stipulating mandatory measures, such as renovating public buildings and energy-saving schemes for utilities.

Member States must complete a 'comprehensive assessment' by December 2015 of the potential of high-efficiency cogeneration and efficient district heating/cooling, set their own targets and present national efficiency action plans in 2014, 2017 and 2020.

DH offers several benefits over decentralised heating in areas of high heat-load density. But the efficiency and environmental benefits depend on the fuel source, technical characteristics of the heat distribution system and boiler plants, in addition to the institutional market structure. DH enables fuel switching, and can run on a variety of fuels, such as coal, oil, natural gas, peat, biomass, geothermal and municipal or industrial waste.

Vronska in Slovenia hosts the country's first solar thermal DH system Credit: EVN

E&P emphasizes heating's contribution – and particularly the recuperation of waste heat – to achieving energy efficiency targets. Of the EU's final energy demand, 40% is for heating (space, water and low-temperature industrial processes), and met largely through imported fuels or low-efficiency electricity. If progress in achieving the 2020 targets is found insufficient in a 2014 review, national energy efficiency targets will be proposed.

'Of course we appreciate it,' says E&P's Jungbauer. 'But we were hoping for more. Article 10, which includes an energy-efficiency obligation scheme, has been watered down, and could have been stronger.' Results will depend on how Member States choose to implement the directive: 'The EED raises awareness but there are a lot of 'shalls' and 'shoulds' in the text,' he says.

Poland aims for cleaner power

For the EU's largest coal producer – Poland – where domestic hard coal accounts for around 74% of energy production, meeting the EU's 2020 goal of reducing CO₂ emissions by 20% will be particularly challenging, and further complicated by the EU's Industrial Emissions Directive, which necessitates investment to reduce particulates and SOx/NOx emissions. In 2013, the 'white certificates' scheme for emissions trading was introduced to ensure that energy companies meet their energy-efficiency obligations.

Allocations for CO₂ emissions are currently obtained free of charge, but from 2013 the number of allowances will be gradually decreased to zero in 2027, and the shortfall will have to be purchased through the Polish Power Exchange.

Currently, renewable energy sources (RES) account for less than 10% of national energy production, although Poland's share of the 2020 EU target is 15% energy from RES. Since 2005, Polish support for RES has consisted of a rainbow of tradeable renewable energy certificates in shades of green, yellow, red, violet and brown. These are issued to producers of renewable energy, providing them with a secondary revenue stream. Poland's use of renewables in DH (CHP or not) in 2009 was around 7%, most of which was derived from combustible renewables.

DH is an important industrial sector in Poland. The Chamber of Commerce Polish District Heating estimates that around 500 companies operated in this sector, earning an income of about €4.1 billion (US$5.3 billion) in 2010. With an urban share of 60%, national DH capacity is 59,260 MW, served by a trench length of 19,400 km of pipeline systems.

The chamber, spurred on by the Polish Energy Policy to 2030, has recognised the potential of cogeneration, and along with the Polish CHP Association, has presented to the Ministry of Economy a programme for developing cogeneration from its present 63% level.

The average profitability of heating companies is far lower than the industrial average, which means that the sector also faces serious competitive challenges. This has caused the sector to contract, and from 2005–09 DH capacity fell from 65,189 MWth to 59,970 MWth, while district heat sales dropped from 295 PJ to 239 PJ.

Renewables projects get underway

The RES considered most feasible for district heating are biomass, geothermal and solar, with biomass considered to be the most viable.

Fortum, a Finnish energy company, has CHP assets in operation in Russia, Poland, Estonia, Latvia and Lithuania, with a total heat production capacity of 14,107 MW in Russia and a combined 2432 MW in the latter four countries. In 2011, it announced the inauguration of a new biomass CHP plant in Parnu, Estonia, with a multifuel circulating fluidised bed (CFB) boiler, offering 100% fuel flexibility with peat, wood and industrial waste. It also invested in a new biofuel CHP plant in Jelgava, Latvia, the first of its scale in the country. Its Czestochowa CHP plant in Poland uses hard coal and co-fires up to 25% biomass in a 186 MWth CFB boiler.

Dalkia has announced two biomass cogeneration projects in Poland, its largest biomass operation to date. Around 700,000 tonnes of biomass will replace coal, and supply electricity to the national grid and heating to the 700,000 inhabitants of LodÂ´z and Poznan, served by DH. The project will require a €70 million investment.

Solar and geothermal energy as fuel sources are naturally limited by their availability. Demonstration solar DH plants (large-scale solar thermal technology generating heat from large collector fields) operate at competitive costs in countries such as Sweden, Denmark, Germany and Austria, but are new to Eastern Europe.

