PowMagazine 07 2014

July 2014 • V

ol. 158 • N

o. 7

Vol. 158 • No. 7 • July 2014

A Brewing Storm of Environmental Concerns

PRBCUG Plant of the Year

Middle East’s Power Pivot

(Not So) Temporary Power

Decommissioning Zion Nuclear Units

Answers for industry.

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July 2014 | POWER www.powermag.com 1

ON THE COVERThe variety, number, and strength of environmental regulations facing the power industry are all quickly building to create what, for some plants, may be a perfect storm. Photo: POWER/Gail Reitenbach; type: Michele White

COVER STORY: ENVIRONMENTAL CONCERNS22 Combined Mercury and SO3 Removal Using SBS Injection

Using a sorbent that removes SO3 before the air preheater, plants can remove higher levels of mercury than is otherwise typical. They also enjoy co-benefit capture of two other elements that could position a plant for compliance with proposed effluent limit guidelines without adding new equipment.

28 Biomass Exemption Sails into the SunsetHow small is small? The definition matters enormously to U.S. biomass plants that may soon find themselves falling into a different category, where they would be subject to new permitting and equipment hurdles.

32 The Water-Energy Nexus Takes Center StageAs droughts and growing demand strain water resources worldwide, the power sec-tor is being called upon to make water efficiency a top priority. Here’s what plant operators will be facing in the future.

36 Shifting Sands: The Middle East’s Thrust for SustainabilityWith its reputation for fossil fuel wealth, the Middle East may seem an unlikely place to encounter low-carbon and energy-efficiency efforts, but population and economic growth coupled with scarce water are behind the shift.

40 Geoengineering: A Practical Climate Work-Around or Just Plain Crazy?Global political and economic approaches to reducing atmospheric greenhouse gases are going nowhere, so some say it’s time to take various geoengineering approaches seriously.

SPECIAL REPORTS

DISTRIBUTED GENERATION

44 Blurring the Line Between Temporary and Permanent PowerAlthough temporary power is familiar to many readers from major construction proj-ects or off-grid mining operations, fewer may realize that the project characteristics for the business are quickly approaching those for “permanent” power stations.

Established 1882 • Vol. 158 • No. 7 July 2014

You’ll find more online at powermag.com every month, from news stories as they’re

posted, to blog posts, to feature stories. Look for these exclusive stories associated with

the July issue features in the Archives:

Evolved Strategy Accelerates Zion Nuclear Plant Decommissioning

The EEI’s Campaign for Electric Utility Industry Supremacy

RWE’s Thomas Birr on Corporate Strategy in a Changing German Electricity Ecosystem

The EPA’s Clean Power Rule in Three Infographics

Web Exclusives

32

22

44

www.powermag.com POWER | July 20142

FEATURES

PRBCUG 2014 PLANT OF THE YEAR

50 Springerville Generating Station Earns PRBCUG 2014 Honors A former POWER Plant of the Year has been recognized this year as the Powder River Basin Coal Users’ Group 2014 Plant of the Year award winner for implement-ing industry best practices, continual improvements, and worker safety.

COAL

54 Does IGCC Have a Future?Is integrated gasification combined cycle the future of coal or a boondoggle? That depends on whom you ask, but the challenges in making the technology economically viable are large. We review the state of the sector and where things may be going.

DEPARTMENTS

SPEAKING OF POWER6 We Have Proposed Carbon Pollution Standards. Now What?

GLOBAL MONITOR8 Is China Considering Carbon Targets? 8 The Expanding Wood Pellet Market9 New Floating Wind Array Planned in Scotland10 THE BIG PICTURE: Recycling CO2

12 Grid-Scale Iron-Chromium Redox Flow Battery Connected13 POWER Digest

FOCUS ON O&M14 Latest Electromagnetic Technology Device Improves Inspection Accuracy and

Repeatability16 Is Your Plant Ready for MATS?

LEGAL & REGULATORY20 Nest Thermostats: The Future of Demand Response Programs?

By Olivia Para, Davis Wright Tremaine

COMMENTARY68 As Clean Energy Accelerates, a New Era of Choice Is Upon Us

By Fred Krupp, president of Environmental Defense Fund

Connect with POWERIf you like POWER magazine, follow us online for timely industry news and comments.

Become our fan at facebook.com/POWERmagazine

Follow us on Twitter @POWERmagazine

Join the LinkedIn POWER magazine Group

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SPEAKING OF POWER

We Have Proposed Carbon Pollution Standards. Now What?

The most contentious (though not neces-sarily the most expensive) proposed en-vironmental regulation to hit the power

industry in this century was released by the Environmental Protection Agency (EPA) on June 2. The most immediate consequence was an increase in the volume of email.

The Big OneAs I write this column a week after the EPA unveiled its proposed Carbon Pollu-tion Standards for existing fossil-fired power plants, those of us in the media are still being inundated with “comments” and “perspectives” from all corners. The tsunami began even before the proposal (remember that it’s not a fait accompli) was released. Some of those pre-release statements in particular made claims based on inaccurate assumptions about what the proposal would include.

I’m not surprised by the volume (in both senses of that word) of chatter both before and after the announcement. (The rule was also a topic of discussion at the annual Edison Electric Institute meeting the following week, though the tone there was one of wait and see what emerges from the final plan. See my report on that meeting, associated with the online fea-tures for this issue, at powermag.com.) Until the proposal was made public, it was easy to fixate on the fossil industry’s worst fears about what the EPA would require. Now that we know (but maybe haven’t read the thousand-plus pages of documents), it’s easy to worry about how states will decide to implement the plan.

However, some aspects of the standards are a bit less worrisome now that we know what’s in the proposed rule. For example, the impact on reliability and affordabil-ity may be minimal, as the EPA promised. Given the range of options for compliance, the coal plants likely to be shuttered, if any are, are those already too old and un-economic to maintain, let alone invest in, especially given current gas prices.

And the carbon rule looks to be less costly than the Mercury and Air Toxics Standards (MATS). The EPA projects that the annual in-cremental cost of compliance with the carbon rule (excluding costs associated with moni-

toring, reporting, and recordkeeping) could be as high as $7.4 billion in 2020 and $8.8 billion in 2030 (in 2011 dollars). Its “project-ed annual incremental private costs” to the electric power industry for the final MATS Rule were $9.6 billion in 2015. Not surprisingly, various industry estimates are higher.

As for the overall economic consequenc-es, those may be flat to positive. A June 6 story in The New York Times noted that “Some critics of the Environmental Protec-tion Agency’s new requirements for power plants argue that forcing emissions reduc-tion will curtail economic growth. But the recent experience of states that already cap carbon emissions reveals that emis-sions and economic growth are no longer tightly tied together.” The article’s case in point was the market-based Regional Greenhouse Gas Initiative (RGGI) in the Northeast, which announced the results of its 24th auction the same day. The nine Northeast and Mid-Atlantic states partici-pating in the cap-and-trade program have substantially reduced carbon emissions while experiencing stronger economic growth than the rest of the country.

There were other factors driving the trends as well, the Times noted. RGGI states’ emissions were dropping even be-fore the 2009 program due to lower de-mand (caused by recession and warmer winters), switching to natural gas, retir-ing coal capacity, and adding renewables to the mix. But as the economy and de-mand recovered, since 2009, “the nine states have cut their emissions by 18 per-cent, while their economies grew by 9.2 percent. By comparison, emissions in the other 41 states fell by 4 percent, while their economies grew by 8.8 percent.”

RGGI has not been without controver-sy (including New Jersey Governor Chris Christie’s pulling his state out of the com-pact in 2011), and one should expect some bumps with any new type of program, but it has achieved its primary goal of reduc-ing carbon emissions. A similar program, the President George H.W. Bush-era SO2 cap-and-trade program to reduce acid rain, also achieved its environmental goals at minimal cost and has been a model for subsequent market-based initiatives.

The experience of RGGI states aside, a multistate cap-and-trade program is only one possible approach. (For more de-tails, see our June 2 story “Carbon Rules Proposed for Existing Power Plants” at powermag.com; for news coverage of future developments, watch for stories online and in our weekly POWERnews eletter.) The fact is, nobody knows whether this plan will, on its own, hurt or help the U.S. economy when it is eventually finalized. The odds are high that there will be some regional variation, given that implementation will be driven by the states. That conclusion doesn’t make for a clever sound byte or a rallying cry for any particular lobbying group, but it’s as close to reality as it’s possible to get at this early stage of the process. (Click the Webinar link at power-mag.com to learn about our July webinar on how to prepare for the next stages of the EPA’s Carbon Pollution Standards.)

The Cumulative EffectOf course, the flurry of analysis and pundit-ry about carbon standards doesn’t dimin-ish the significant challenges of complying with all the other long-standing regulations (including those governing “traditional” pollutants like SOx, NOx, and particulate matter), those recently finalized (especially MATS and the cooling water intake rule), and those anticipated (particularly coal ash and effluent limit guidelines). In fact, it’s the combination of all those rules that has to be giving heartburn to those charged with developing unit and fleetwide compli-ance plans.

Thinking about the tradeoffs involved—including those between energy and water and between efficiency and added controls—and the potential conflicts between the goals of various regulations led to the creation of this month’s cover, with its cumulus clouds. Taken together, the regulatory requirements and economic imperatives (including low gas prices, flat demand, and customer defection) facing coal plants in particular are going to make running more efficiently a core business goal. Look for articles on ways to do that in forthcoming issues. ■

—Gail Reitenbach, PhD is POWER’s editor (@GailReit, @POWERmagazine).

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Is China Considering Carbon Targets? China, the world’s biggest emitter of green-house gases (GHGs) could limit its total carbon dioxide (CO2) emissions for the first time, possibly starting in 2016. He Jiankun, chairman of China’s Advisory Committee on Climate Change, reportedly told confer-ence attendees in Beijing in June—one day after the U.S. Environmental Protec-tion Agency proposed rules to slash carbon emitted from existing power plants by 30% from 2005 levels by 2030—that China “will use two ways to control CO2 emissions in the next five-year plan: by intensity and an absolute cap,” he said.

He, a high-level advisor and not a gov-ernment official, later told news agency Reuters that the comments were a “per-sonal view,” but the announcement stirred up optimism from clean energy policy groups. Experts have pointed out that China has been reluctant to establish a binding carbon target, cautioning that the announcement did not mean anything substantive. The country set its first-ever emissions cut—40% to 45% by 2020, compared to 2005 levels—relative to its economic growth, which means absolute carbon emissions could still grow as Chi-na’s economy expands.

Many of China’s cities are plagued with severe air quality problems, inciting wide-spread concerns and protests. Among the worst hit is the capital Beijing (Figure 1), which during 2013 endured a total of 189 polluted air days—when residents were advised to stay indoors as fine particulate levels soared. This January, the city intro-duced an “all-out effort,” setting targets to tackle smog by 2017 by scrapping old cars, suspending polluting industries, and

reducing coal burning. Last September, meanwhile, China an-

nounced it would put in place a national plan to reduce its dependence on coal to improve air quality. Clean-up efforts are showing progress, albeit slow, said the country’s environmental watchdog in the “2013 Report on the State of the Envi-ronment in China,” which was released in early June. Only three of 74 cities that adopted revised air quality standards achieved required levels of sulfur dioxide, nitrogen oxides, fine particulates, carbon monoxide, and ozone. To achieve addi-tional progress, China would further en-hance the country’s energy efficiency and optimize the industrial structure, as well as enhance regional cooperation, a senior environmental protection official said as the report was released.

In related news, China’s government this May invited private companies to partici-pate in 80 major national projects, includ-ing hydropower, solar energy, wind power, and oil and gas pipelines. The move is a boost for reforms to increase privatization because, as observers note, state-owned investment ventures in energy, informa-tion, and infrastructure have a combined outstanding debt of $3 trillion as of June last year, Reuters reports.

Investor concern over unsustainable debts in China’s emerging markets were spotlighted this March, when Suntech Power Holdings—the world’s largest pro-ducer of solar panels—defaulted on a $541 million bond and other outstanding loans, marking the first-ever default of a Chinese multinational company.

Suntech’s troubles are said to have fol-lowed the plunge in solar module prices as production outpaced demand. In March, Shanghai Chaori Solar Energy Science and Technology Co. also missed payment on debt, signaling China’s first onshore bond default. That event was seen as a test case for the Chinese government, which inves-tors had assumed would bail out any Chi-nese corporation in danger of defaulting.

Among sectors open to new investors are State Grid Corp.’s distributed power grids and electric vehicle charging equip-ment, which have an estimated market value of $32 billion, state media reported. China’s state-controlled grid operator has called for a $100 billion infrastructure project to build a nationwide network of ultra-high-voltage links to reduce long-distance power losses and as a means to tackle fine particulates and other air pol-lution. However, skeptics have questioned the project’s feasibility and high costs.

The Expanding Wood Pellet MarketLast year, the U.S. exported nearly twice the amount of wood pellets it sent over-seas in 2012—and almost all of it went to Europe for heat and power needs. This trend has gained momentum since 2009, when the European Commission (EC) en-acted its 2020 climate and energy pack-age, and will possibly continue in the long term, says the U.S. Energy Information Administration (EIA) in a new report.

As recently as 2008, about 80% of U.S.–made wood pellets, typically from wood

1. China’s pollution fog. According to

the U.S. embassy in Beijing, China’s capital

has seen at least 1,812 days since 2008 when

air quality reached “unhealthy” levels and only

two days when levels were “good.” This im-

age was taken in February 2013. Courtesy:

Screw/Wikipedia Commons

2. From trash to treasure. Wood pellet exports from the U.S. nearly doubled last year,

from 1.6 million short tons in 2012 to 3.2 million short tons in 2013. Source: EIA

U.S. total exports

United Kingdom

Belgium

Denmark

Netherlands

Italy

Rest of Europe

Rest of world

0 500 1,000 1,500 2,000 2,500 3,000 3,500

Imports of U.S. wood pellets by country

(2013)

United Kingdom

59%

Italy

5%

Netherlands

6%

Denmark

7%

Belgium

18%

Rest of Europe

3%

Rest of world

2%

2013

2012

Thousand short tons


waste (such as sawdust, shavings, and wood chips), but also from unprocessed harvested wood, were consumed domesti-cally for residential heating fuel. But the EC’s binding 2009 legislation, which calls on the European Union (EU) to reduce greenhouse gas emissions by 20% from 1990 levels and to produce 20% of its pow-er from renewables, has sent demand for U.S. wood pellets soaring, the EIA says.

At least 98% of wood pellet exports (and 99% sourced from ports in the south-eastern and lower Mid-Atlantic regions of the U.S.) went to Europe in 2013, mostly to the UK, Belgium, Denmark, the Neth-erlands, Italy, and other countries that are using wood pellets to replace coal for power generation and space heating (Figure 2). The UK, specifically, consumed 59% of U.S. wood pellet exports to meet demand that has grown from near zero in 2009 to more than 3.5 million short tons in 2013. It also imported from Canada and other European sources.

