Navigant Research Blog

In Eastern Tennessee, the Future of Electricity Generation Takes Shape

— September 4, 2013

It’s been a cool, wet summer in the Southeastern United States, which has meant lower power sales for the Tennessee Valley Authority (TVA), the federally owned utility that serves 9 million customers across seven states in the region.  The TVA said last month that it sold 4% less power and took in 6% less revenue in the third quarter than the same period in 2012, mostly because of the mild weather, a weak economic recovery, and lower fuel prices.

TVA, which brought electricity and running water to much of the Southeast in the decades following the Great Depression, is facing many of the challenges that big utilities across the country face, and it has responded (or has been forced to respond) by beginning to phase out its coal-fired units in favor of gas-fired generation at modern combined cycle plants, including one at the John Sevier power station in Rogersville, Tennessee.  In 2011, the TVA signed a landmark agreement with four states, several environmental groups, and the U.S. Environmental Protection Agency that calls for the retirement of 18 units at three power plants, including the huge Johnsonville Fossil Plant in Tennessee, the Widows Creek Fossil Plant in northern Alabama, and the Sevier plant.  Two of the four units at Sevier have been idled, and the other two will either be equipped with modern emissions control equipment, converted to biomass-fired generation, or retired by the end of 2015.

The agreement, which was spurred by a lawsuit filed by the state of North Carolina over air pollution from TVA plants, also levied a $10 million civil penalty on the utility and calls for $350 million in investment in new pollution controls over the next 5 years.  The Sierra Club called it “one of the largest pollution reduction agreements in the nation’s history.”

Shifting to Gas

The transition at the Sevier plant was not a conversion, per se; TVA determined that switching the existing units to gas-fired generation would be much more costly than simply idling the coal units and building a new combined cycle plant.  The new John Sevier Combined Cycle plant went into commercial operation last year and has 880 MW of total capacity – about 490 MW in single cycle mode and another 390 MW in combined cycle – in which excess heat from the primary gas turbine system is recycled to drive a secondary steam turbine.  TVA says that, compared to the old coal units, the new gas-fired station will produce 40% less air pollution – half the carbon dioxide and 1% sulfur dioxide.

Last year the TVA said it had signed a lease-purchase agreement with an investor group known as John Sevier Combined Cycle Generation LLC, under which the utility will lease the $820 million to the company for $1 billion over 30 years.  Such complicated financing arrangements are a necessary strategy for the TVA, which lost $203 million on revenue of $7.9 billion in the first 9 months of this year.  Pressured by tightening regulations, market forces, and public demand for cleaner power, TVA, like many big utilities, is facing wrenching changes in the coming years.  Switching to advanced natural gas-fired power stations, like the new Sevier plant, offers one way forward for the TVA and for U.S. utilities in general.

For an in-depth examination on switching coal-fired generation capacity to natural gas, please join us for the Navigant Research webinar, Coal to Natural Gas Plant Conversions, on Tuesday September 10 at 2 p.m. Eastern time.

 

Power For The 20 Percent

— August 21, 2013

According to the World Bank, people worldwide spend about $37 billion annually on kerosene for lighting, biomass (typically wood or charcoal) used in open fires, and polluting traditional stoves for cooking.  These inefficient energy pathways not only cost too much, but they also impose severe health risks on indigenous populations and increase carbon emissions contributing to global climate change.

It’s estimated that more than one-fifth of humankind lacks modern energy services.  While the cost of providing universal access to the electricity grid, or to decentralized electrification systems, would be in the tens of billions of dollars annually, these “costs” also represent potential revenues for vendors of smart grid and microgrid enabling technologies, such as distributed generation, energy storage, smart inverters and smart meters.  The United Nations has made the goal of universal energy access a major priority, viewing the development of microgrids as a key enabling technology.

The International Energy Agency (IEA) estimates that the annual cost of achieving universal energy access throughout the world would be approximately $48 billion.  Under a base case scenario, the gap between expected costs and available (primarily public sector) funding is $34 billion annually.  The majority of this latter figure represents household lights and cell phone chargers.  However, more than 10% of this total represents vendor revenues in the remote microgrid space, if private investment, policy reforms and technology advances can be marshaled to meet market demand.  This is double the market for traditional utility grid expansion in the developing world.