A consortium of Slovenian and Austrian companies completed the first large-scale solar thermal plant in Slovenia in March 2012. Solar collectors with an area of 842.3 m², or 590 kW, feed into a 93 m³ storage tank, which in turn feeds into the Vransko DH grid, supplying heat to around 2500 inhabitants.

Iceland, where 99% of the population is currently served by DH, is in the enviable position of being able to use its geothermal resources to generate 77% of its district heating.

Geothermal district heating dates back to Roman times, and now has potential in Poland and Hungary – the latter being considered a 'hot' market by the European Geothermal Energy Council.

Hungary currently has around 16 geothermal DH projects in operation, with over 500 MWth of installed capacity, and this number will double by 2014. PannErgy, a Hungarian energy company, focuses on the use of geothermal resources for DH energy in the Carpathian basin. With technology and know-how supplied by Iceland's Mannvit, and with the help of partnerships with municipalities, a 3.2 MWth plant (replacing a natural gas boiler) is already in operation in Szentlorinc, and another will open soon near Miskolc.

The potential of municipal and industrial waste as a DH fuel is significant and under-used. Polish waste- management legislation adopted in 2011, which requires the reduction of land filling from the present 90% level, opens an opportunity for investments in waste-to-energy plants. The EU has also announced its intention to 'phase-out biodegradable waste going to landfill in 2020–25'.

Currently the Czech Repub- lic, Slovakia, Poland and Hungary only host a handful of installations for generating heat or power from municipal waste. Fortum has announced a new waste-to-energy CHP plant and distribution company in Lithuania, in a joint venture with the city of Klaipeda. Commercial operation is planned for early 2014, when 270,000 tonnes of municipal and industrial waste will be expected to produce around 150 GWh of electricity and 400 GWh of heat annually.

Renewables DH outlook

While RES are associated with localised energy production, DH systems work on a centralising economies-of-scale principle. The EU Energy Roadmap 2050 emphasizes that decentralized and centralized systems must interact: 'In the new energy system, a new configuration of decentralized and centralized large-scale systems needs to emerge, and will depend on each other, for example, if local resources are not sufficient or varying in time.'

CHP DH systems can even be used to balance fluctuating electricity production from intermittent renewables, such as wind or solar. For example, on excessively windy days overcapacity can be shifted from feeding the grid to using heat pumps to heat water. Torshavn, in the Faroe Islands, is setting up a 10 MW boiler to link its DH system to the grid. In Germany a research project co-ordinated by the Steinbeis Research Institute for Solar and Sustainable Thermal Energy Systems is also examining solutions for decentralized feed-in to solar DH systems.

DH's fuel flexibility, along with extensive inherited networks offer great potential for Central & Eastern Europe's (CEE) energy future. But due to its synergy aspects, DH has never fitted neatly into energy statistics or policy. However, national energy policies must embrace DH more closely to achieve EU energy policy targets in energy efficiency, or in the use of renewables and CHP.

Rachana Raizada is a freelance journalist, who writes on the energy sector.

More COSPP Articles Past COSPP Articles

On-site renewables a history of barriers, a future of opportunities

Tue, 21 May 2013 21:23:00 GMT

People like the idea of decentralized power. They also like the idea of using renewables. So what is stopping the greater development of distributed renewable energy? Ed Ritchie finds out that may be changing.

Solar PV roof panels delivers almost all of Freeze's electricity requirements Credit: Solis Partners

The on-site power industry continues to grow on the world stage of energy production, but that growth would better serve the need for sustainable power if renewable energy was the dominant resource.

With so many benefits, it is a paradox that it should have a history of so many barriers. Moreover, with natural gas from shale fields in North America flooding the market with historically low gas pricing, we have a new actor that could rewrite renewable energy's role. But it is far from the final curtain, and as sustainability policies grow, so do the opportunities for clean, on-site power.

Before we examine the opportunities and challenges ahead for renewables, let us turn to an expert organization for perspective on the impact of North America's natural gas production. According to the 2012 World Energy Outlook (WEO), by the International Energy Agency (IEA), North America is at the forefront of a sweeping transformation in oil and gas production that will affect all regions of the world.

The WEO finds that the extraordinary growth in oil and natural gas output in the US will mean a sea-change in global energy flows, and predicts that America will become a net exporter of natural gas by 2020 and be almost self-sufficient in energy, in net terms, by 2035.

Even under the shadow of cheap gas, the IEA predicts that renewables could become the world's second-largest source of power generation by 2015 – if subsidies can meet a goal of US$4.8 trillion from now to 2035.

According to the IEA research, subsidies in 2011 amounted to $88 billion. In many other countries, subsidies and the policies that they reflect have proven to be successful for the renewable energy industry, and Germany and Denmark are often cited as prime examples.

But renewables on-site or in distributed energy applications are lagging behind the huge multi-megawatt projects dominated by wind and solar that rely on transmission lines and utility grids.