One reason for the soaring growth is the UK’s Renewables Obligation program, through which operators of several large coal-fired power plants have either ret-rofitted existing units to cofire biomass wood pellets with coal or have converted to 100% biomass. Last December, for ex-ample, Drax completed the $1.14 billion conversion of three of its six coal-fired units at the Drax Power Station to bio-mass. The facility reportedly needs at least seven million metric tons of wood pellets a year. At the same time, Drax is considering converting a fourth unit, meaning pellet demand could exceed nine million metric tons. The company is building two of its own pellet plants in Louisiana and Mississippi.

According to one of the largest U.S. wood pellet manufacturers, Enviva, the primary reason that European utilities are banking on imports—rather than using wood from European forests—is because “North America has significantly more for-estland than Europe as well as a long his-tory of sustainable forest management and productive commercial forest product in-dustries.” And, biomass isn’t being adopted on the same scale in the U.S. because it just doesn’t have a “cohesive” national re-newable policy as the EU does. Meanwhile, ocean freight is “substantially more carbon and energy efficient in a per ton basis than trucking,” says the company. “This means that shipping a ton of pellets from the Southeast U.S. to England results in less carbon emissions than trucking that same ton from northern Scotland to England.”

For Enviva, the growth of the wood pel-

let export market is sound. Though the UK recently placed a 400-MW limit on new-build biomass-fired power plants, “there’s no limit on the conversion of existing coal plants to biomass or on the construction of biomass-fueled combined heat and power (CHP) fa-cilities,” it says. “Demand for sustainably produced biomass fuels is still expected to grow substantially through 2020 as coal-fired power facilities attempt to meet regula-tory targets and improve the environmental profile of energy generation.”

New Floating Wind Array Planned in ScotlandThe world’s first floating wind turbine ar-ray could be installed offshore of north-east Scotland by 2017 if a project recently unveiled by Kincardine Offshore Windfarm Ltd. proceeds as planned.

The joint project between Pilot Off-shore Renewables and the construction giant Atkins entails the installation of eight turbines on semi-submersible plat-forms about 8 miles off the fishing port

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07

CONCRETE CURING

What: At a precast concrete

production facility, on-site waste

CO2 from flue gas can be reacted

with calcium to form limestone

within the concrete, and possibly

increase concrete strength and

durability.

Status: Under development

06

ENHANCED GEOTHERMAL

SYSTEMS (EGS)

What: A new approach to this geothermal

technology involves circulating supercritical

CO2 as a heat exchange fluid instead of

water or brine to recover geothermal heat

from reservoirs 3 km deep or more for power

generation. The concept could significantly

increase the cycle efficiency compared to

current EGS.


increase con

du

StSStSSS atus: Un

for power

nificantly

pared to

nt

05

METHANOL PRODUCTION

What: CO2 can be combined with

hydrogen, compressed, and

reacted to produce methanol and

water.

Status: Demonstration stage

(plant in Iceland)

N

h

d

04

ALGAE CULTIVATION

What: CO2 can be bubbled through

algae cultivation systems, increasing

yield for a range of uses, including

biomass, biofuels, chemicals, and

food products.

Status: Demonstration level of

technical maturity technical matur

03

CLATHRATE DESALINATION

What: CO2, mixed with brine from an aquifer

at high pressure and low temperature, forms

a hydrate of CO2 surrounded by water

molecules. The hydrate is removed and

rinsed, and then goes through multiple

stages to remove dissolved solids in the

brine, resulting in an exhaust stream

of potable water that can be sold where

water is in short supply.


What: C

hydr

reacted

Statu

W

02

UREA YIELD BOOSTING

What: During production of urea (which

is used to make fertilizers), a surplus of

ammonia is often produced when natural

gas is the feedstock. CO2 can be

compressed and combined with the

surplus ammonia for additional urea

production.

Status: Commercial. CO2 capture plants

for urea yield boosting have been

installed since the late 1990s.

W

at

W

a

01

ENHANCED OIL RECOVERY (EOR)

What: Involves injection of CO2 into a

depleted oil bearing field to decrease oil

viscosity, allowing it to flow to a

production well more easily, and

increasing production by 5% to 40%.

Status: Commercial. At least 113

CO2-EOR projects inject 3.1 billion cubic

feet per day of natural and industrial

CO2 for EOR across the U.S.

The ongoing focus on carbon capture, utilization, and storage (CCUS)

has resulted in novel ways carbon dioxide (CO2) captured from industri-

al processes and power generation can be used profitably—thereby

offsetting costs associated with carbon capture. Here are seven

potential options that are undergoing development or are in commer-

cial use today. Source: Department of Energy, Office of Fossil Energy

—Copy and artwork by Sonal Patel, associate editor

THE BIG PICTURE: Recycling CO2

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of Stonehaven, in waters that are about 60 meters (m) to 80 m deep. Kincardine wants to begin construction in the second quarter of 2016 to have the wind farm op-erating by the end of 2017.

Several developers have proposed float-ing offshore wind arrays off the coasts of the UK, Norway, Denmark, Portugal, and the U.S., touting the use of semi-submers-ible platforms as a means to cut construc-tion and installation costs, because they remove the need for costly foundations. Floating offshore wind turbines can also be located in deeper waters and take ad-

vantage of stronger winds. According to Navigant Consulting, 1.7

GW of offshore capacity was installed in 2013 worldwide—mostly in Europe—bringing the total capacity to 7 GW. New and expanding projects are likely to con-tribute a record-setting 2.2 GW in 2014 alone, mostly in Germany and the UK. “Globally, offshore wind projects continue to trend further from shore into increas-ingly deeper waters,” explained Bruce Hamilton, who directs research at Navi-gant’s energy arm, this May.

Hamilton noted that Principle Power

deployed a full-scale 2-MW prototype WindFloat turbine off the coast of Aguça-doura, Portugal (Figure 3), a system that has since produced more than 9 GWh de-livered by subsea cable to the local grid. Japan also has two experimental floating 2-MW Hitachi turbines and plans to put a new Mitsubishi 7-MW turbine on a semi-submersible platform this year.

Among notable floating projects pro-posed are Principle Power and Deepwater Wind’s five floating platforms, each with a 6-MW turbine, off Coos Bay in southern Oregon, and Statoil’s proposed 30-MW venture planned for the Buchan Deep site, about 19 miles off Peterhead in Scotland. The European Commission has also award-ed funding to Principle Power to build a 27-MW second phase consisting of five WindFloat platforms developed by Prin-ciple Power, with a final build-out phase that could have a capacity of 150 MW.

“However, the costs for the initial proj-ects are very high, and as with any new technology configuration, years of testing will be required to understand how reliable and economical the technology can be,” cautions Steve Sawyer, secretary-general for the Global Wind Energy Council. “And then the challenge will be the same as for the current round of offshore deployment, that is to say how to get the scale-up re-quired to make the economics work.”

Grid-Scale Iron-Chromium Redox Flow Battery ConnectedOne of the world’s first grid-scale iron-chromium redox flow batteries was inter-connected this May to the distribution grid. The EnerVault Turlock, which its developer EnerVault says is a 250-kW, 1-MWh battery grid-scale energy storage system, will be charged by a 150-kW dual-axis tracking solar photovoltaic system in an almond orchard in California’s Central Valley, will power a 260-kW irrigation pump, and will inject energy back into the grid during peak times (Figure 4).

According to the Energy Storage Associa-tion (ESA), iron-chromium flow batteries, pioneered and studied extensively by NASA in the 1970s and 1980s, are essentially re-dox flow batteries—a class of electrochem-ical energy storage devices that employ reduction and oxidation reactions to store energy in liquid electrolyte solutions, which flow through a battery of electrochemical cells during charge and discharge.

That means, unlike other types of bat-teries, which are packaged in small mod-ules, iron-chromium flow batteries consist

3. Floating through. The current 2-MW WindFloat prototype off the coast of Aguçadoura,

Portugal, could be expanded to five platforms. A final build-out phase is planned to have a capac-

ity of 150 MW. Courtesy: Principle Power

4. Novel development. EnerVault connected its unique iron-chromium redox flow bat-

tery to the grid this May. Courtesy: Government Contractors Network


of two large tanks that store electrolytes containing iron and chromium—both abundant, relatively low-cost materials that are relatively environmentally be-nign. During discharge, the electrolytes are pumped through an electrochemical reaction cell and power becomes available. To store energy, the process is reversed.

EnerVault, however, has developed a new electrolyte pumping system to improve the efficiency of the charge/discharge cycle. In its design, electrolytes flow through a “cas-cade” of cell stacks, each holding electrolyte with a progressively lower state of charge. That allows an increase in energy density compared to a conventional flow battery.

Development of the technology was backed by $5 million in Department of Energy (DOE) funding. The DOE says that flow batteries could be an especially good solution for small island grids such as Ha-waii or at military bases. Or, they could be paired with renewables and used in a microgrid that can continue to operate during a power outage.

POWER DigestChile Banks on Renewable Capacity Expansion, Energy Efficiency. Chile in mid-May released a $650 million invest-ment plan to reduce energy costs and promote non-hydro renewable energy de-velopment for the country that imports about 60% of its primary energy resources. The plan calls for a 30% cut in marginal power costs on Chile’s central grid, which serves 90% of the country’s citizens, by 2018. It also requires that 45% of pow-er capacity installed between 2014 and 2025 be from solar, wind, and geothermal sources to put Chile closer to its target of producing 20% of its energy from re-newables. The government also called for energy savings of up to 20,000 GWh per year. Experts have warned that Chile must triple its 18 GW capacity within 15 years to continue growing its economy (see “Chile’s Power Challenge: Reliable Energy Supplies” in the September 2012 issue). Chile’s power mix is dominated by hydro-power, but droughts have left a country that has no indigenous oil or natural gas reserves energy-strapped. Beyond calling on the state oil company to boost explo-ration, the country also hopes to build a liquefied natural gas import terminal in the mineral-rich north.

Columbia Passes Renewable Energy Law. Columbia in May passed a bill that encourages investment in research and de-velopment of clean technologies as well as the use of renewables via tax incentives. The

bill also calls for rural areas that are isolated from the national grid to take up unconven-tional renewable energy solutions.

Germany Approves Industrial Ex-emption to EEG Fees. Germany’s federal government in early May approved a bill that, if adopted in July, will become ef-fective in August and protect energy-in-tensive industries from increases in a levy to promote renewables under the 2008 Re-newable Energy Act (EEG). The EEG surged to €0.0624/kWh in 2014—a 20% increase that represents nearly a fifth of residential electricity bills. Eligible companies will be defined by guidelines set by the European Union. They will pay 15% of the EEG fee, though payment is limited to 4% of the gross added value of the company (limited to 0.5% for energy-intensive consumers such as steel or aluminum plants).

Mexico’s Energy Reform Efforts Inch Forward. Mexico’s efforts to pass second-ary legislation to finalize its energy reform are grinding ahead slowly, and experts say final passage of the bills could occur be-fore the end of June. The country’s federal congress and a majority of state congress-es in December passed the much-awaited constitutional energy reform, which could spark increased private participation in

power projects, lower electricity prices, and transform the profile of the country’s ossified, state-dominated power sector.

Turkey Point Reactors Get Florida State OK. Florida’s state authorities have granted Florida Power and Light (FPL) approval to advance development of two planned AP1000 units at the Turkey Point Nuclear Power Plant, which already has two 1970s-built reactors. FPL submitted a construction and operating license ap-plication for the new Units 6 and 7 to the Nuclear Regulatory Commission in 2009, but it is still awaiting approval. In 2011, the Florida Public Service Commission al-lowed FPL to recover costs for the nuclear investment via customer charges.

Westinghouse to Fuel Three Vatten-fall Reactors. Westinghouse Electric Co. was selected in May by Vattenfall Nuclear AB in Sweden to provide replacement nu-clear fuel deliveries and related engineer-ing services for three reactors: Forsmark 3, Ringhals 3 and Ringhals 4. The contract in-cludes yearly deliveries of fuel for the three reactors during a four-year period (2016 to 2019). Westinghouse will produce the fuel at its facility in Västerås, Sweden. ■

—Sonal Patel is a POWER associate edi-tor (@POWERmagazine, @sonalcpatel)



Latest Electromagnetic Technology Device Im-proves Inspection Accu-racy and Repeatability

Eddy currents are electrical currents in-duced within conductors by changing magnetic fields. They are commonly used in nondestructive evaluation (NDE) and corrosion monitoring of structures with painted surfaces. The work of eddy current technicians, who specialize in the elec-tromagnetic modality, requires a high de-gree of accuracy even when working under challenging testing conditions.

Traditionally, technicians relied on ser-vice bulletins or paper-based instructions that outline each step of the test to en-sure accuracy and their own safety. This, however, can add to the complexity, cost, and timeliness of the testing. It also pro-vides opportunity for error, often requiring a second technician to read the instruc-tions and record the result, which itself is an error trap.

General Electric’s (GE’s) Measurement and Control business recently introduced a first-of-its-kind, handheld electromagnetic inspection technology that integrates test-ing intelligence and industry experience into an easily adaptable platform. The GE Mentor EM allows technicians to access in-formation and guidance needed to perform efficient and accurate weld, rotary, and sur-face inspections (Figure 1). By decreasing the need for paper-based service bulletins and cumbersome manuals, the device re-places legacy processes and takes full ad-vantage of the latest technology.

The equipment makes eddy current in-

spections easier, more accurate, and less time-consuming than in the past. Techni-cians are given instant access to critical in-formation by simply connecting to a local network to share data, immediately down-load up-to-date procedures and workflows, and collaborate with Level-3 experts in real time directly from the device. Additionally, reports can be generated on the spot, from the site of inspection. By placing workflows directly on the device, the Mentor helps to ensure strict compliance with codes, guide-lines, and standard practices.

According to Lyle Spiess, NDE inspec-tion programs supervisor for South Texas Project (STP) Electric Generating Station, NDE toolboxes need to have the necessary tools to validate material defects. “Inter-granular stress-corrosion cracking (IGSCC) on stainless steel material is very difficult to detect with liquid penetrant alone, and the magnetic particle method can’t be utilized. The Mentor is a field unit that provides very reliable IGSCC surface detec-tion with the use of a simple eddy current surface probe,” Spiess said. “We also use the Mentor for our heat exchanger bobbin probe functionality test while our high-end, more expensive, multi-channel units are in the field.”

GE Mentor Create software can be used to create customizable, on-device inspection workflow applications that provide consis-tent, up-to-date, and easy-to-follow instruc-tions for technicians of all levels. Inspection

technicians gain access to on-device pho-tos, procedures, and videos for reference while setting up, acquiring data (Figure 2), or analyzing data. By limiting the range of adjustments available to the operator, the opportunity for error is minimized.

“The menu-driven features of the Mentor allows linking the eddy current technique utilized for examination to the procedures required for guidance,” said Spiess.