By comparison, Navigant Research estimates in a forthcoming report that the size of today’s entire remote microgrid market is approximately $3 billion, but the scope of that revenue includes substantial project portfolios in both North America and Europe.

Local Goods

Can vendors respond to this challenge while still turning a profit? The jury is still out.  To date, it appears that private sector models are providing the best results, both for vendors and the consumers being served.

While rural cooperatives in Alaska have proven that publicly owned utilities can successfully deploy remote microgrids, the experience in the rest of the world with the cooperative business model has been less inspiring.  This approach has been deployed in Bangladesh and Nepal with some success, but in India – probably the largest market for remote microgrids in the world – such endeavors have largely failed.

In contrast, the energy service company (ESCO) model, whereby a private company owns, installs and operates the remote microgrid and provides energy services to consumers, is, with certain caveats, looking like the most promising path forward.  This model has found success in countries such as Zambia, Kenya, Sri Lanka, and the Dominican Republic.  There appears to be a growing consensus, however, that 3 megawatts (MW) of electrical capacity is the minimum size to make these private sector projects work.

A few caveats on private sector models.  They often require either a clear regulatory framework or long-term subsidies (or the elimination of existing subsidies for incumbent technologies).  A review of existing remote microgrids in the developing world indicates that success for remote microgrid business models ultimately rests in designing creative ways to generate income for the local communities being served.  In other words, business models must serve not only the entity that builds, develops, or owns the infrastructure, but also the end users – in the form of less costly or reliable energy, local jobs, quality of life – in other words, the basics that citizens of the First World view as their birthright.

 

Coal-To-Gas Plant Conversions Face Challenges

— July 5, 2013

The prospect of more stringent carbon emissions restrictions for existing power plants, as laid out in President Obama’s late-June speech on climate change, leaves the coal industry facing a series of hard choices.  Among the main questions: What to do with aging coal plants, many of which will be prohibitively expensive to fit with emissions-control systems to meet the new requirements?

One option is to simply decommissioning them – demolishing the plant, selling off the scrap metal, and finding a re-use for the brownfield site on which the plant was located.  A growing number of coal plant owners and operators, though, are considering converting those plants to run on natural gas: a seemingly straightforward changeover that would enable the same boiler, turbines, and other plant infrastructure to run on a fuel that is both less expensive than coal (for now) and less polluting.  A SourceWatch page on coal plant conversions lists dozens of such projects, from Washington, D.C. to California.

A closer look at these projects, though, indicates that converting to natural gas is neither as simple nor as cost-effective as it might appear.  Some announced projects have already been delayed, or killed; others are merely under consideration and may never become reality.  Many so-called “conversions” are, in fact, simply replacements, according to a 2010 study by the Aspen Environmental Group.

New Pipelines, New Hurdles

The problem is one of cost.  In many cases it’s simply cheaper to tear the plant down and start all over, rather than fueling the existing units with gas.  Combined-cycle gas-fired generation plants cost roughly $1 million per MW, installed; the cost of converting existing coal-fired equipment can be twice as much.  A 2012 study by engineering firm Black & Veatch considered several options for switching from coal to some form of natural gas generation for a hypothetical 250-MW power plant.  “Full conversion to natural gas only” and “Conversion to coal with natural gas co-firing” were the least cost-effective options, the study concluded; simply replacing the existing plant with a new combined-cycle system, fired by natural gas, was among the most attractive.

What’s more, older coal plants are not necessarily located in places served by natural gas pipelines.  New pipeline construction, accounting for rights-of-way acquisitions, metering stations, compressors, and other costs, can itself reach more than $1 million per mile, adding millions of dollars to the conversion, when a new plant integrated into existing natural gas infrastructure.

Thus it’s no surprise that some utilities with ambitious coal-to-gas conversion plans have begun to have second thoughts.  Minneapolis-based Xcel Energy, for instance, issued an RFP in March for new generating capacity that could replace the 109-MW Arapahoe plant and its 352-MW unit at the Cherokee plant, in north Denver.  Both of those stations had been slated to be converted from coal to natural gas.  The Tennesse Valley Authority, which last year said it would condider switching its huge Widows Creek Fossil Plant to natural gas, to coincide with a proposed natural gas pipeline across the Southeast.  That decision is now on hold.