Given that distributed energy resolves issues of transmission inefficiencies and renewables solve sustainability issues, the industry should be in a much better position. However, the lag of renewable energy is painfully obvious in the birthplace of the photovoltaic (PV) panel, the US. But that could change.

Although renewable distributed energy is far from an industry heavyweight in the US, there are still plenty of companies making money from it. Utility-scale wind farms can be very profitable, but not on-site wind installations, where projects do not compare with the levels of on-site PV.

Biogas in agricultural and municipal installations is viewed by many as a mature market in Europe, but is still struggling in North America. However, cheap natural gas prices are causing developers to reassess the viability of biogas projects.

Solar energy

So that leads to solar PV and another paradox. Although it is an industry plagued by barriers in the US, according to the Solar Energy Industry Association (SEIA) at its Solar Energy Focus conference in Washington DC, 2012 was a historic year for the US solar industry. There were 3313 MW of PV capacity installed, earning a growth rate of 76% over 2011's record deployment totals. For 2013, SEIA forecasts more than 4200 MW of PV and 940 MW of concentrating solar power.

A project at the distribution centre of Freeze, a T-shirt manufacturer in Dayton, New Jersey, will be contributing 1.82 MW of those 4200 MW. Solis Partners, of Manasquan, New Jersey, designed, engineered and constructed the system on the roof of Freeze's 29,729 m² (320,000 ft2) facility, and it supplies about 80% of the company's annual electricity needs.

According to Jamie Hahn, co-founder and managing director of Solis Partners, for a successful distributed renewables project such as Freeze's, it is all about overcoming barriers and delivering the customer a ready-made 'turnkey' package, to avoid the complications of financing, permitting and operations.

'Business owners have their core businesses to take care of so they don't want to manage a power plant on their roof or property,' says Hahn. 'To start, this project could not have been done without a power purchase agreement because the tax equity needed to monetize 52% of the incentive structure makes it difficult for many businesses.

'So this power purchase agreement has no cost and the owners don't have to build, maintain or operate the system. Instead they get reduced electricity costs.'

Net metering needed

In March 2013, the state of New Jersey reached 1 GW of installed solar capacity, putting it in an exclusive club of just two other states: California and Arizona. 'The incentives are critical, and a perfect example is Germany,' says Hahn. 'They have over 50% of the world's solar, yet their sun resources are equivalent to what we see north of Seattle, Washington [which averages 226 cloudy days per year].' Germany's PV installations exceed 7634 MW.

The Freeze project sells power to the local utility through a net metering programme, and Hahn notes that spinning the meter backwards is critical for distributed renewables.

The elimination of net metering benefits has become an issue in California, where an organization of solar companies formed CAUSE (Californians Against Utilities Stopping Solar Energy) in response to efforts by the state's investor-owned utilities to end net metering.

At present, 43 states and Washington D.C. have net metering policies, but the electric utility industry in the US has long been a major barrier to net metering. 'The electrical grid cannot tolerate large and sudden power swings or fluctuations,' says Hahn. 'And as solar and wind approach 20% of the amount of power in any given grid, the need for energy storage systems becomes critical to smooth out the peaks and valleys of renewable power.'

A battery storage system, supporting small wind at the Santa Rita prison in California Credit: Chevron Energy Solutions

The utility industry has a history of publicising solar and wind intermittency as a barrier to renewable technology, but there are dissenting voices.

In 2007, Citizens for Pennsylvania's Future spoke to Karl Pfirrmann, interim president and CEO of PJM Interconnection, the world's largest grid operator, on the subject of wind intermittency. Pfirrmann noted that wind did not pose significant costs as a result of its variable nature because the transmission system can readily accommodate changes in power flows. As to the impact on spinning reserves (standby generators) to mitigate intermittency, Pfirrmann said that there were minimal effects on efficiency, with modest costs deducted from payments to wind generators.

Confirmation of Pfirrmanns's observations were recently published by the US National Renewable Energy Laboratory in a two-phase project, The Western Wind and Solar Integration Study – one of the largest regional wind and solar integration studies ever carried out. Phase 1 analysed the impacts of high penetrations of wind and solar power. It found no technical barriers for high penetrations of wind and solar power (up to 35%), if increased balancing authority co-ordination and sub hourly scheduling were adopted.'

Phase 2 examined new data to address concerns expressed by utility companies about damage to fossil-fuelled generators during cycling, due to heat and emissions while handling intermittency from renewables.

Researchers and industry partners analysed data from cost studies on 400 fossil-fuelled plants, and found that 'the impacts of wind-induced cycling are minimal', and capped wear-and-tear costs at 2% of the value of wind, and emissions impacts at Â±3%. So there is strong evidence of weak consequences.