“In high-consequence inspection envi-ronments, it is essential that technicians have access to the information they need, when they need it,” said Dave Jankowski, North American commercial NPI leader for GE Measurement & Control. “GE Men-tor EM with Mentor Create eliminates the cumbersome paper trail traditionally as-sociated with electromagnetic eddy cur-rent testing, dramatically improving the safety, efficiency, and accuracy of the testing process. Additionally, GE’s inno-vative technology will help transform the industry by bridging the skills gap and addressing the current global shortage of experienced inspection personnel in the workforce today.”

The device has a high-resolution dis-play, and its touchscreen is designed to work with gloves. “We at STP find the flex-ibility of the Mentor useful for many ap-plications,” Spiess said.

—Edited by Aaron Larson, a POWER associate editor (@AaronL_Power, @

POWERmagazine).

1. Eddy current testing with the GE Mentor EM. On-device workflow ap-

plications allow efficient, accurate data collec-

tion. Courtesy: GE Measurement and Control

2. Testing in progress. Accessing procedures on the device reduces the potential for

errors. Courtesy: GE Measurement and Control

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Is Your Plant Ready for MATS?It has been more than two and a half years since the Environmental Protection Agency (EPA) issued national emission standards for hazardous air pollutants from coal- and oil-fired electric utility steam generating units (EGUs), and stan-dards of performance for fossil fuel–fired electric utility, industrial/commercial/in-stitutional, and small industrial/commer-cial/institutional steam generating units.

Specifically, the rule created mercury and air toxics standards (MATS) designed to reduce emissions from new and existing coal- and oil-fired EGUs.

Existing sources have up to four years, if they need it, after the final rule be-came effective—April 16, 2012—to com-ply with MATS. The period includes three years provided to all sources by the Clean Air Act and an additional year the EPA al-lows state permitting authorities to grant, as needed, for technology installation. In

other words, power plants have less than one year left to comply with the rule, un-less granted the additional one-year ex-tension by their state.

While MATS compliance strategies have been covered extensively (see “Using Neural Network Combustion Optimization for MATS Compliance” in the February issue and “The Role of Activated Carbon in a Comprehen-sive MATS Strategy” in the March issue of POWER, online at powermag.com), in this article we will try to touch on a few key operational best practices that will help plants meet the new EPA requirements.

1. Nozzle deterioration. Low primary

airflow resulted in damage to this burner.

Courtesy: Storm Technologies

2. Burner geometry. It is essential

for mechanical tolerances to be within one-

quarter inch of design specification. Courtesy:

Storm Technologies

3. Good as new. Following repairs, the

burner will fire more efficiently. Courtesy:

Storm Technologies


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Tuning Up

To comply with the performance tune-up work practice require-ment, each facility must demonstrate continuous compliance by conducting a combustion process tune-up, a thorough equip-ment inspection, and an optimization to minimize generation of CO and NOx. The work practice requirement must be completed at least once every 36 calendar months (or 48 calendar months if a neural network is employed). The work practice involves: maintaining/inspecting burners (Figures 1 and 2) and associ-ated combustion controls; tuning the specific burner type, as applicable, to optimize combustion; obtaining and recording CO and NOx values before and after burner adjustments; keep-ing records of measurements and adjustments (Figure 3); and submitting a report for each tune-up conducted.

A combustion tune-up will involve optimizing combustion of the unit consistent with the manufacturer’s instructions, as applicable, or in accordance with best combustion engineering practices for that burner type. Under the final rule, the tune-up must be conducted at each planned major outage and in no event less frequently than every 36 calendar months, with an exception that if the unit employs a neural network system for combustion optimization during hours of normal unit op-eration, the required frequency is a minimum of once every 48 calendar months.

Initial compliance with the work practice standard of maintaining burners must occur within 180 days of the com-pliance date of the rule. The initial compliance demonstra-tion for the work practice standard of conducting a tune-up may occur prior to the compliance date of the rule, but it must occur no later than 42 months (36 months plus 180 days) from the compliance date of the rule or, in the case of units employing neural network combustion controls, 54 months (48 months plus 180 days). Adequate records must be maintained in order to show that the tune-ups met the requirements of this standard.

Boiler Tune-Up Requirements

The work practice standards for boiler tune-ups require inspec-tions of the burners and combustion controls. Should issues be found with the burners or combustion control components that affect the ability to optimize NOx and CO, these items must be installed/corrected within three calendar months after the burner inspection. Burner or combustion control component parts that do not affect the ability to optimize NOx and CO may be addressed on a timetable determined by the plant.

Boiler tune-ups are to include visual inspection of flame pat-

tern, damper observations, evaluation of windbox pressures and air proportions, and inspection of the air-to-fuel control system.

Combustion should be optimized to minimize generation of CO and NOx, with adjustments made consistent with the manu-facturer’s specifications or best combustion engineering practice for the applicable burner type. Optimization includes burners, overfire air controls, firing system improvements, neural network or combustion efficiency software, control systems calibrations, adjusting combustion zone temperature profiles, and add-on controls such as selective catalytic reduction and selective non-catalytic reduction systems.

Testing and tuning should be completed at full load or unit normal operating load. Figure 4 shows an actual CO, NOx, and O2 curve developed during testing/tuning that was completed.

The EPA has amended the work practice and management prac-tice tune-up standards to clarify that CO measurement, required before (Figure 5) and after (Figure 6) tune-ups, may be taken using portable CO analyzers. The requirements to inspect burn-ers and the system controlling the air-to-fuel ratio may be com-pleted during the next scheduled shutdown. Units that produce electricity for sale may also delay these inspections until the first outage, not to exceed 36 months from the previous inspection. Optimization of CO emissions must also regulate NOx within the given emissions limits. For units that are not operating when a tune-up is required, the tune-up must be conducted within 30 days of startup. ■

—Danny S. Storm is president and COO of Storm Technologies Inc.

1,600

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800

600

400

200

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4. An inverse relationship. The curves show the effect excess

O2 has on CO and NOx. Courtesy: Storm Technologies

5. Before. The imagery shows significant differences between the

north and south ducts. Courtesy: Storm Technologies

6. After. Following tuning, there was much less variation between

the ducts. Courtesy: Storm Technologies

CO NOx

Convection

Furnace

800.848.5086

©2014 Diamond Power International, Inc. All rights reserved.



Nest Thermostats: The Future of Demand Response Programs? Olivia Para

Sure, the Nest Learning Thermostat is smart, user-friendly, and downright sexy, but at $249, it’s more a luxury item than a mass-market appliance. Indeed, Nest thermostats

are highlighted in upscale real estate listings alongside marble countertops and stainless steel appliances. Although Nest has done well since its debut in 2011, with almost a million units sold, it’s hard to see how a luxury market item would justify the $3.2 billion price Google paid for Nest Labs earlier this year.

More Than a ThermostatBut Nest is not just selling sleek thermostats. Nest is partnering with utilities to provide residential demand-response programs. Currently, Nest offers two: Rush Hour Rewards and Seasonal Sav-ings. Customers participating in Rush Hour Rewards are compen-sated for allowing their thermostats to be adjusted during peak demand episodes. During a Rush Hour episode, Nest automati-cally makes small adjustments to temperatures based on each customer’s past schedule and settings. Typically, this means “pre-cooling” before the peak demand and short periods of cooling during the rush hour. The program is fully automated—the cus-tomer doesn’t have to remember to adjust the temperature and doesn’t even need to know there is a rush hour event occurring.

Last summer, Rush Hour Rewards helped achieve a 55% reduc-tion in energy use during peak times. A better sign of success, according to Nest, is how few customers manually changed the temperature during a peak event—just 14%. This is an indica-tion that Nest’s approach to demand response keeps customers comfortable, which should result in greater and more consistent participation.

Rather than responding to specific events, Seasonal Savings, by contrast, makes small, gradual adjustments to participating customers’ thermostats twice a year—in early summer and win-ter. The Seasonal Savings algorithm takes a customer’s historical schedule and temperature preferences and what the Nest ther-mostat has learned from the customer’s use to identify small ad-justments that will save energy while minimizing the noticeable change. Seasonal Savings helped reduce air conditioning usage by 4.7% on average by automatically making small temperature adjustments over time. On average, the temperature changes were less than 1 degree.

Demand Response 2.0Nest is not the first company to offer such programs, but it has uniquely combined smart and effective algorithms with a customer-focused approach. Most demand response programs re-quire customers to allow their utility to simply shut off air-con-ditioning units with special thermostats. Other utility demand response programs send an email with savings tips and hope the customer remembers to implement them. The inflexibility and

effort required with these programs are major barriers to greater participation. Both Rush Hour Rewards and Seasonal Savings are designed so that customers don’t even notice the changes. “In fact, 84% of customers who participated in Rush Hour Rewards and 89% of customers who participated in Seasonal Savings told us they were just as comfortable as they were before they partici-pated in our energy service programs,” Tony Fadell, Nest founder and CEO, said in a statement. “This is critical to the adoption and ultimate success of these programs.”

Most importantly, Nest’s demand response programs are fast responding and centrally controlled. The main issue facing utili-ties and grid operators today is integrating renewable energy generation and the increased ramping that results. To address this issue, the California Independent System Operator (CAISO) is focused on increasing the availability of fast-responding de-mand response programs that it can control. CAISO wants more resources that are callable at a certain time or during certain system conditions. Specifically, in response to critical emer-gency or stressed system conditions, CAISO needs to be able to dispatch the demand response program itself based on real-time system needs.

Currently, Rush Hour Rewards episodes are called on by utili-ties, usually a day in advance of a forecasted shortage. However, Nest has just announced Rush Hour Rewards 2.0. In the past, Rush Hour events would last two to four hours, depending on the utility’s best guess of air-conditioning needs during a heat wave. Rush Hours Rewards 2.0 will allow on-demand events that last just 30 minutes. This option gives energy companies and grid operators the ability to react quickly to rapidly changing system conditions. This will be valuable during unexpectedly hot days and could also be used to respond to sudden changes in production from intermittent renewable generation. With Rush Hour Rewards 2.0, power companies and grid operators will be able to act quickly to balance energy needs instead of having to guess the day before.

It does not appear that selling fancy thermostats to design- and green-minded consumers is the reason for Google’s $3.2 bil-lion investment in Nest. Rather, the potential is for Nest/Google to use the technology to become a major player in energy mar-kets. Together, Nest and Google could help multiply the reach of this technology in a way that utilities have failed to do with utility-run demand response programs. While individual custom-ers may notice few changes in their heating and cooling, the impact this technology will have when aggregated at utility scale could help avoid development of new power plants and transmis-sion lines. ■

—Olivia Para ([email protected]) is an associate in Davis Wright Tremaine’s energy practice group in the firm’s

San Francisco office.

AIR-COOLED HEAT EXCHANGERS COOLING TOWERS AIR-COOLED STEAM CONDENSERS



ENVIRONMENTAL CONCERNS

Combined Mercury and SO3 Removal Using SBS Injection

The U.S. Environmental Protection

Agency’s (EPA’s) Utility Mercury and

Air Toxics Standards (MATS) regula-

tion requires power plants to reduce emissions

of hazardous air pollutants (HAPs), including

mercury. The regulation requires that these

emission reductions be achieved by April

2015, or April 2016 if the plant is granted an

extension. Activated carbon injection (ACI)

is the most widely used technology for the

specific control of mercury emissions; how-

ever, ACI’s effectiveness is greatly reduced in

the presence of sulfur trioxide (SO3).

This article describes a novel approach

for mercury control that relies on the injec-

tion of a single sorbent to effectively remove

SO3 upstream of the air preheater (APH),

which greatly enhances mercury adsorption

onto the native “unburned carbon” in the

flue gas downstream of the APH. Further-

more, removal of SO3 prior to the APH al-

lows for the flue gas temperature exiting the

APH to be reduced, which further enhances

mercury capture and improves the plant en-

ergy efficiency. The co-benefit capture of

hydrochloric acid (HCl) and selenium from

the flue gas using this approach is another

advantage.

The Challenges of Removing SO3Over the past decade many generators have

installed new emissions controls on their coal-

fired power plants, including selective catalytic

reduction (SCR) systems for nitrogen oxides

(NOx) control and flue gas desulfurization

(FGD) systems for SO2 control. One conse-

quence of SCR retrofits has been a significant

increase in the amount of SO3 generated in the

flue gas and the potential to create a visible

sulfuric acid “blue plume.” In addition, higher

SO3 levels can adversely affect many aspects

of plant operation and performance, including

severe corrosion of back-end equipment, foul-

ing of the APH, and limitations in the ability to

operate at reduced loads due to SCR operating

temperature constraints.

The addition of SCR or FGD to a power

plant, or a switch to higher-sulfur fuels, can

also trigger the EPA’s New Source Review

(NSR) rules. In some cases, power plants

have been required to mitigate the elevated

SO3 emissions as a result of NSR rules.

The trademarked SBS Injection technol-

ogy has been widely applied to control SO3

emissions from coal-fired power plants.

However, it is only in recent years that the

co-removal of mercury has also been docu-

mented and demonstrated at several plants.

The technology injects a “sodium-based

solution” into the flue gas, typically ahead of

the APH or SCR. By removing SO3 prior to

these devices, many of the adverse effects of

SO3 can be successfully mitigated, and plant

performance and reliability can be improved.

SO3 removal efficiencies of greater than 98%

have been achieved using SBS Injection, with

stack emissions typically less than 1.0 part per

million (ppm). The process has been installed

on 24 boilers representing more than 15,000

MW of generating capacity, and has been in

continuous operation for more than 10 years.

A typical installation is shown in Figure 1.

As with any emissions control technol-

ogy, proper design and operation are critical

to ensure that desired performance and reli-

ability are achieved. Because the SBS Injec-

tion technology relies on the injection of a

wet sorbent solution into the flue gas, care-

Though no single mercury capture approach is best for all plants, when you can capture two (or more) pollutants with one sorbent, it’s worth a careful look.

Sterling M. Gray, Jim B. Jarvis, and Steven W. Kosler

Courtesy: URS Corp.



ful attention during system design is needed

to ensure proper atomization and drying of

the liquid to avoid solids deposition within

the ductwork.

In addition, the injection of any sodium-

based sorbent can result in secondary reac-

tions producing sodium bisulfate, which can

lead to fouling of the APH. As a result, the

injection location must be properly selected

to provide adequate reaction time prior to

the APH to ensure the SO3 concentration is

sufficiently reduced to avoid these reactions.

Recent experience has shown that with proper

design and operation of the SBS process, these

operational issues can be easily overcome.

Mercury Control ChallengesAs noted, MATS requires power plants to re-

duce emissions of HAPs, including mercury,

and although ACI is the most widely used

technology for the specific control of mer-

cury emissions, its effectiveness is greatly re-

duced in the presence of SO3. Plants burning

medium- to high-sulfur fuels and equipped

with SCRs can have as much as 30 to 80 ppm

of SO3 in the flue gas.