Considering the growing public opposition to expansions of oil and gas infrastructure in the Lower 48, any major addition to the existing natural gas pipeline system has to be viewed as a long-term, risky endeavor.  Converting from coal to natural gas will no doubt be an option for many existing plants.  But it’s hardly going to be the answer for a majority of the country’s aging coal fleet.  These options will be explored in further detail in an upcoming Navigant Research report on decommissioning coal plants.

 

China’s Coal Conundrum

— June 21, 2013

International climate-change diplomats, who have had a rough decade, got some potentially exciting news in May when reports emerged that China will consider an absolute cap on carbon emissions in advance of the climate talks scheduled in Paris for 2015.

A hard emissions cap would be a dramatic policy shift for the People’s Republic, which has previously limited emissions reduction schemes to compressing the Chinese economy’s energy intensity (the amount of CO2 released per unit of GDP) and which has decried international efforts to limit the greenhouse gas (GHG) emissions – and thus the economic growth – of developing countries.

The shift was signaled by remarks made by Jiang Kejun, a carbon policy researcher at the influential National Development and Reform Commission in Beijing, who told the Financial Times, “I am sure China will have a total emission target during the 13th Five-Year Plan.”

The move could enable an achievement that has eluded the world’s major nations for years: a binding international agreement on carbon caps that includes both the developed economies of West and East Asia and rising economic powers like China and India.

If true, this move would mark the latest in a series of measures to reduce GHG pollution in China, the world’s largest producer of atmospheric CO2.  Seven Chinese cities plan to enact experimental carbon-trading programs, starting in 2014.  Already the world’s largest investor in renewable energy, China has set the goal of obtaining 15% of its power from nuclear power and renewables by 2020.  Since taking office in March, President Xi Jinping has made shifting to a less resource-intensive economy and reducing the country’s catastrophic air pollution major priorities.  In many respects China has leaped ahead of both the United States and the European Union in its efforts to shift away from fossil fuels.

There’s one problem with this scenario: any program to reduce carbon emissions on the mainland depends on shrinking China’s reliance on coal – and coal-fired power in China is not going away anytime soon.

No Peak Soon

“It is very unlikely that demand for thermal coal in China will peak before 2030,” said William Durbin, the Beijing-based president of global markets with Wood Mackenzie, an energy research and consulting firm, in a statement accompanying the release of a new report entitled “China: The Illusion of Peak Coal.”

“Despite efforts to limit coal consumption and seek alternative fuel options, China’s strong appetite for thermal coal will lead to a doubling of demand by 2030,” the report concludes.  Coal consumption in China, bolstered by a period of rampant construction of coal-fired plants that has only recently slowed, must rise to feed China’s explosive demand for power, which will nearly triple to 15,000 TWh by 2030.

Even existing goals for reducing coal consumption are sketchy, many analysts believe.  “Achieving these targets eventually would come at considerable economic cost,” John Reilly, an environmental economist at MIT, told New Scientist magazine.

China is by far the world’s largest importer of coal, and despite massive investments in nuclear, wind, and solar power, along with a crash program to develop domestic natural gas reserves, no other energy source can replace coal as a source of primary power in the next two decades.  China’s leaders are determined to replicate America’s shale gas boom, but “natural gas supplies will struggle to meet demand growth due to modest investment in conventional reserves and the very slow development of domestic unconventional shale gas reserves,” Wood Mackenzie states.

Gray Market, Black Fuel

The continued coal boom in China also reflects the provincial divisions that make enacting nationwide policies increasingly challenging for leaders in Beijing.  Most coal-reduction schemes are centered in the big cities of the coast, while the poorer provinces of the interior still rely on dirty, cheap coal.  Ambitious plans to build long distance ultra-high-voltage transmission networks, for example, won’t reduce overall coal burning; they’ll simply shift coal demand from the coast to the interior.  What’s more, official statistics on coal use in China significantly underestimate the true demand, because of the size of the gray market consisting of small, unlicensed mines and untracked sales.  A 2011 report on the Chinese coal industry produced by Stanford’s Program on Energy & Sustainable Development stated the problem clearly: “One important driving force underlying the existence of gray coal markets in China is the historic and chronic difficulty of compelling local officials to obey central policies.”

China’s evident intention to institute firm caps on GHG emissions is an encouraging sign.  But the grim reality is that such a cap has no chance of succeeding without a dramatic, and unlikely, reduction in power generation from coal.

 

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