Old grid infrastructure

However, according to Ken Skylar, manager of Renewable Services at PJM, there is another barrier to distributed renewables relating to the design and age of the infrastructure of the grid. 'Upgrades are needed to the distribution system because it was not designed to accommodate large amounts of variable frequency resources on these individual feeders,'

Ultimately those upgrades will occur as utilities adopt Smart Grid technology, as this technology offers a good return on investment to utilities, and access to government funding programmes.

For example, a recent study by the US Department of Energy, entitled Economic Impact of Recovery Act Investment in the Smart Grid, found that Smart Grid projects funded through the American Recovery and Reinvestment Act (ARRA) resulted in roughly a $7 billion total economic output, 50,000 jobs and a return of $1 billion in government tax revenue.

The state of Florida recently completed its Smart Grid with the help of $200 million in ARRA funding. Florida Power & Light reports that in its first week, the system's 4.5 million smart meters and 10,000 grid sensors identified 400 malfunctioning transformers, as well as many other problems. Smart Grid technology also helps utilities take advantage of demand response programmes, and could enable distributed renewables to participate.

Demand response

Reducing a location's electrical load in response to pricing signals from grid operators – known as demand response – is now a billion-dollar industry. One of the world's leading curtailment services providers, EnerNOC, connects more than 100 utilities and grid operators worldwide to commercial, institutional and industrial customers that participate in demand-response programmes. The potential energy reductions from EnerNOC's $10 million contract with the Massachusetts Department of Energy Resources will reduce electricity consumption in 480 state buildings.

According to Greg Dixon, senior vice president of marketing at EnerNOC, programmes on demand response are growing, but distributed energy has not been a key player.

'New York and New England are hotspots, but few developers and owners of CHP systems are aware of this,' says Dixon. If a business is in a demand response programme, it would be possible to design a PV system for its needs.

In the demand response market, savings from local utilities and payments from grid operators such as PJM are substantial. At DONSCO Inc, a foundry in Wrightsville, Pennsylvania, savings from utility charges amount to $64,200 per year. The savings through the PJM's interruptible programme also equal an annual $30,000, and $66,000 per year comes from a synchronous reserves programme.

Energy storage systems are equally capable of handling utility demand-response requirements, and mitigating renewable intermittency issues.

For instance, In Kaua'i, Hawaii, the utility uses a 1.5 MW battery from Xtreme Power, Austin, Texas, to act as a source of spinning reserves, while providing frequency and voltage ancillary services for a 3 MW PV system. PJM also has a Smart Grid demonstration project using batteries at residential homes with PV and wind resources.

Recent events in Germany could boost the progress of battery technology and pricing. On 1 May, the country launched a support programme for PV battery storage, with €25 million for the first year, then another €25 million for the second year. Better batteries and high-performance PV systems could help avoid a technical barrier to distributed renewables that is happening now, and a financial barrier that is coming in 2017.

Xtreme Power and many other manufacturers have utility-scale energy storage systems. And with numerous technologies such as compressed air, pumped storage and a range of battery types, competition is fierce.

The future of wind power is in jeopardy in the US due to the threat of losing the Production Tax Credit (PTC), an incentive that provides a 2.2 cent per kWh benefit for wind, during the first 10 years of operations. On 2 anuary, 2013, a shutdown was avoided with a temporary one-year extension of the PTC as part of the fiscal cliff bill.

The immediate future in the US, however, looks better for the PV industry. Rather than a PTC, the US tax code allows for an investment tax credit (ITC) of 30%. But the PV industry cannot rely on such incentives for ever. 'January 2017 is when the 30% federal investment tax credit incentive reduces significantly to 10%,' explains Hahn.

Subsidies and incentives for renewables are also losing ground in Europe, with Germany, Spain, Italy Switzerland and the UK also making cuts. But according to Maria van der Hoeven of the IEA, it's a sign that renewable energy is coming of age and needs less public support. But she notes that worldwide incentives for renewables amounted to $66 billion in 2010, in contrast to fossil fuel subsidies of $409 billion.

According to the Institute for Local Self-Reliance (ILSR) in Washington D.C., incentives in the US have resulted in commercial solar achieving 5.5 GW of generation, operating at grid parity in 2012. But grid parity has been limited to states with strong sun and high utility rates, such as Hawaii.

However, ILSR predicts that in Southern California and New York, parity is just around the corner, and unsubsidised rooftop commercial output could rise nationally to 122 GW by 2022. However, policy makers need to address significant non-cost barriers, including, archaic utility rules, net metering caps and so on.

One possibility to overcome awkward financing would be to tap into the strategies of investor-owned utilities. Hahn says: 'We're waiting on some modifications to the tax code. They would allow limited partnership structures found in fossil fuel plant financing.' Barriers such as funding, poor infrastructure, and utility opposition, however, do not trouble multinational corporations. Walmart has announced a programme to power 100% of its operations with renewable energy – a six-fold increase in renewables projects, which is expected to save more than $1 billion annually on energy.