Research shows that even low levels of

SO3 (2 to 5 ppm) can inhibit good mercury

adsorption. There has been significant ef-

fort to develop sulfur-tolerant carbons to

overcome this challenge, but with only lim-

ited success. Dry sorbent injection (DSI)

has also been used to control SO3, but this

technology is often unable to achieve the

low SO3 levels required for good mercury

capture, and it can adversely affect the per-

formance of downstream particulate control

equipment.

Another widely used approach for mercury

control is catalytic oxidation and subsequent

capture in a wet scrubber. SCR catalyst can

be particularly effective for oxidation of mer-

cury, but its performance is sensitive to flue

gas temperature and halogen concentration.

Wet scrubbers are very effective in capturing

the oxidized form of mercury, but they will not

capture mercury in its elemental form. Some-

times, oxidized mercury captured in the scrub-

ber can be converted back to the elemental

form and be “re-emitted,” thereby increasing

stack emissions. Much research has been done

to understand and control “re-emissions,” with

some success reported in recent years. (For

more on the variety of approaches to mercury

capture, enter “mercury capture” in the Search

box at powermag.com.)

The EPA also recently proposed new

Effluent Limitation Guidelines (ELG)

for the power industry that place a limit

of roughly 120 parts per trillion (ppt) for

mercury in wet scrubber or FGD waste-

water streams. For plants that discharge

wastewater from their FGD system, this

may present another challenge in manag-

ing the fate of mercury with their plant.

Achieving the proposed limits may require

additional physical and chemical treat-

ment of the stream to transfer the soluble

mercury from the liquid phase to the solid

phase, with subsequent separation and re-

moval from the waste stream. In the worst

case, expensive mercury-specific treat-

ment techniques may be required.

In addition to mercury, these two regula-

tions place limits on acid gas—including HCl

and hydrofluoric acid (HF)—emissions in

flue gas and selenium discharges in wastewa-

ter. The MATS rule requires HCl emissions to

be limited to 0.002 lb/MMBtu as a surrogate

for the control of emissions of acid gases.

The proposed ELG rule could limit selenium

levels in FGD wastewater streams to only 10

parts per billion (ppb). The ability to capture

and remove these two species ahead of the

wet scrubber could be advantageous and may

be an effective strategy in complying with the

regulations.

A New Approach to Mercury ControlGiven the challenges of controlling mercury

emissions, and the associated high costs, there

is a need for a new cost-effective approach.

Over the past decade, testing by URS and oth-

ers has confirmed the significant impact of

SO3 on mercury capture by activated carbon.

1. SBS Injection system. The SBS system typically includes a field-erected reagent

solution storage tank (shown on the right), shop-fabricated injection skid (center), and smaller

water storage tanks (left). Courtesy: URS Corp.

14

12

10

8

6

4

2

0

0 5 10 15 20 25 30 35 40 45

Me

rcu

ry f

rac

tio

n i

n a

sh L

OI

(ug

/g)

Measured or estimated SO3 concentration at ESP outlet (ppm)

◆ Plant A ■ Plant B ▲ Plant C ■ Plant D ● Plant E Plant D (Post-APH) 2009

● Plant D (Pre-SCR) 2009

2. The lower the better. Native mercury capture across the electrostatic precipitator

(ESP) can be greatly enhanced when SO3 is reduced to only a few ppm. Source: URS Corp.



URS has gathered extensive data from

existing SBS Injection installations that also

show how SO3 affects the “native” capture of

mercury by the unburned carbon (UBC) or

loss on ignition (LOI) that is typically present

in flue gas. Figure 2 shows how mercury ad-

sorption onto unburned carbon increases dra-

matically as the flue gas SO3 concentration

is reduced from 5 ppm to 1 ppm. The data

shown were collected by varying the SBS

sorbent injection rate and measuring both the

mercury and LOI levels in the fly ash and the

SO3 concentration in the flue gas exiting the

electrostatic precipitator (ESP). The results

show that reducing the SO3 down to very low

levels can result in significantly higher mer-

cury capture rates.

Industry research also shows that mercury

adsorption onto carbon is temperature depen-

dent with minimal capture above 350F and

maximum capture below 250F. To investigate

both the effect of flue gas temperature and

SO3 concentration, URS recently conducted

a full-scale test program with cofunding pro-

vided by the Electric Power Research Insti-

tute (EPRI) and a host utility. Testing was

conducted at a Midwestern power plant with

an existing SBS Injection system. The plant

burns high-sulfur bituminous coal and is

equipped with an SCR, ESP, and wet FGD.

During the test program, the APH exit

gas temperature was varied from nominally

340F down to 290F at full-load conditions by

simply varying the degree of combustion air

preheat. Temperatures as low as 265F were

achieved at reduced load conditions. The

SBS sorbent injection rate was also varied

from a typical molar injection ratio of 1.5 to

an elevated ratio of 2.5 Na2CO3:SO3.

Flue gas measurements of elemental and

oxidized mercury concentrations were made

at the ESP outlet using a semi-continuous

emission monitor and were validated with

limited sorbent-trap testing in the stack. Flue

gas SO3 measurements were also made at the

ESP outlet using the controlled condensation

sampling method. Coal and fly ash samples

were collected during the test program, and

both were analyzed for mercury and UBC

content. Finally, HCl and selenium measure-

ments were made in the coal, fly ash, and flue

gas at the ESP outlet.

Parametric test results, summarized in

Figure 3, show the overall mercury removal

efficiency as measured from the coal to the

ESP outlet. Results indicate that higher mer-

cury removal was achieved by both increas-

ing the SBS injection rate and lowering the

flue gas temperature.

At the highest temperature (340F), mercu-

ry removal was limited to about 60% at ele-

vated sorbent injection rates. However, at the

lower flue gas temperature (270F), mercury

removal increased to 80% and above, even at

the lowest sorbent injection rate.

Test results also indicated that both elemen-

tal and oxidized mercury were removed across

the ESP, ensuring a reduction in stack mercury

emissions. For example, at the lowest flue gas

temperature (270F), the elemental mercury

concentrations at the ESP outlet were reduced

to about 0.6 lb/TBtu, well below the MATS

emission limit of 1.2 lb/TBtu. During the

testing, flue gas SO3 levels at the ESP outlet

ranged from 0.8 to 1.2 ppm, and fly ash LOI

levels varied from 3.5% to 5.0%.

Results from the test program clearly

show the benefit of both reducing the flue

gas SO3 concentrations to very low levels and

reducing the flue gas temperature leaving the

APH. Some of the approaches to lowering

the flue gas temperature include eliminating

preheating of the combustion air entering the

APH, modifying the depth and design of the

APH heating elements to increase overall

heat transfer, and lowering the furnace exit

gas temperature. Most plants can use one or

more of these approaches to reduce their flue

gas temperatures. However, Figure 3 shows

that even at moderately high APH outlet tem-

peratures, SBS Injection can enhance native

mercury capture and reduce emissions.

By capturing a very significant fraction of

the mercury across the ESP, the stack mer-

cury emissions can typically be reduced to

well below the MATS emission limit. Based

on the positive results from the EPRI test pro-

gram, the host utility has elected to upgrade

its existing APH elements to achieve much

lower flue gas temperatures and much higher

mercury capture—a key component of its

MATS compliance strategy.

Other power plants are also exploring how

they can use their SBS Injection system to

reduce mercury emissions. Recent testing at

an SBS installation in West Virginia has also

shown that reducing the APH operating tem-

perature can lower mercury emissions. In the

Midwest, Indianapolis Power & Light recently

selected the SBS Injection process for its Pe-

tersburg Station specifically to control both SO3

and mercury as part of its MATS compliance

strategy. For plants burning fuels with a range

of sulfur and mercury levels, the SBS injection

process can effectively mitigate the impact of

SO3, thereby maximizing the native capture of

mercury and minimizing emissions.

Furthermore, by reducing the SO3 con-

centration at the inlet to the APH to very low

levels, it is also possible to eliminate fouling

of the APH due to sulfuric acid and/or am-

monium bisulfate. Based on research and

testing conducted by a leading APH manu-

facturer, the APH can now be reliably oper-

ated at much lower temperatures, improving

mercury capture and plant heat rate or energy

efficiency. One might say that this new ap-

proach allows a power plant to “capture more

mercury … by burning less coal.”

Capturing more mercury in the fly ash also

significantly reduces the amount of mercury

that is captured by the wet scrubber, which

can provide several potential benefits. First,

if less mercury is retained in the scrubber,

then the potential amount of mercury that

can be “re-emitted” is also reduced, thereby

lowering the risk that this phenomenon will

result in exceedences of the MATS limit.

Second, by lowering the mercury content in

the FGD scrubbing liquor, it is much more

likely that ELG limits for mercury content in

100

90

80

70

60

50

40

30

20

10

0

260 270 280 290 300 310 320 330 340 350

Air preheater outlet temperature (F)

Me

rcu

ry r

em

ova

l (%

, co

al

to E

SP

ou

tle

t)

◆SBS molar ratio 1.5 ■ SBS molar ratio 1.8 ▲ SBS molar ratio 2.5

3. Reducing temperature reduces emissions. Once the SO3 is removed ahead of

the air preheater, mercury emissions can be further reduced by lowering the flue gas tempera-

ture. Source: URS Corp.



FGD wastewater streams can be met without

the need for additional treatment.

HCl and Selenium Co-RemovalAs mentioned earlier, HCl emissions in flue gas

and selenium discharges in wastewater are also

regulated by MATS and proposed ELG rules,

respectively. Recent testing has shown that

sorbent injection for the removal of SO3 and

mercury is also effective for the capture and re-

moval of HCl and selenium from flue gas.

HCl removal results as a function of the

SBS sorbent injection rate are illustrated in

Figure 4. At typical SBS sorbent injection

rates, roughly 40% HCl capture was achieved,

while elevated injection rates resulted in

nearly 70% HCl capture. These results are

consistent with previous testing that shows

that SO3 is preferentially removed, with ex-

cess sorbent available to remove HCl present

in the flue gas. However, results at a given

plant will vary depending on the relative con-

centrations of SO3 and HCl in the flue gas,

and the overall sorbent injection rate.

Co-removal of HCl with the fly ash can pro-

vide several advantages to the operating plant.

Some plants must control the dissolved chlo-

ride levels in their wet scrubbers due to materi-

als of construction and corresponding corrosion

concerns. As a result, many plants must operate

with a chloride purge stream from the FGD sys-

tem. In most cases, this chloride purge stream

must be treated prior to discharge.

In addition, the newly proposed ELG rules

may require additional treatment to meet new

stringent limits for mercury and selenium. By

capturing HCl in the fly ash, and reducing the

amount captured in the FGD system, it may

be possible to greatly reduce, or even elimi-

nate, the need for a chloride purge stream.

As a result, it may be possible to avoid the

75

70

65

60

55

50

45

40

35

30

1.25 1.50 1.75 2.00 2.25 2.50 2.75

SBS Injection molar ratio (Na2CO3:SO3)

Ch

lori

de

re

mo

val

ac

ross

ES

P (

% o

f c

oa

l C

l)

4. HCl captured in ESP. In addition to very high SO3 removal, SBS Injection can achieve

significant co-removal of hydrochloric acid (HCl), thereby reducing levels in the downstream flue

gas desulfurization system and wastewater streams. Source: URS Corp.




significant capital and operating costs associ-

ated with FGD wastewater treatment.

Effective capture of selenium has also

been demonstrated using the SBS Injection

process. Figure 5 shows selenium removal

across the ESP as a function of the SBS sor-

bent injection rate and flue gas temperature

at the APH outlet. Results indicate that 60%

to 90% capture efficiency was achieved over

the range of sorbent injection rates tested.

As described earlier, the newly proposed

ELG rules place stringent limits on selenium

in FGD wastewater streams. By capturing a

significant fraction of the gaseous selenium

with the fly ash, it may be possible to meet

the ELG limits without the need for costly

treatment technologies.

It All Adds UpAchieving new stringent MATS and ELG

limits presents numerous challenges for con-

ventional approaches that will require signifi-

cant capital expenditures, as well as increased

plant operating costs. As described here, re-

cent testing has shown that the injection of a

single sorbent can effectively remove the reg-

ulated pollutants while improving plant heat

rate and energy efficiency, reducing plant

operating costs, and achieving significant co-

removal of HCl and selenium—which may

make it possible to avoid costly wastewater

treatment requirements resulting from the

proposed ELG rules. ■

—Sterling Gray ([email protected]) is a technology and business development

manager in the Process Technologies group at URS Corp. Jim B. Jarvis is a senior project

manager, and Steven W. Kosler is a senior process engineer for URS Corp.

100

95

90

85

80

75

70

65

60

55

50

1.25 1.50 1.75 2.00 2.25 2.50 2.75

SBS Injection molar ratio (Na2CO3:SO3)

Se

len

ium

re

mo

val

ac

ross

ES

P (

% )

5. Captures selenium too. Significant co-removal of selenium across the ESP us-

ing SBS Injection can help plants meet the stringent proposed effluent limitation guidelines.

Source: URS Corp.

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Biomass Exemption Sails into the Sunset

Approximately four years ago the U.S.

Environmental Protection Agency

(EPA) took the first step in regulating

greenhouse gas (GHG) emissions from elec-

tric generating units (EGUs) by promulgating

the Greenhouse Gas Tailoring Rule on June 10,

2010. The rule was implemented over a two-

and-a-half-year period with three major steps

covering new and existing emission sources.

This rule will significantly affect new and ex-

isting sources, as GHG emissions are now reg-

ulated pollutants. Facilities that generate more

than 100,000 tons a year of equivalent carbon

dioxide are now classified as major sources.

Carbon dioxide equivalent is defined as the

combined emissions from carbon dioxide,

methane, nitrous oxide, hydrofluorocarbons,

perfluorocarbons, and sulfur hexafluoride.

For the majority of fossil fuel–fired sourc-

es, this rule is just another regulatory speed

bump requiring EGUs to address GHGs.

For smaller renewable power generators and

utilities adding biomass power plants to their

fleet, this regulation is a serious roadblock

that will push small biomass facilities from

less-regulated area emission sources to full-

blown major emission sources.

With deadlines for meeting renewable

portfolio standards quickly approaching, ad-

ditional regulatory hurdles would decrease

the likelihood of reaching those mandated

levels of renewable generation. It is with this

in mind that shortly after promulgation of

the GHG Tailoring Rule, several members of

the U.S. Congress filed complaints with the

then-administrator of the EPA, Lisa Jackson,

requesting a deferral of the rule’s applicabil-

ity to biomass sources.

Enough pressure had been placed on the

EPA that action was taken to temporarily

exempt renewable EGUs from the Tailoring

Rule’s impact. On July 1, 2011, the Federal

Register published an update to include a

three-year deferral for the “application of

Prevention of Significant Deterioration (PSD)

and Title V permitting requirements to carbon

dioxide emissions from bioenergy and other

biogenic stationary sources.” The purpose of

this three-year deferment was to allow the

EPA to conduct a detailed analysis of the sci-

ence associated with biogenic carbon dioxide

emissions from stationary sources.