Companies that sell to Walmart are required to show their sustainability efforts. And as Walmart has demonstrated, using distributed renewable energy is obvious choice for the cleanest, most efficient source of power.

Ed Ritchie is a US-based freelance journalist, who writes on the decentralized energy sector.

More COSPP Articles Past COSPP Articles

What's in the pipeline?

Tue, 21 May 2013 20:36:00 GMT

Natural gas is an excellent fuel for DG and CHP, explains Dr. Jacob Klimstra, but because of widening differences in its composition and the introduction of regional standards governing its quality concerns are growing.

Natural gas is an important fuel for distributed generation (DG) and cogeneration. Running generators on clean natural gas can result in large savings in fuel consumption by locally using the heat released during the production of electricity. On top of this, emissions will be realtively low.

Distributed generation also avoids the need for long transmission lines, plus transporting energy over long distances via pipelines with natural gas is said to be 5–25 times cheaper than transmitting electricity over power lines.

Energy can also be stored in the gas in the pipeline if it is at a pressure exceeding the value needed by the customers. So natural gas, is in effect, a large natural battery that is excellent for the long-term back-up of intermittent renewables, such as wind and solar.

Traditionally, the majority of natural gas consumers received it through pipelines from a single source. This meant that the composition of the gas remained fairly stable. This enables the users to achieve optimum performance and minimum emissions from their boilers, gas turbines or gas engines by tuning them to the prevailing composition of the fuel.

However, local gas reserves in industrialised countries are rapidly diminishing, at the same time as its popularity is increasing, due to its lower-specific greenhouse gas emissions and cleaner combustion.

In response to this, natural gas in increasingly being shipped as liquefied nartural gas (LNG) from areas, such as the Middle East, Indonesia, Africa and Australia, to many countries in Asia. The US has large shale gas resources, which might turn North America into a net gas exporter, while Europe increasingly depends on imports from Russia because domestic fields in the waters off the UK and the Netherlands are rapidly depleting.

However, dependence on a single foreign supplier is unattractive because it limits the possibilities for price negotiation. In addition, political tensions could affect security of supply.

It is for these reasons that the European Commission is now promoting the full integration of all European gas transmission systems.Such integration also aims to allow greater competition between gas suppliers, resulting in lower prices for customers.

However, when gas comes from multiple sources, its composition can vary widely and sometimes instantaneously, and thereby affecting the quality of the fuel.

Quality

Expressing the quality of natural gas is more complicated than doing the same thing for power. Customers are happy if electricity at 50 Hz or 60 Hz is at a voltage close to the rated value, has no excessive harmonic distortion and has a supply reliability of at least 99.99%. However, with natural gas, the definition of quality is more diverse.

Gas companies generally express the quality of their fuel through its composition, its Wobbe index (WI) and calorific value. Additional factors, such as combustion velocity, knock resistance, the absence of sulphur and siloxanes, as well as firmness in composition, can be important to users.

The WI is a measure of energy flow for a given pressure drop over a restriction. The majority of gas applications use a pressure drop when administering gas to a burner or carburettor. For the WI, the volumetric calorific value H (MJ/m³) of the gas has to be known, as does the relative density d = ρgas/ρair of the gas:

Because the quotient of the two densities ρ (kg.m³) is dimensionless, the WI has the same dimension as the calorific value: MJ/m³. If the WI changes, the power output of the gas application also changes unless corrective steps are taken. The same applies for the air-to-fuel ratio λ, because for most systems that consume gas, the air-to-fuel ratio varies in inverse proportion to the WI:

λ (new) = WI(initial)/WI(new) ∙ λ (initial)

The air-to-fuel ratio determines the temperature of the flame and the combustion velocity, so the combustion process will change with the WI, and thereby affecting fuel efficiency, thermal load and emissions.

For example, if the WI drops from 55 MJ/m³ to 50 MJ/m³, the initial λ value of 1.9 increases to 2.1. If the application is a gas engine with a venturi carburettor to prepare the fuel-air mixture, the engine would most probably misfire and stop fully.

If for the same initial λ value of 1.9, the WI increased from 50 MJ/m³ to 55 MJ/m³, the new value of λ would fall to almost 1.7, resulting in substantially higher NOx emissions and, most probably, knocking. In addition, the power output would increase by 10% and potentially leading to system overload

Standards

Less than a decade ago the US had big plans for importing LNG because its domestic resources were declining and it wanted to ensure security of supply, plus natural gas produces lower greenhouse gas emissions compared to coal.