For clarity, not all biomass power genera-

tors were granted the deferment. As part of

the three-step implementation process of the

GHG Tailoring Rule, the first step included fa-

cilities that currently were covered under Title

With quickly approaching deadlines for achieving renewable portfolio stan-dard goals, the likely lapse of a critical exemption this month may increase the challenges for meeting those mandates.

Brandon Bell, PE

Source: National Renewable Energy Laboratory

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V permitting programs. Those facilities would

not be granted a deferment and would be sub-

ject to carbon dioxide equivalent regulations.

For biomass facilities that were already cov-

ered under Title V programs, the EPA issued

a guidance document for determining the best

available control technology (BACT) for bio-

genic carbon dioxide emissions. The EPA also

made the deferral voluntary, leaving it to the

discretion of individual states to adopt the de-

ferral and to regulate accordingly.

Significance of Area SourcesArea sources, sometimes also referred to as

minor emission sources, are facilities that have

emissions too small to be treated as a point

source. The EPA defines area sources as those

emitting any individual hazardous air pollut-

ant (HAP) less than 10 tons per year, emitting

combined HAPs less than 25 tons per year, or

(depending on the source category) a facility

emitting less than 100 or 250 tons per year of

individual criteria pollutants.

HAPs are defined by the Clean Air Act,

which was last updated in 1990 and contains

a list of 189 chemicals classified as HAPs.

Criteria pollutants consist of nitrogen oxides

(NOx), sulfur dioxide (SO2), fine particulate,

carbon monoxide, and volatile organic com-

pounds.

EGUs that have the capability of firing

more than 250 million Btu an hour of fossil

fuels fall under the more stringent regulation

of 100 tons per year of criteria pollutants to

achieve area source classification. Assuming

a facility uses biomass as its primary fuel

source and the combined fossil firing of any

ancillary equipment is less than 250 million

Btu an hour, the facility would be regulated

as an area source. This is advantageous, as

biomass area sources are allowed to emit up

to 250 tons per year of criteria pollutants and

avoid federal PSD regulations.

There are other advantages for a facility

being classified as an area emission source. If

a facility falls under PSD permitting require-

ments, the following areas must be addressed

in the permit application: BACT analysis

addressing emission controls technologies,

an air quality analysis, an additional impact

analysis, and public involvement:

■ BACT analysis is a case-by-case analysis

that addresses the maximum degree of

emission control for each pollutant and

factors in energy, environmental, and eco-

nomic impacts.

■ The air quality analysis is meant to dem-

onstrate that the new facility will not

violate any National Ambient Air Qual-

ity Standards as a result of the facility’s

operation. This analysis first assesses the

existing air quality of a site using ambient

monitoring devices. The second part of the

analysis incorporates dispersion modeling

of the new emission source to predict the

impact on the surrounding environment.

■ Additional impact analyses pertain specifi-

cally to the effect of construction and opera-

tion of the new facility on the proposed site.

These assessments include ground and wa-

ter pollution on soils, impacts on wetlands,

vegetation, visibility, endangered species

analysis, and archaeological impacts.

■ Public involvement allows the general pub-

lic to provide comments to a draft permit

and typically involves a public hearing to ad-

dress any concerns directly to the EPA and

owners. The time to permit a major source

can take anywhere from 12 to 18 months,

depending on the complexity of the facility.

Because area sources have been deemed

too small to be classified as a point source,

their permitting process is typically done at

a state level. Most states do not impose PSD

permitting requirements such as BACT, air

quality analysis, and impact analyses.

As a result of the less-onerous permit re-

quirements, the process to obtain a construc-

tion permit for an area source is reduced to

approximately three months. The speed and

reduced complexity of the permitting process

is particularly favorable to utilities wishing to

utilize biomass fuel sources to meet renew-

able portfolio standards. Private developers

also favor the area source permitting process,

as less capital is required and quicker con-

struction start times are expected.

How Biomass EGUs Are AffectedWith a greater focus on adding renewable

power generation to meet renewable portfolio

standards, the ability to permit and build bio-

mass power generation facilities is becoming

crucial. Biomass fuels by their nature tend to

have low levels of compounds that create reg-

ulated byproducts as a result of combustion.

As an example, a typical woody biomass fuel

used to generate steam from a fluidized bed

combustor and using only a pulse jet fabric fil-

ter for particulate control could be sized at 25

MW and still be classified as an area source.

In the U.S. there are approximately 144

power generating facilities using biomass fu-

els as their primary fuel source (Figure 1). Of

those 144 facilities, nearly half (71 facilities)

have a rated capacity of 25 MW or less, mak-

ing small generators a significant portion of

the national biomass generation portfolio.

If the current GHG Tailoring Rule exemp-

tion for biogenic sources were vacated, the

rated capacity of the same wood burning bio-

mass facility outlined above would plummet

to approximately 8 MW of generation capac-

ity before crossing the major emission source

threshold. This reduction is significant, as the

number of biomass sources currently rated at

8 MW and less is a mere 16. Assuming the

25 MW or less >25 MW 8-25 MW 8 MW or less

73

71

16

55

1. How small is small? Currently, biomass plants of 25 MW and less fall below the

threshold for being classified as “major emission sources.” If biomass plants were subject to

the Greenhouse Gas Tailoring Rule, the threshold would drop to 8 MW, exempting only 16 of the

144 existing biomass facilities instead of the 71 considered area sources today. Source: Energy

Information Administration



same distribution of biomass plant sizes is

expected in the future, approximately 89% of

those facilities would be classified as major

emission sources as a result of the GHG Tai-

loring Rule being applied.

Sunset ProvisionThe exemption of biogenic carbon dioxide

sources from the GHG Tailoring Rule was

not a popular move for some industry groups.

This is evidenced by the more than 200-page

“Summary of Public Comments and Re-

sponses” document issued on June 28, 2011.

With such strong feelings against the defer-

ral, these groups filed a challenge to vacate

the EPA’s deferral.

In July 2013, the D.C. Circuit Court issued

a 2-1 ruling vacating the biogenic carbon diox-

ide deferral and caused turmoil in the biomass

industry. The industry legally had 30 days to

file for a rehearing on the ruling, but the op-

portunity to appeal is being withheld. Instead,

the court decided to tie any additional actions

to another key case, Utility Air Regulatory

Group (UARG) v. EPA. In this case the UARG

is challenging the EPA’s authority to regulate

carbon dioxide from stationary sources via the

Massachusetts v. EPA (2007) ruling.

The D.C. court withheld the mandate of

the vacatur until a ruling from UARG v. EPA

was issued. As a result of this withholding,

the original biogenic exemption remains in

place. The Supreme Court heard oral argu-

ments in the UARG v. EPA case on Feb. 24,

2014, and a decision is expected in the latter

part of the year.

Although this would appear to give renew-

able biomass power generators hope for the

future, the reality is that time is still running

out on this exemption. In the published defer-

ral, section 51.166 provided clear direction for

the lifespan of this deferral: “For the purposes

of this paragraph, prior to July 21, 2014 the

mass of the greenhouse gas carbon dioxide

shall not include carbon dioxide emissions re-

sulting from the combustion or decomposition

of non-fossilized and biodegradable organic

material originating from plants, animals,…

and biodegradable organic material.”

That statement is commonly referred to as

a sunset provision for the deferral. Without

EPA studies supporting the future exemption

of biogenic carbon dioxide emissions, and

barring any decisions by the federal courts

to overturn the vacatur, on July 21, 2014, the

deferral will simply expire.

Regulatory and Permitting ComplexitiesAlthough it may appear that the expiration of

the biogenic deferral will be detrimental to

new biomass facilities, the problem may be

more complex than that. With the assumption

that no further action by the courts will be

realized, facilities that took advantage of the

biogenic carbon dioxide deferral during this

three-year period most likely will be required

to retroactively obtain permits that address

the GHG Tailoring Rule.

Precedence for this retroactive permit mod-

ification was demonstrated with the vacatur

of the EPA’s Section 112(n) Revision Rule

of the Clean Air Mercury Rule. The Section

112(n) revision rule was published Mar. 29,

2005, and removed coal- and oil-fired EGUs

from the list of applicable sources in Section

112(c). On Feb. 8, 2008, the U.S. Court of

Appeals for the D.C. Circuit Court vacated

the Section 112(n) revision rule and issued a

mandate on Mar. 14, 2008. EGUs that used

this exemption in the permitting process and

began construction or reconstruction between

Mar. 29, 2005, and Mar. 14, 2008, were now

legally required to comply with Section

112(g) requirements.

Implementation of the GHG Tailoring Rule

has been around for several years now, and by

far the most common control method for carbon

dioxide equivalent emissions has been energy

efficiency methods. However, for those facili-

ties constructed between June 10, 2010, and

July 21, 2014, that used the biogenic carbon

dioxide deferral and now will be classified as

major emission sources, other pollutants may

be subject to emissions control technologies.

Depending on the specific pollutant in

question, expensive control technologies

may need to be retroactively installed at ex-

isting facilities. Equipment such as selective

catalytic reduction systems for NOx control

and wet and dry scrubbers for SO2 control

potentially work their way into the econom-

ics of these biomass facilities. However, it is

too early to say if any of these pollution con-

trol technologies will be mandated.

Although the biogenic carbon dioxide de-

ferral is set to expire in July, there is still the

possibility that the regulation of carbon diox-

ide emissions from EGUs could be vacated

later this year. Deadlines for meeting state

renewable portfolio standards are quickly

approaching—nine are set for 2015—and the

need for renewable power sources is great.

Adding additional permitting, capital, and

operational hurdles for new and some exist-

ing sources will only make achieving these

goals more problematic.

With so much uncertainty, it’s hard to pre-

dict what the future holds, but new biomass

EGUs should be prepared for stiffer environ-

mental controls, and existing biomass EGUs

that utilized the biogenic exemption should

prepare for possible permit modifications. ■

— Brandon Bell, PE (bbell@valdeseng .com) is a project manager at Valdes Engi-neering and a POWER contributing editor.




The Water-Energy Nexus Takes Center Stage

Unless you’ve been living in a cave,

you’ve likely heard the term “water-

energy nexus” recently. Around the

globe, experts and policy makers are waking

up to the reality that the world’s energy needs

and its water needs are on a collision course.

A recent report from the Congressional

Research Service lays out the challenge in

the U.S. National water consumption is pro-

jected to increase 7% by 2030, and 85% of

that increase is attributable to the energy sec-

tor. Globally, the figures are dire: According

to the International Energy Agency (IEA),

consumption is projected to increase 2.5% per

year through 2035 even with policy changes

designed to increase water use efficiency,

with energy-related consumption doubling

over the same period.

The potential for a staggering conflict can

be drawn from just two statistics: Worldwide,

according to the United Nations, 2 billion peo-

ple lack access to safe water supplies, and 1.3

billion lack access to electricity. In most cases,

these numbers represent the same people.

Uncertain DataOne problem in tackling these challenges is

a paucity of good data. The U.S. Geological

Survey (USGS), which publishes comprehen-

sive reports on water usage in the U.S. every

five years, has not reported water consumed in

power generation since 1995—only total with-

drawals. The USGS plans to return to report-

ing this data with the study for 2010, but this

report will not be available until late 2014.

Thus, though it is known that withdraw-

als for once-through cooling (OTC) have

been more or less level since 1980, it is not

clear how recent moves toward generation re-

sources with very different water use profiles

may have affected consumption. The Electric

Power Research Institute (EPRI) has attempt-

ed to fill this gap, most recently with a report

updated in April 2014, though it covered only

thermoelectric plants using freshwater.

The EPRI results, based on data from

2009 for all thermal plants except nuclear

(for which data through 2011 was available)

are consistent with previous studies suggest-

ing that while power generation withdraw-

als are a significant portion (about 40%) of

total withdrawals, consumption constitutes a

much smaller share. Total withdrawals were

estimated at 139,800 million gallons per day

(mgd), with OTC accounting for almost all

of this. Consumption was estimated at 3,930

mgd, with most of this (2,760 mgd) account-

Power plant operators have long understood the vital role water plays in power generation. Now, as the rest of the world begins recognizing that as well, a conflict is brewing between the growing demand for electricity and increasingly strained water resources.

Thomas W. Overton, JD

Source: EPA



ed for by wet recirculating cooling.

This appears to represent a largely un-

changed load on the nation’s water resources

compared to 2005 USGS data. The USGS es-

timated that total (fresh and saltwater) with-

drawals for power generation that year were

201,000 mgd, of which 142,710 mgd were

freshwater.

Regional ChallengesWhile the U.S. is far less water-stressed than

countries such as China and India, many

states face challenges in meeting water de-

mand. A May 2014 report from the U.S. Gen-

eral Accounting Office (GAO) found that 24

of 50 states were likely to experience region-

al water shortages over the next decade and

40 out of 50 state water managers expected

some portion of their states to experience

shortages under average conditions.

These responses are not surprising given that

large portions of the western U.S. are currently

experiencing severe to exceptional long-term

drought. This includes nearly all of California,

Arizona, and New Mexico, and large portions

of Texas, Oklahoma, and Kansas.

Significantly for the generation industry,

California and Texas represent the two largest

markets for future capacity, according to the

Energy Information Administration (EIA).

Further, the Southwestern U.S. as a whole is

projected to see greater than 30% electricity

demand growth by 2040.

Ongoing droughts have threatened disrup-

tions to generation in Texas and the Midwest

(see “Water Issues Challenge Power Genera-

tors” in the July 2013 issue) and have caused

curtailments in hydropower generation in

California and the Pacific Northwest. The

California Independent System Operator

said in May that the state was likely to have

as much as 1,669 MW of its hydroelectric

capacity unavailable this summer, while

as much as 1,150 MW of thermal capacity

would be unavailable due to limitations on

cooling water withdrawals.

Kate Zerrenner, project manager for the

Environmental Defense Fund’s U.S. Climate

and Energy Program and a former climate

policy analyst with the GAO, isn’t convinced

generators fully appreciate what they’re fac-

ing. “Many electric utilities and power grid

operators have drought contingency plans,

but drought planning is not the same thing

as water planning,” she told POWER. “If we

anticipate a growing demand of this limited

resource (and we do), we need to talk about

climate change. It is no longer an option to

conduct long-range planning without using

all the available data. We need a thorough

analysis of climate impacts on water, so both

electric and water utilities know what they’re

working with.”

Globally, water stresses are concentrated

in the Asia-Pacific region, with the greatest

future stresses projected to come in the coun-

tries expected to see the greatest electricity

demand growth: China and India (Figure 1).

Many of China’s problems stem from a

geographic mismatch between its resources

and population. While water is relatively

abundant in the south, its population and

water-intensive industry—and thus its great-

est power demands—are concentrated in

the water-poor northeast. About 60% of the

nation’s planned capacity growth is sited

in this region, even though it has but 5% of

the country’s water resources. According to

a report from the World Resources Institute

released in April, almost 60% of China’s

generating capacity is expected to face steep

competition for water in the future, which has

forced the central government to enact caps

on withdrawals and set goals for increased

efficiency. (For more on China’s water chal-

lenges, see “Power Sector Link to Water Is

Deep, Complex” in the June issue, available

at powermag.com.)