Terminals for receiving LNG were built at major ports along the east and west coasts. Up to then the US had enjoyed reasonably stable gas compositions, but there were fears over the consequences of the differing compositions of the LNG. This led the Federal Energy Regulating Committee (FERC) to approach the US Natural Gas Council and other interested parties on how to deal with the anticipated problems.

A new committee, NGC+, was established, with members from equipment manufacturers, power plant companies, pipeline operators, gas distributors, feedstock companies and LNG suppliers.

Over the course of 19 meetings, the 71 stakeholders discussed all aspects of combustion efficiency, emissions, flame stability and appliance performance. As a result, a White Paper on natural gas interchangeability and non-combustion end use1 was issued on 28 February 2005.

Table 1 gives the agreed values for some gas indices, while Figure 2 shows how these values affect the upper calorific value and WI.

In the White Paper, the WI is allowed to vary in the range Â±4% around the traditional average value of 53.16 MJ/m³, while the upper calorific value can vary by Â±6% around 41.17 MJ/m³. It is important to note that the upper calorific value is specified here for a reference temperature of 25Â°C, while Table 1 uses reference conditions for a m³ of 101.25 kPa and 273.15 K. These reference conditions often differ depending on the country or the organization, and care should be taken to take this into account when comparing different gas quality standards.

In Europe, the EASEEgas consortium, made up of primarily members from the gas sector, has been working for almost a decade on specifications for the transborder transfer of natural gas.

Table 2 lists the gas quality index values set for this. Based a mandate from the Commission, the organization of gas transmission operators, ENTSO-G, and the normalisation committee, CEN, are now turning this into a standard.

It appears that in the EASEEgas proposal, almost any natural gas available in the world can be accepted. This is welcomed by gas traders and shippers but has significnatly negative consequences for gas consumers.

A range in the WI between 49 MJ/m³ and 57 MJ/m³ means that a gas-consuming device can suddenly experience a decrease of 14% in fuel supply. In such a case, an initial air-to-fuel ratio λ of 2 in a gas engine or a gas turbine combustor will instantaneously become λ = 2.3, resulting in combustion instability and misfiring. The gas standards do not exclude so-called plug flow, which means that a sudden change in composition of the gas supplied can always occur.

A change in the opposite direction – in other words a sudden jump in the WI from 49 MJ/m³ to 57 MJ/m³ – will decrease the air-to-fuel ration λ from 2 to 1.7, resulting in 16% more power, a higher combustion velocity and higher combustion temperatures.

The power output controller of a gas engine can normally handle a rapid change in output caused by a change in WI. In engines that feature a carburettor, the throttle valve will readjust the amount of mixture flowing to the engine, and in gas engines with electronic gas admission valves, the readjustment in power output will be even faster. However, the air-to-fuel ratio of carburettor-based engines takes longer to control because of the adjustment in the carburettor setting.

Knock resistance

In gas engines, a gas with a higher volumetric calorific value will generally have a lower knock resistance – the knock resistance of gaseous fuels is expressed by the methane number (MN).

The MN method was initially developed at the laboratories of AVL in Graz, Austria, with a consortium of German and Austrian engine manufacturers in the early 1970s. In that programme, no hydrocarbons higher than butane were taken into account. Subsequently, the initial method was improved to fit the actual performance of modern engines. The effects of higher hydrocarbons, such as pentane, hexane and heptane on the methane number are now included.

Gas engines in stationary applications for cogeneration and on-site power production demonstrate optimum performance with a MN of 80 or higher. This also applies to natural-gas-fuelled trucks and ships. Fuel efficiency, power output and load-step-response capability are negatively affected by low MNs.

Some gases within the EASEEgas range, such as LNG from Libya, have a MN as low as 63. Figure 4 shows MNs for a selection of natural gases that lie in the EASEEgas range. Gases with an MN of less than 60 might even occur if the specifications contain no lower limit for the MN. The specifications for gas in the US guarantee that the MN is always above 73.

Gas treatment

Shale gas in the US3 varies widely in composition from site to site. To comply with the NGC+ limits, the concentration of higher hydrocarbons is reduced by condensing them out (Figure 5) as natural gas liquids (NGLs). These NGLs help to make shale gas production profitable. According to Valerie Wood, president of EnergySolutions3: 'NGLs are priced in accordance with crude oil prices. The production of high-value NGLs helps to lower natural gas break-even prices.'

However, gas transmission operators in Europe refuse to see removal of higher hydrocarbons at LNG terminals as a solution for obtaining narrower gas specifications. Their excuse is that European and national legislation prohibits gas transmission companies from selling NGLs to refineries. Such an aberration can easily be rectified.

Also, rich gases might occur only occasionally, resulting in a low utilisation factor for a treatment installation. However, that is no excuse. In electricity supply, peaking plants necessary to keep the system stable also have a limited number of operating hours per year. Keeping the WI in a narrow range, even with a large number of gas sources, is not a technical problem. Gasunie in the Netherlands has maintained the WI of the L-gas and H-gas within a range of Â±2%.

Billing

An important negative aspect of a wide range of gas compositions is the variability in volumetric calorific value. As mentioned earlier, the EASEEgas specifications allow an upper calorific value of between 36 MJ/m³ and 48 MJ/m³. However, commercial and domestic gas consumers use a gas meter that is based on volume flow without a correction for calorific value.

Gas distribution companies have a policy of correcting gas bills for the average calorific value over a certain time span. However, under the proposed regulations, the gas composition can change instantaneously and frequently. Proof of this has already been seen at a cogeneration installation at a point at where three gas streams met.

An owner of a local generating set, such as a cogeneration plant for a greenhouse, might use the installation to sell electricity to the grid during times of peak demand. With today's gas prices, the profitability of such plants is only marginal. If the calorific value at a given time is only 36 MJ/m³ and the gas company charges the CHP plant for a calorific value of 40 MJ/m³, it appears that the electrical efficiency of the CHP plant has dropped from 45% to 40.5%.

Instantaneous monitoring of plant performance based on the quotient of electricity production and gas flow will be flawed under such circumstances.

Optimum adjustment for minimum NOx emissions is also not possible with a wide range in WI.

Widespread concern

It is not only the cogeneration and on-site power sector that is worried about the proposed wide range in gas quality. BDH, the German association of energy and environmental industries, and Figawa, the country's association of gas and water companies, have voiced their concerns in a letter to stakeholders.

Most existing gas appliances are not able to cope with a wide range in gas composition. In the UK, the allowed WI is restricted to between 47.2 MJ/m³ and 51.2 MJ/m³, which is about the same range as that of the USA' NGC+. Research has shown that expanding this range is extremely costly because the required scale of investment is factors higher than any profits that come from acquiring cheaper gas.

A paper from Jackson, Finn and Tomlinson4 propose an effective method for extracting higher hydrocarbons from LNG. Ballasting rich gases with nitrogen is ofter proposed to reduce the WI and the calorific value. This, however, is of no use for gas engines because nitrogen in the fuel gas does not improve the knock resistance in modern, high-performance, lean-burn engines.

Arguments by the gas sector that engines and turbines are just a small segment in the gas market does not bear any relationship to the reality and the future.

Better insulated homes and solar heat collectors will drastically reduce the use of gas for heating purposes. In contrast, gas use in engines with the ability to rapidly respond to the intermittency of renewable energy from wind and sun will substantially increase. Next to that, gas-fuelled cogeneration is still a favoured way of saving fuel and reducing greenhouse emissions.

Unfortunately, the gas industry is also now trying to convince countries outside Europe to adopt the gas quality range as proposed for that region. Hopefully, democratic processes will prohibit the interests of consumers from being ignored.

In 1986, a major gas quality conference5 was held in the Netherlands in which experts from gas companies from all over the world participated. The main message was clear: gas quality should be user-led, not supplier-led, and care has to be taken for it not to become politician-led.

In a nutshell

The proposed wide range in transboundary gas composition by the gas industry in Europe has negative consequences for fuel efficiency, power capacity and emissions of gas-fuelled equipment. And the aspirations of European policy makers on security of supply and open markets for natural gas will ultimately result in higher costs for most gas users.

The economic benefits for Europe of accepting all gas available on the world market regardless of its quality may well be lower than the extra costs incurred by adapting gas consuming equipment for efficiency loss and for emission increases.

Solutions for reducing the large range in gas quality available on the market are standard, proven and globally widespread.

In Europe, gas companies have so far dominated all policy making on gas quality without taking into account the expertise of equipment manufacturers and users of gas-fuelled equipment. The US, in contrast, has followed a more democratic path.

Finally, a wide range in calorific value will further deteriorate and obscure the way gas energy deliveries are measured with gas meters.And legislation in Europe should allow gas transmission companies to sell NGLs.

References

Natural Gas Council, White Paper on Natural Gas Interchangeability and Non-Combustion End Use, 28 February 2005.
Leiker M, Cartelliery W, Christoph K, Pfeifer U & Rankl M, 'Evaluation of the Anti-knocking Property of gaseous Fuels by means of the Methane Number and its Practical Application to Gas Engines', ASME paper 72-DGP-4, April 1972.
Darin L George & Edgar B Bowles, 'Shale Gas Measurement and Associated Issues', Pipeline & Gas Journal, pp38–41, July 2011.
www.natural-gasliquids.com/editorimages/downloads/UK%20Gas%20Paper%2013-01%20(final).pdf
G J van Rossum, editor, 'Gas quality', Proceedings of the Congress of Gas Quality, Groningen, the Netherlands, 22–25 April 1986, ISBN 0-444-42628-0.