According to the IEA, withdrawals for

power generation in India are expected to

grow by almost 50% between 2010 and

2035, with consumption more than doubling.

Most of the stresses will come in the southern

and eastern coastal regions, as well as heavily

populated Gujarat state. The country has al-

ready experienced water-related disruptions

to generation: Shortages forced the 2.3-GW

Chandrapur coal plant in Maharashtra offline

in the summer of 2010, leading to power out-

ages across the state, a situation that nearly

recurred during a second drought in 2012.

A similar shutdown occurred at a plant in

Chhattisgarh in 2008, and the 2012 drought

was blamed in part for a massive blackout in

August that knocked out power for almost

half the nation.

Though Europe is not generally consid-

ered water-stressed, it has still experienced

water-related challenges to generation, nota-

bly during droughts in 2003 and 2005, which

caused a series of curtailments at thermoelec-

tric plants. France in particular lost a quar-

ter of its nuclear capacity during the 2003

drought as a result of constraints on cooling

water. Climate change is expected to aggra-

vate future water stresses in Europe, accord-

ing to the IEA, with reduced summer river

flows and higher water temperatures.

Other regions of the world are facing po-

tential water-energy collisions. The Middle

East, one of the most arid regions on earth,

is a study in contrasts. The wealthy countries

around the Persian Gulf have managed their

water stresses through energy-intensive de-

salination. Though this has given them suf-

ficient water supplies, a substantial portion

of their total generation capacity is devoted

to producing water. Meanwhile, the poorer

countries struggle to meet both water and

power needs of their population. (For more

on this region’s energy profile, see “Shifting

Sands: The Middle East’s Thrust for Sustain-

ability” in this issue.)

Latin America’s heavy reliance on hydro-

power has meant fewer challenges with respect

to cooling but greater exposure to drought-in-

duced curtailments. Conflicts have also arisen

between hydroelectric plants and agricultural

interests. Though the region as a whole is less

water-stressed than others, there are still arid

countries, such as Chile, where generators

have had to plan carefully to meet their water

needs (see “Chile’s Power Challenge: Reliable

Energy Supplies” in the September 2012 is-

sue). Climate change is also expected to re-

duce the reliability of existing hydro resources

in the future, according to the IEA.

Finally, Africa—the least electrified re-

gion in the world—is also looking toward

hydropower as a way forward. Hydro cur-

rently supplies 32% of Africa’s generation,

though only 8% of its economically feasible

hydro potential has been developed (see “The

Power Potential of Southern Africa” in the

February 2014 issue).

Changing RegulationsGiven its numerous inherent challenges, it’s

hardly surprising that the water-energy nexus

has drawn increasing regulatory attention.

At the federal level, the Environmental Pro-

tection Agency (EPA) on May 19 issued its fi-

nal rule governing power plant cooling water

intake systems under Section 316(b) of the

Clean Water Act. The rule is focused on reduc-

ing impingement and mortality of aquatic life

and is expected to have little immediate effect

on total withdrawals. Closed-cycle cooling is

favored—though not required—for new ca-

pacity. (For more on the new rule, see the June

2014 issue cover story, “Site-Specific Factors

1. Under threat. India’s drive to boost

its generation capacity will be challenged by

its perennial water shortages. The 2.6-GW

Ramagundam coal plant in the southern state

of Andhra Pradesh is located in one of the na-

tion’s most water-challenged areas. Source:

Getsuhas08/Wikipedia



Are Critical for Compliance with Final 316(b)

Existing Facilities Rule.”)

The EPA is also in the process of revis-

ing its rules on power plant effluent. The

proposed rule, published in April 2013, es-

tablishes new or additional requirements

for wastewater streams. Several compliance

options are proposed for existing plants, but

zero-liquid discharge could potentially be the

standard for new plants. The final rule was

supposed to be published on May 22 but has

been delayed until September 2015 while the

EPA completes its rulemaking for coal ash.

At the state level, California in 2010

moved to phase out OTC at plants that draw

cooling water from the ocean or marine estu-

aries (Figure 2). The rule requires retrofitting

with closed-cycle cooling or reducing impact

on marine life through other means. Most

plants will need to be in compliance by 2020,

though a few have until 2029.

While regulatory attention is growing,

Zerrenner believes more than that is neces-

sary. “In most instances, power and water

are not managed by the same regulatory enti-

ties,” she noted. “To the same effect, at the

legislative level, often the committee charged

with water policy is not the same as the one

charged with energy policy.” Tackling the

water-energy nexus will require breaking

down policy and regulatory silos.

At the federal level at least, that may be

happening. In May, Senators Lisa Murkowski

(R-Alaska) and Ron Wyden (D-Ore.), both

members of the Senate Committee on Energy

and Natural Resources, introduced a bill to

establish an interagency coordination com-

mittee focused on the water-energy nexus.

The bill also proposes a budget mechanism to

allow policymakers to see where funding is

needed across energy-water initiatives.

The Challenge of Changing TechnologiesWhile a shift away from OTC may reduce

withdrawals, Kent Zammit, senior program

manager with EPRI, warned that it could also

increase consumption. “Wet cooling towers

typically evaporate over twice as much wa-

ter as OTC,” he said. According to the EPRI

study, coal plants using OTC from adjacent

rivers consumed 212 gal/MWh on average,

while those using cooling towers consumed

365 gal/MWh. The differences were even

greater for nuclear plants, with those using

cooling towers consuming 545 gal/MWh ver-

sus 155 gal/MWh for OTC.

This suggests that while shifting to

closed-cycle cooling will require much lower

volumes of available water, it is likely to in-

crease the power sector’s overall consump-

tion, perhaps significantly, unless dry cooling

methods constitute the bulk of the new sys-

tems. Dry cooling, however, is the most

expensive and carries the largest efficiency

penalties. It is also not appropriate for every

plant or every location. Large nuclear plants

in particular are unable to use dry cooling, in

part for safety reasons. Dry cooling for coal

plants, while currently rare, is seeing increas-

ing use, particularly overseas: China, South

Africa, and Australia have all built large coal

plants using dry cooling methods in water-

challenged areas.

While wind and solar photovoltaic gen-

eration require negligible amounts of water,

the same cannot be said of all new genera-

tion technologies. Concentrating solar power

(CSP), in particular, when coupled with wet

cooling methods, can consume substantial

amounts of water, in some cases exceeding

that of fossil generation methods. This is a

problem since these systems are typically

sited in hot, arid, water-poor areas because

these regions typically experience the highest

insolation.

When coupled with dry cooling, CSP re-

quires very little water (Figure 3). However,

in addition to the increased costs, dry cooling

is much less effective in hot environments,

and CSP plants can experience reduced out-

puts of 10% to 15%, or more, on hot days.

Integrated gasification combined cycle

(IGCC) generation, should it gain a foot-

hold—which is uncertain (see “Does IGCC

Have a Future?” in this issue)—could reduce

overall water consumption from coal genera-

tion. However, the savings are not as great as

might be suspected because the water saved

from the steam cycle and emissions control

systems is offset by consumption from the

gasifier.

According to research by the National

Energy Technology Laboratory (NETL), cur-

rent IGCC designs consume around 102 gal/

MWh to 139 gal/MWh for process and emis-

sions control, compared to 107 gal/MWh to

116 gal/MWh for steam plants. The main

savings are in cooling, if wet evaporative

methods are used: Largely because of their

greater efficiency, IGCC plants consume

around 20% to 30% less water for cooling

than do steam plants.

When carbon capture and storage (CCS)

is included, however, the water savings are

significant. Though CCS itself consumes

substantial additional water, it requires far

less when coupled with IGCC than with

steam. Adding CCS could nearly double a

2. Shifting gears. Dynegy’s 2.5-GW Moss Landing plant near Monterey, Calif., must

cease using ocean water for cooling before 2018. Dynegy is considering retrofitting wet cooling

towers for the four-unit facility. Courtesy: David Monniaux

3. Sipping lightly. The 392-MW Ivanpah

Solar Electric Generating Station near Las

Vegas uses large air-cooled condensers that

keep the plant’s water needs very low. It con-

sumes only 5% of the water of a comparably

sized thermal plant using wet recirculating

cooling. Source: POWER/Tom Overton



steam plant’s water consumption, according

to the NETL report, but it would increase

an IGCC plant’s consumption by only about

37%. Still, said Zammit, the “penetration

and impact [of CCS] will be unit- and site-

specific.”

Another impact on water resources could

come from biomass generation. While in-

plant water consumption is comparable to

coal plants, growing biomass fuel may re-

quire significant amounts of water, particu-

larly if it is grown specifically for use in a

power plant. This is a concern in areas where

agricultural water supplies are already under

stress, such as China, India, and the U.S. cen-

tral plains.

Biomass is not the only fuel with an effect

on water resources. Natural gas from shale is

projected to constitute 53% of the U.S. gas

supply by 2040, according to the EIA. While

the water consumed by hydraulic fracturing

is small compared to agricultural use, much

shale gas development is taking place in ar-

eas under water stress, such as Texas. Shale

gas, as a new industry, must compete with

existing demands on water resources, some-

thing that has caused controversy in many

areas. It is worth noting as well that, unlike

water used in agriculture, most of the water

used in hydraulic fracturing is permanently

lost from the hydrological cycle. Waterless

methods, though currently limited, are likely

to grow in importance.

The Way ForwardThere is clearly pressure—political, social,

and environmental—to reduce the power sec-

tor’s load on water resources. Most of these

pressures will be experienced in areas such as

India and China, where both electricity and

water supplies are constrained.

Zerrenner believes one key is better coor-

dination between power and water suppliers.

“The power sector and the water sector need

a better understanding of how they impact

each other,” she said. “A crucial first step is

for power and water engineers to start collab-

orating. They can then work with regulators

and legislators to reveal novel conservation

strategies. Everyone in the chain in both

sectors needs to understand the interconnec-

tion.”

For existing plants, a focus on improving

efficiency—of both water and plants—will

be key. A 2010 NETL study reviewed various

methods that have been employed globally,

among them:

■ Replacing/retrofitting with modern, more

efficient plant systems.

■ Switching to higher-quality coal.

■ Use of waste heat to dry high-moisture

coals.

■ Retrofitting dry cooling.

■ Retrofitting cogeneration.

■ Purification/desalination of brackish water

and saltwater.

■ Dry bottom ash handling.

■ Dry emissions scrubbing.

■ Recycling and reusing wastewater.

■ Improved monitoring of water consumption.

The use of alternative sources of water de-

serves special attention, since it can have the

most direct impact on a plant’s consumption

of local water resources. One facet of this can

include capturing wastewater streams, such

as cooling tower blowdown, and using these

for processes that do not require high water

quality. Cascading wastewater from higher-

to lower-quality needs enables extensive re-

use. Many plants in water-stressed areas have

already implemented such recycling mea-

sures. Making degraded water sources more

cost-effective for cooling is another area with

future possibilities, according to Jessica Shi,

a senior technical leader at EPRI.

Where large quantities of water are needed

for wet cooling, municipal wastewater has

proven useful as a replacement for freshwa-

ter. A number of new plants in the U.S., such

as the Sand Hill Energy Center in Austin

(Figure 4) and the Empire Generating Plant

in Rensselaer, N.Y., have leveraged such sup-

plies. Doing so, however, requires special

measures because of the potential for gener-

ating airborne pathogens.

For high-quality water needs, purifica-

tion and desalination of water resources

that are not suitable for agriculture or other

competing uses—whether seawater or low-

quality groundwater—is an option. While

expensive and energy intensive, it can be

made cost-effective if a desalination plant is

co-located with the power plant in an area

where freshwater is at a premium (that is,

where it can be sold to recapture some costs)

and waste heat can be captured for use in the

desalination process (see “Adding Desalina-

tion to Solar Hybrid and Fossil Plants” in

the May 2010 issue). Advanced membrane

distillation technology could also greatly re-

duce the costs of desalination.

Going forward, new technologies will

be necessary to further improve efficiency

and reduce costs for closed-cycle cooling,

as well as improving overall plant water

efficiency. “We have technologies today

that can reduce water consumption for new

plants,” said Zammit. However, “research is

still needed to address the cost and O&M

impacts of such technologies. In addition,

research into technologies such as the ther-

mo-syphon cooler and more cost-effective

water treatment options could help conserve

water at existing plants.”

EPRI and several partners inaugurated the

Water Research Center at Georgia Power’s

Plant Bowen in Cartersville, Ga., in 2012

with the goal of generating industry-wide

insights that will help generators minimize

their impact on water resources. (See “Re-

search Center Dedicated to Power Plant Wa-

ter Use Opens” in the November 2012 issue,

and “Advanced Cooling and Water Treatment

Technology Concepts for Power Plants” in

the April 2014 issue.) Specialized research

such as this is certain to be key. ■

—Thomas W. Overton, JD is a POWER associate editor (@thomas_overton, @

POWERmagazine).

4. Nifty shades of gray. The Sand Hill Energy Center in Austin, Texas, began using treat-

ed wastewater from a nearby wastewater treatment plant for cooling in 2006, which allowed it

to reduce its use of municipal potable water by 80%. Courtesy: Austin Energy



Shifting Sands: The Middle East’s Thrust for Sustainability

The Middle East is a region of ex-

tremes. While some countries enjoy

opulent wealth, others are some of

the poorest in the world. While it is the

center of global oil and gas production,

it is also a primary center of oil demand,

driven ever higher by soaring peak power

demand. And, already one of the driest

and most water-scarce areas of the world,

the region is expected to double its popu-

lation in the next 40 years.

In response to expected soaring growth

in power demand, and with some countries

already afflicted by crippling power short-

ages, governments in the 14 countries across

the region (Bahrain, Iraq, Iran, Israel, Jordan,

Kuwait, Lebanon, Oman, Palestine, Qatar,

Saudi Arabia, Syria, United Arab Emirates

[UAE], and Yemen), and specifically the Is-

lamic monarchies that make up the Gulf Co-

operation Council (GCC)—Qatar, the UAE,

Kuwait, Bahrain, Saudi Arabia, and Oman—

are embarking on ambitious plans to expand

power capacity.

But compared to countries with soaring

needs like China, Brazil, and India, this re-

gion’s efforts are distinguished by a shift

toward diversification and away from depen-

dence on indigenously sourced fossil fuels.

Conservation of fossil fuels is being pursued

not only because the hydrocarbon resources

are finite but also because it makes sound fi-

nancial sense.

The Middle East, for example, uses oil for

33% of power generation—compared to the

world average of just 4%—especially during

the sultry summer months. But at internation-

al prices of $100 per barrel, burning oil (at

highly subsidized prices) in low-efficiency

thermal power stations that characterize the

region poses a financial drain and diminishes

prospects for oil exports.