More COSPP Articles Past COSPP Articles

Industrial-scale cogeneration takes off in Mexico

Tue, 21 May 2013 19:24:00 GMT

by Steve Hodgson

The well-established cogen markets of Europe and the US are served by the equally well-established trade associations, COGEN Europe and the CHP Association (formerly the USCHPA), which also act as pressure groups trying to support cogeneration/CHP industries and to transform the markets for their products.

A whole series of national trade associations do similar work in the individual countries of Europe and, in the US, eight regionally-based Clean Energy Application Centers lobby for and support CHP development locally. In addition to these organisations, the closely-linked district heating industry is also supported by Euroheat & Power in Europe and the International District Energy Association, which is based in the US but has wider horizons.

The existence of a trade association gives its members, the main industry players, a unified voice in making the case for the technology, and gives governments and regulators a way to directly address the industry. The associations tend to do a good job – often 'punching above their weight' when it comes to making sure that cogeneration is treated according to its merits in energy debates and the development of legislation and regulations.

So it's good to see the emergence of a new national trade association – COGENERA Mexico, which is in the process of being constituted. The new organisation was introduced to the world at last month's COGEN Europe conference in Brussels. It has a familiar agenda – regulatory issues around cogeneration in Mexico; financing and fiscal incentives; promotion of the technology and development of a market for it; fuels and sustainability issues.

At the Brussels event, Ana Delia Cordova, a member of the Board of COGENERA Mexico, spoke of the value of learning from the experience of COGEN Europe and similar organisations already involved in promoting cogeneration, and of the cogen business opportunities opening up in Mexico.

And these opportunities may be many. The US Commercial Service has recently issued guidance on opportunities resulting from expected growth in cogeneration by the Mexican private sector in the coming years. It identifies the petroleum, petrochemicals, chemicals, sugar and paper and pulp industries as potential growth application areas.

In addition, Mexico's state-owned oil company, PEMEX, and its Comision Federal de Electricidad (CFE) are already collaborating on cogeneration plants at PEMEX facilities that both cut steam costs for PEMEX and deliver low-cost electricity to CFE. The Commercial Service identifies 10 GW of potential cogeneration plants for PEMEX facilities alone, and suggests that the collaboration model could be extended beyond these two companies.

And, an alert published earlier this year by the Mexico office of international lawyers Baker & McKenzie reports new incentives for and activity in the cogen sector in Mexico, following helpful recent amendments to energy regulatory instruments. It points to 63 permits granted for new cogeneration plants in the country, adding up to some 3 GW of new generating capacity.

Meanwhile, reports in the last few weeks from the COSPP website (www.cospp.com) suggest considerable activity is already underway:

Spain's Iberdrola has begun work on a new 430 MW cogeneration plant at a PEMEX refinery in Salamanca, a city in Guanajuato state.
PEMEX has brought a 300 MW cogeneration scheme on line in the south-eastern state of Tabasco.
Rolls-Royce is to supply industrial gas turbine equipment for a proposed cogeneration scheme at a textile and chemicals complex in Veracruz.
Two Spanish contracting companies, OHL and Sener, are to build a 35 MW cogeneration scheme for the refining arm of PEMEX at a facility in the north-eastern state of Tampaulipas.

Cogeneration in Mexico seems to be having a growth spurt just now, and with sizeable schemes too. Assisted by a favourable regulatory environment and ample reserves of natural gas at low prices, the sector has very considerable potential. What's needed now is investment from outside the country in new projects. And a new national trade association focused on cogeneration should help too.

Steve Hodgson
Contributing Editor

More COSPP Articles Past COSPP Articles

International retailer to install CHP in German and Russia stores

Dr. Heather Johnstone — Mon, 20 May 2013 16:49:00 GMT

METRO Cash & Carry, in partnership with Germany utility E.ON, is installing advanced gas-fired micro-CHP units at two of its wholesale stores in Germany and two in Russia.

The units will heat the stores and meet a portion of their electricity needs. Depending on the size of the store, the units’ electric capacity will range from 250 kW to 800 kW.

Subsequently, the installation of CHP units at four other METRO stores in Germany and at new stores opening in Russia are planned, with the future option to supplement the on-site CHP units with solar power.

E.ON will plan, finance, install and maintain the CHP units, and METRO will operate them.

The units are expected to lower the stores’ energy costs and reduce carbon emissions by up to 20%.

This is not METRO’s first foray into the realm of decentralized energy.

It has deployed distributed energy solutions at several of its sits, including it hypermarket at Schwelm in west central Germany, where an on-site micro gas turbine has been providing the facility with power and heat since 2011.

For more Cogeneration/CHP news.

For more Europe news.