Natural gas has been the replacement of

choice, given the region’s large gas resource

base—though, as experts point out, the re-

gion suffers a moderately underdeveloped

transmission and distribution network that

puts countries at risk of shortages. In Iraq,

for instance, gas shortages have currently

stalled operations at four power plants that

were completed in the country last year,

and in Saudi Arabia, gas shortages have

forced generators to turn to burning heavy

fuel oil or crude oil directly. (For more on

the use of heavy fuel oil, see “ Blurring the

Line Between Temporary and Permanent

Power” in this issue.) The uncertain sup-

ply of natural gas has in some cases even

impelled countries like the UAE, Saudi

Arabia, Oman, and Bahrain to consider

building coal-fired capacity.

And beyond volatile prices and tightening

supplies, Middle Eastern oil-producing na-

tions are also wary of the diminishing com-

petitive advantage for hydrocarbons posed

by global climate change policies, prompting

them to look to renewables, which provide

obvious sustainability advantages. Others,

still, are considering nuclear.

The ChallengesAccording to experts, long-term sustainable

growth in the Gulf Arab states particularly

will depend on how well they introduce ener-

gy efficiency measures, invest in low-carbon

energy supplies, improve water efficiency,

and expand water desalination capacity.

The Renewable Energy Policy Network

Economic and population booms forecast for several countries in the oil- and gas-rich Middle East are forcing a reassessment of those countries’ historic reliance on fossil fuels and a new focus on securing sustainable electricity and water supplies.

Sonal Patel

Courtesy: Dhuruma Electricity Co.



for the 21st Century (REN21), a global policy

research network, and the International Re-

newable Energy Agency concur that progress

is happening rapidly. One factor spurring a

dynamic shift in the policy landscape across

the region is the establishment or expansion

of regional cooperation and institutional ac-

tivities related to enhancing energy and water

supply sustainability.

Recent years, for example, have seen the

founding of the Masdar renewable energy

development and investment cluster in Abu

Dhabi and the King Abdullah City for Atom-

ic and Renewable Energy in Saudi Arabia.

Meanwhile, at least 12 of the 14 Middle East-

ern countries, both net oil-exporting and net

oil-importing, have renewable energy targets

(Table 1).

Some are staggering: Saudi Arabia alone

is looking to add 54 GW of renewables by

2032 to replace an estimated 23% to 30%

share in total primary energy supply (see

sidebar “Saudi Arabia’s Planned Transforma-

tion”). Several countries also have net meter-

ing in place or capital subsidies and tax or

production credits or reductions, and most

rely on either direct or indirect public fund-

ing or public competitive bidding processes

for fixed quantities of renewable energy.

REN21 reports that investment trends

in the region are healthy, despite a global

downturn. New investment in renewables in

the Middle East and North Africa combined

totaled $2.9 billion in 2012, an increase of

almost 40% over 2011, and a 6.5-fold in-

crease from 2004. Yet, that progress could

be hindered by a number of challenges, it

warns, including the region’s susceptibility

to political unrest, financial uncertainty, and

policy risk.

Nuclear PossibilitiesConsidering those risks, it is significant that

several countries in the Middle East—among

them, the UAE, Jordan, Saudi Arabia, and to a

lesser extent, Qatar, Oman, Kuwait, and Bah-

rain—are actively considering starting nuclear

programs for power and water supply.

In a 2008 independently published com-

prehensive policy on nuclear energy, the gas-

rich UAE dismissed coal as an option to meet

projected escalating power demand because

of its environmental and energy security im-

plications. In an explanation that has since

been echoed by the region’s other countries,

the UAE said nuclear emerged as a “proven,

environmentally promising and commercial-

ly competitive option.”

Today, after accepting a $20 billion bid

from a South Korean consortium to build

four nuclear reactors—a total of 5.6 GW—

two are already under construction at UAE’s

Barakah site in Abu Dhabi (Figure 1). The

UAE hopes to have all four 1.4-GW APR-

1400 units producing power by 2020 and

plans to export power to Gulf neighbors via

the regional power grid. Uniquely, the UAE

offset delays to a construction start by offer-

ing joint-venture agreements to foreign in-

vestors for the construction and operation of

future nuclear plants, and it plans to manage

its nuclear power program based on contrac-

tor services, rather than indigenous expertise.

It also concluded long-term agreements for

the supply of nuclear fuel. The plants will,

for the most part, be financed by the state and

Korean equity partners.

The Barakah reactors won’t be the first in the

region. That honor goes to Iran’s controversial

Bushehr reactor. Construction was suspended

in 1979, resumed in 1994, and the plant began

commercial operation in late 2013, reconfigured

as a VVER-1000 by Russia’s Atomstroyexport.

Installed

capacity (MW) PV CSP Wind

Biomass/

Waste Geothermal Hydro Total Renewable target(s)

Oman 0.7d 0c 0c 0c 0c 0c 0.70 200 MW targeted total installed PV capacity

Palestine* 1b 0c 0c 0c 0.023b 0d 1.02 20% of total electricity consumption by 2020

Yemen 1.5b 0c 0c 0c 0c 0c 1.50 15% of total electricity by 2025

Kuwait 1.8d 0c 0c 0c 0c 0c 1.80 10% of total electricity consumption by 2020, 15%

by 2030

Bahrain 5c 0c 0.5b 0c 0c 0c 5.50 NA

Saudi Arabia 7a 0c 0c 0c 0c 0c 7.00 23%–30% targeted share of renewables in total

primary energy supply by 2032

Jordan* 1.6b 0c 1.4b 3.5b 0c 10b 16.50 1 GW renewable capacity by 2018

Qatar 1.2d 0b 0b 40b 0b 0b 41.20 10% targeted share of replaced energy used for

power and desalination with solar power by 2018

UAE 22.5b 100a 0c 3b 0c 0c 125.50 7% of total capacity by 2020 (Abu Dhabi); 5% of

total consumption by 2030 (Dubai)

Lebanon* 1b 0c 0.5b 0c 0c 282b 283.50 12% of total electricity consumption by 2020

Israel* 269b 0c 6c 27b 0c 7e 309.00 10% of total electricity consumption by 2020

Syria 0.84d 0c 0c 0c 0c 1,151d 1,151.84 195 MW target of PV and wind in primary energy

by 2015

Iraq 3.5e 0c 0c 0c 0c 1,864b 1,867.50 450 MW additional renewable capacity by 2017

Iran 4.3d 17c 91b 0c 0c 9,500b 9,612.30 NA

Notes: a = 2013, b = 2012, c = 2011, d = 2010, e = 2009. All countries are net oil-exporting, with the exception of those marked with an asterisk.

Table 1. Installed renewable capacity in the Middle East. Source: REN21

1. Nuclear option. In August 2012, the

United Arab Emirates became the world’s

first “newcomer” in 27 years to start nuclear

power plant construction when it began work

on Barakah 1. Today, two of four planned APR-

1400 reactors are under construction there,

slated to come online by 2020. Courtesy:

Emirates Nuclear Energy Corp.



And beyond Saudi Arabia’s lofty call for 18

GW of new nuclear capacity, Qatar is also look-

ing into the viability of nuclear power to sup-

port soaring electricity demand and expanded

desalination capacity. The country signed a

nuclear cooperation agreement in 2010 with

Russia’s Rosatom. Oman, meanwhile, has

expressed interest in investing in a neighbor-

ing country’s nuclear plant. In 2010, Kuwait

announced an intention to build four 1-GW

nuclear reactors by 2022, but in mid-2011 said

it would not proceed with those plans.

Finally, Jordan, which must import more

than 95% of its energy needs at a cost of

nearly one-fourth its GDP and which also has

a substantial “water deficit,” in October 2013

selected Atomstroyexport as the supplier of

two AES-92 nuclear units. The country will

make its final decision on the new builds in

late 2015. Russia is expected to contribute

about half of the project’s total $10 billion

cost for the build-own-operate project.

Power TradingEmerging solutions to address potential en-

ergy shortfalls in the region include the estab-

lishment of cross-border interconnections and

power trading. While most countries have had

long-existing interconnections with neighbor-

ing countries, some are considering transcon-

tinental imports, including hydro from the

Nile Basin, the Congo, and Central Asia and

Pakistan. The most prominent interconnec-

tion program is the Gulf Cooperation Council

Interconnection Authority’s (GCCIA’s) partly

commissioned 400-kV “supergrid,” which

links GCC countries: Bahrain, Kuwait, Qatar,

Oman, UAE, and Saudi Arabia.

That $1.2 billion project entails three

phases (the first two were completed by

2011), including a high-voltage direct cur-

rent back-to-back 1,200-MW installation

between a 50-Hz, 400-kV system and a 60-

Hz, 380-kV system. Developers highlight

the line’s success, saying it has provided

instantaneous transfer of power to state net-

works to avoid full or partial interruptions

during major incidents—thus avoiding sig-

nificant economic losses caused by outages.

A 2013-released GCCIA report claims it has

saved GCC countries $3 billion in invest-

ments as well as $330 million in operating

costs and fuel.

The interconnection authority is now re-

portedly eyeing the introduction of an en-

ergy market management system, a bidding

platform that would replace time-consuming

Saudi Arabia’s Planned Transformation

The region’s energy supply woes and future trends are perhaps best

characterized by Saudi Arabia, the world’s 13th-largest country

that is mostly a harsh, dry desert with great temperature extremes.

It is the world’s largest country without a river. The kingdom also

takes the distinction of being the world’s largest oil producer, ex-

porter, and holder of proved oil reserves.

But during the summer, when temperatures can soar to 128F, the

country sees sharp upward swings in oil demand, primarily driven

by power sector consumption—and specifically, from its largest

utility, Saudi Electric Co. (SEC).

In 2012, the kingdom’s power fuel mix was 39% natural gas

(down from 52% in 2007), 35% crude oil, 20% diesel, and 6% fuel

oil. Despite calls for more gas-fired generation to free up more

crude oil for exports, an increasing preference for oil-fired genera-

tion over gas generation is being bolstered by highly subsidized

prices for oil paid by power producers. In 2012, for example, gen-

erators paid $0.73/MMBtu for crude oil (the corresponding interna-

tional price was $19.26/MMBtu) and $0.75/MMBtu for natural gas

(compared to an international price of $9.04/MMBtu). However,

observers also note that Saudi Arabia lacks adequate infrastructure

to pipe natural gas from the production and processing centers in

the eastern region to the oil-rich western and southern regions.

One of the kingdom’s newest gas plants, shown at the top of this

story, is Dhuruma Electricity Co.’s (DEC) Riyadh PP11 plant, a 1.7-

GW independent power project situated about 125 kilometers west

of Riyadh, which was completed in March 2013 after three years

of construction. Hyundai Heavy Industries was the project’s en-

gineering, procurement, and construction contractor. GE supplied

the seven high-efficiency gas turbines and two steam turbines.

Experts posit that Saudi Arabia’s key challenge lies in a low

energy pricing policy. Despite gradual reform recently embarked

on by the government, and a revision of tariffs in 2010, the policy

caps power prices in the kingdom at 1.3 cents to 6.9 cents/kWh

and encourages “wasteful” consumption, notes Bassam Fattouh,

director of Oxford’s Institute of Energy Studies and head of the

research center’s Oil and the Middle East Programme.

“Between 2003 and 2012, electricity sold (a proxy for electricity

demand) increased from 128,629 million kWh to 240,288 million

kWh, an increase of 78%. During the same period, the peak load

increased from 23,938 MW to 51,939 MW, an increase of 117%,”

he says. Fattouh also points out that 50% of the kingdom’s total

generated power is consumed by the residential sector—and nearly

three-quarters of that is used for air conditioning. Industry uses

17%, commercial entities 16%, and governmental agencies 13%.

Because Saudi Arabia has a regionally unique 60-Hz grid fre-

quency that severely limits the potential for grid interconnections,

the country has embarked on plans to increase its generating ca-

pacity from 55 GW in 2013 to 120 GW by 2020 to meet soaring

future demand and support expanded water desalination efforts.

But beyond its short-term options to use fuel oil and diesel instead

of crude oil—which often has to be imported during summer de-

mand swings—and reluctant to undertake the political wrangling

required to raise prices of fossil fuels to reflect true costs, Saudi

Arabia plans to press ahead with improving power sector efficiency

by phasing out old power plants and introducing more efficient

ones (thus gaining 37 GW of capacity), reducing consumer de-

mand, and changing its power mix.

Among its diversification ambitions is building up to 18 GW of

nuclear capacity over the next two decades, at a cost of nearly $7

billion for each of the 16 planned reactors. The country has signed

key nuclear cooperation agreements with Japan, France, and Jor-

dan, and hopes to call in preliminary bids for its first reactor this

year. Construction could then commence in 2017, with completion

slated for 2022. Meanwhile, the kingdom has also unveiled formi-

dable renewable energy capacity targets: 25 GW of concentrated

solar power, 16 GW of solar photovoltaic, 9 GW of wind, 3 GW of

waste-to-energy, and 1 GW of geothermal by 2032.

Combined, Saudi Arabia’s plans effectively call for nuclear

and renewables to make up 50% of produced electricity by

2032—though, as experts point out, the kingdom has not

matched its targets with a dedicated national policy frame-

work or energy strategy.



bilateral negotiations and contracts and al-

low countries to request bulk electricity and

advertise spare capacity at the same time.

The GCCIA ultimately wants to establish a

wholesale and spot-priced market in the GCC

and beyond, though GCCIA Chief Operating

Officer Ahmed Ali Al-Ebrahim acknowledg-

es several hurdles must first be overcome.

Perhaps its greatest challenge, though:

The GCC must orchestrate a policy shift

away from electricity subsidies in the region.

Subsidies on power and natural gas produced

obstruct a proper electricity market from

forming in the GCC, because true prices of

both are unknown. Until GCC countries can

address the political and economic issues that

inhibit price-reflective electricity markets,

the full potential of the GCC interconnection

grid will be left untapped, he said.

Water WoesFor the drought-prone Middle East, where

average rainfall ranges between 20 and 40

cm per year (compared to 72 cm globally),

water scarcity is a paramount concern. The

region hosts about 5% of the world’s popula-

tion but only 1% of its renewable water re-

sources, most of which is in transboundary

basins such as the Euphrates and Tigris River

Basins (shared by Syria, Iraq, and Iran) and

the Jordan River Basin System (Jordan, Pal-

estine, and Israel). As a result, almost all of

the region’s water resources are overexploit-

ed and severely polluted, leading to saltwater

intrusion in the aquifers and subsequent low-

ering of water tables. Meanwhile, population

and economic growth are expected to further

catapult water demand—which, compounded

by adverse climate change effects, could set

the stage for conflict.

Some initiatives entail regional collabo-

ration on water and electricity. The oil-rich

countries on the Arabian Peninsula, specifi-

cally, are tackling the problem with large de-

salination schemes to help alleviate water

stress. Desalination is costly and energy in-

tensive, with energy costs accounting for up

to 50% of operation costs. According to the

Pacific Institute, desalination plants general-

ly require 15 MWh for every million gallons

of freshwater produced. Still, the process has

been practiced for more than 50 years in the

region (Figure 2) and emerged as the most

feasible solution for some countries.

The International Desalination Associa-

tion (IDA) reports that more than half of the

world’s capacity growth between 2001 and

2011—276%, rising to 6.7 billion cubic me-

ters a day (m3/d)—took place in the Middle

East. The region’s desalination efforts are

characterized by three main methods differ-

ing in terms of energy consumption and cost,

and whether they can be used for seawater

or brackish water treatment. Multistage flash

and multi-effect distillation are distillation-

based methods that are generally preferred

because they support cogeneration of water

and power. The third, more energy-efficient

method—reverse osmosis (RO)—uses mem-

branes to separate salts from water. But

though membrane technology and energy

recovery have improved markedly since the

1960s, and RO today makes up the bulk of

worldwide desalination capacity, energy con-

sumption still accounts for about 40% of op-

eration costs.

The region’s recent shift to promote sus-

tainability encapsulates the water and energy

nexus (see also “The Water-Energy Nexus

Takes Center Stage” in this issue). Experts

posit that Saudi Arabia’s water use is seven

times its sustainable level, while the UAE

uses 15 times its sustainable level, and Kuwait

more than 20. Meanwhile, several leaders are

actively backing projects that shift from fu-

eling desalination efforts with oil (and, less

frequently, natural gas) and toward concen-

trated solar power and other renewables—

even though some experts are unconvinced

renewables can match the high-energy foot-

print needed for desalination.

As the largest desalination producer in

the world, Saudi Arabia’s efforts to produce

more than 4 million m3/d (representing 18%

of global production), for example, require

roughly 300,000 barrels of oil per day. The

kingdom in December announced it would

build the world’s largest solar-powered de-

salination plant in Al-Khafji Governorate on

the Arabian Gulf Coast that will have the ca-

pacity to produce 30,000 m3/d and 2.5 GW of

power via ultra-high concentrator photovol-

taic cells when completed. That RO project

is only the first phase of the King Abdullah

Initiative for Solar Water Desalination that

requires all seawater desalination in the king-

dom to be powered completely by solar by

2020. The second phase entails a 300,000

m3/d solar-powered desalination plant; a third

phase implements the initiative throughout

the kingdom.

Finally, with 120 desalination plants oper-

ating in the region and more water required

to fuel the energy boom and vice versa, some

experts express trepidation about the possible

environmental consequences from release of

so much brine back into the oceans. Then

there are concerns about greenhouse gas

emissions from the intense amount of energy

required for the process.

But the solutions here too are standard.

Two levels of actions require urgent atten-

tion to achieve a lower energy footprint, says

Middle East expert and former IDA President

Dr. Corrado Sommariva. “The first one is the

creation of policies that encourage energy

efficiency, providing a realistic price for en-

ergy even in oil-rich countries and rewarding

energy efficiency. On the technical level, it

is necessary to educate managers and plant

operators on how to operate plants in a much

more energy efficient manner with relatively

few changes.” ■

—Sonal Patel is a POWER associate edi-tor (@POWERmagazine, @sonalcpatel).

2. Rendering water. The desalination facility at Kuwait’s 300-MW gas-fired Shuwaikh

power plant in the Arabian Gulf region went into operation in the 1950s. The plant’s efficiency

was recently improved by up to 15% with the overhaul of three blocks. The country’s popula-

tion hit three million in 2010 and is expected to be 5.5 million in 2025. While its only renewable

water comes from wells, per capita water consumption is 110 gallons per day, almost double

the international rate. Courtesy: Bilfinger Engineering and Services



Geoengineering: A Practical Climate Work-Around or Just Plain Crazy?

As it looks increasingly unlikely that

the world will adopt a political and

economic approach to reducing

greenhouse gas emissions—primarily car-

bon dioxide—what was once regarded as

a far-fetched, fringe idea is generating in-

creased mainstream interest. The popular

term is “geoengineering,” although the chief

proponent prefers “solar radiation manage-

ment” or SRM.

Initially, the attention of those focused

on preventing or managing global warming

focused on the political and economic ap-

proach: How do we get the governments of

the world to find ways to stop putting more

carbon dioxide and other greenhouse gases

into the atmosphere? But that strategy has

become mired in international politics with

little prospects of effective action.

What’s left? Attention is increasingly fo-

cusing on ways to cool the planet by blocking

some sunlight from reaching Earth, either by

preventing it from getting to Earth or reflect-

ing it back toward the sun. It’s no longer a

fantastic notion but is becoming a main-

stream approach.

Add Another GasThe SRM acronym is the creation of David

Keith, the Gordon McKay Professor of Ap-

plied Physics at Harvard’s School of Engi-

neering and Applied Sciences (and also a

professor of public policy at Harvard’s Ken-

nedy School of Government). His recent

book, A Case for Climate Engineering (MIT

Press, 2013), argues that research should be-

gin now on ways to slow global warming by

engineering practices, rather than by what

appear to be dead-end policy directives and

regulatory initiatives.

Keith is humble about the path he urges.

“The bitter truth,” Keith writes, “is that the

world’s efforts to cut emissions have (with

a few exceptions) amounted to a phony war

of bold exhortation and symbolic action. It’s

tempting to assert emissions cuts are impos-

sible and that we must look to alternatives

like geoengineering. This is double wrong.

First, solar geoengineering may reduce risks

in the short term but it cannot get us out of the

long-term need to cut emissions. Second, to

assert that emissions cannot be cut is to take

human agency—and responsibility—out of

the picture as if emissions were coming from

some species other than our own.”

Keith wants to test a managed approach to

using sulfate aerosols released into the atmo-

sphere: a controlled attempt to mimic what

nature has already done repeatedly with major

volcanic eruptions—such as the Mount Pina-

tubo eruption in the Philippines in 1991—that

cool the planet. (The NASA image at the top

of this article shows the atmosphere less than

two months after the Pinatubo eruption; two

dark layers of aerosols make distinct bound-

aries in the atmosphere.) “The best case for

taking solar geoengineering seriously,” he

said in a Washington Post interview last year,

“is that the balance of scientific evidence we

have—from the same kind of climate models

and other science that we use to understand

climate change—suggests that these technolo-

Faced with roadblocks to reducing greenhouse gas emissions via globally meaning-ful regulations or carbon pricing schemes, some scientists say it’s time to consider even more drastic human intervention.

Kennedy Maize

Source: NASA



gies could, if used carefully, significantly re-

duce climate risk. Full stop.”

Keith says the technologies he’s explored,

injecting sulfur dioxide into the atmosphere or

adding fine sea salt to marine clouds to make

them whiter and change the solar albedo, or

reflectivity, “appear to provide a pathway by

which we could substantially reduce climate

risks over the next half-century. That means

reducing the risks of sea-level rise, reducing

the risks of stress for crops of people in the

poorest and hottest parts of the world.”

Keith says he sees geoengineering as a

short-term way to buy time. “Nothing chang-

es the fact that in the long run, the only way

to manage carbon risk is to stop emitting car-

bon dioxide. But, similarly, nothing we know

about cutting carbon dioxide emissions says

that’s going to help us deal with the risk of

CO2 that’s already in the atmosphere.” He

says he sees “cutting emissions as a long-

term solution and geoengineering as more of

a short-term solution.”

In his book, Keith says, “Geoengineer-

ing complements emissions reductions. Cut-

ting emissions reduces the long run risk by

stopping the accumulation of carbon, while

geoengineering—if it works as expected

—will mask risks in the short run (in the slow

moving world of carbon and climate short

run means the next half century).

“But geoengineering cannot eliminate the

underlying risk that comes from humanity’s

rapid (in geological time) transfer of carbon

from underground reservoirs to the atmo-

sphere. It’s hard to overstate the importance

of geoengineering’s ability to reduce risk

for current generations as there are no other

methods that can reduce these risks signifi-

cantly in the next half century.”

The Reflection OptionAnother approach to geoengineering comes

from Scottish engineer Stephen Salter, emer-

itus professor of engineering design at the

University of Edinburgh. Salter is the inven-

tor of the “Salter Duck,” a device for turn-

ing ocean wave motion into electricity (see

sidebar). His latest idea, which has won sub-

stantial support, including investment from

Microsoft billionaire Bill Gates, is to mount

a fleet of ships to spray seawater into the at-

mosphere to change the albedo of clouds to

reflect sunlight back into space (Figure 1).

(Keith also has money from Gates.)

Gates provided funds for prolific inventor

Armand Neukermans to test the idea of alter-

ing the reflectivity of clouds to deflect sunlight

away from the planet. Neukermans calls it

“cloud brightening.”

“He more or less showed it was feasible to

my satisfaction,” said Ken Caldeira, a promi-

nent climate scientist who advises Gates on

global warming issues.

Jane Long, a former top executive at the

Department of Energy’s Lawrence Liver-

more National Laboratory, said, “If we have

to intervene, we should be doing the research

now, because these ideas are extremely com-

plicated and extremely risky. I hope we never

have to do it, but I think it’s irresponsible not

to understand as much as we possibly can in

case we need it.”

Long was the co-chair of a Bipartisan

Policy Center task force, which three years

ago concluded that “the federal government

should embark on a focused and systematic

program of research about climate remedia-

tion. The federal government is the only en-

tity that has the incentive, responsibility, and

capacity to run a broad, systematic and effec-

tive program; it can also play an important

role in effectively establishing international

research norms.”

Not So FastBut that’s not a unanimous opinion by any

reckoning.

The enthusiasm for geoengineering,

even for small-scale research, is dangerous

techno-optimism that risks turning over the

state of the climate to business interests, says

Clive Hamilton, professor of public ethics at

Charles Sturt University in Australia and also

the author of a recent book, Earthmasters:

The Dawn of the Age of Climate Engineering

(Yale University Press, 2103). He argues that

research into geoengineering would threaten

the moral imperative to protect the Earth. He

writes that geoengineering “actually repre-

sents a profound change in the relationship of

Homo sapiens to the Earth. In the twenty-first

century the fate of nature has come to depend

on the ‘goodwill’ of humans, and to the ex-

tent that humans are part of nature the Earth

system itself has acquired a moral force.”

Hamilton and Keith debated the geoengi-

neering topic at a joint Harvard–Massachu-

setts Institute of Technology meeting last

fall, with predictably inconclusive results

(Figure 2). Nonetheless, the event—and the

publication of dueling books—has served

to raise the profile of the geoengineering is-

sue. The sparring between those advocating

geoengineering research and its opponents

has been going on for several years, but it has

been rekindled by the publication of the two

books and the failure of the governments of

1. Cloud brightening. When aerosol

particles from ship exhaust enter the lower at-

mosphere, marine stratocumulus clouds are

brightened, leaving “ship tracks” visible in sat-

ellite images. Scientists at Pacific Northwest

National Laboratory and the National Oceanic

and Atmospheric Administration (NOAA) are

among those studying the effects of particle

injection to evaluate whether this technique

could be used to offset some effects of global

climate change. Courtesy: Jeff Schmaltz,

MODIS Rapid Response Team, NASA/God-

dard Space Flight Center

Salter’s Ducks

Back in 1974, amidst the Arab oil embargo,

University of Edinburgh engineer Stephen

Salter came up with an interesting idea

for how to generate electricity from ocean

waves. It was a pear-shaped device about

the size of a house that floated in the wa-

ter. As the waves hit it, the gyroscopes in-

side the device converted the wave energy

into rotation, which could then be used

to generate electricity. Each duck could

generate up to 6 MW, and the plan was

to install them in groups of a dozen or so

(perhaps to be known as flocks). A small-

scale prototype was built in 1976.

Initial estimates from the government

concluded that “Salter’s ducks” were far

too expensive to compete with even the

most expensive generation of the time,

nuclear power.

As oil prices fell in the 1980s, the Brit-

ish government abandoned its wave en-

ergy program. It later turned out that the

government had overestimated the costs

by a factor of 10. In an article in 2008, The

Economist magazine said, “The reasons for

this were not made public, but it is widely

believed to have happened after lobbying

by the nuclear industry. In testimony to

a House of Lords committee in 1988, Dr

Salter said that an accurate evaluation of

the potential of new energy sources would

be possible only when ‘the control of re-

newable energy projects is completely re-

moved from nuclear influences.’”



the world to agree on ways to curb carbon

dioxide emissions.

The advocates portray geoengineering as

a technological issue. The opponents tend to

advance moral objections. In his book, Ham-

ilton argues, “Climate engineering may lend

itself to moral corruption. If we are preparing

to pursue for self-interested reasons—because

we are unwilling to restructure our economies

or adjust our lifestyles—then the promotion of

geoengineering can provide us with a kind of

cover or even self-absolution. But if climate

engineering is inferior to cutting emissions

(in the sense of being less effective and more

risky) then merely by choosing to engineer the

climate instead of cutting emissions we suc-

cumb to moral failure.”

One of the most aggressive foes of geoen-

gineering has been Joe Romm, a physicist and

former Clinton administration Energy Depart-

ment official, now ensconced at the liberal

Washington think tank Center for American

Progress. (Hamilton dedicates his book to

Romm.) Romm has commented, “Frankly, it

would be more literally accurate to rename

geoengineering ‘smoke and mirrors,’ as those

are two of the most widely discussed measures

for managing incoming solar radiation.”

Several years ago, when the geoengineer-

ing discussion was just gaining steam, Romm

commented, “We’re screwing up the planet

with unrestricted greenhouse gas emissions,

and the question is, do we want to try to fix

that problem by gambling on some other

large-scale effort to manipulate the climate—

or should we just try to restrict emissions? It’s

as if the doctor says you have a disease that

can definitely be cured by diet and exercise

but you opt for expensive chemotherapy even

though the doctor can’t guarantee the results

but is pretty certain the side effects would be

as bad as the disease.”

Former Vice President Al Gore is also op-

posed to geoengineering, although he endors-

es small-scale approaches such as white roofs

to reflect incoming solar radiation. But he

sneered at the larger-scale plans of technolo-

gists such as Keith and Salter. In a conference

call with reporters recently, as reported in the

Guardian newspaper, Gore said, “The most

discussed so-called geoengineering propos-

als—like putting sulfur dioxide in the atmo-

sphere to reflect incoming sunlight—that’s

just insane. Let’s just describe that clearly—

it is utterly mad.”

Gore is also cool to what some have

termed “soft geoengineering,” a planetwide

endeavor to build new nuclear power plants.

This is a course proposed by several leading

climate scientists, including the prominent

climate campaigner and former NASA sci-

entist James Hansen and National Center for

Atmospheric Research scientist Tom Wigley.

Gore told the conference call that he’d been

a staunch supporter of nuclear power when

he was in Congress, but is no longer optimis-

tic about expansion today. “I do believe that it

may be possible for scientists and researchers

to develop a better and more inherently safer

and cheaper form of nuclear reactor, which

may yet play a significant role in resolving

this crisis. It is not available now.”

Geoengineering advocates acknowledge

that nasty side effects could result from spray-

ing sulfur into the air or seawater into clouds.

In his Washington Post interview, Keith said,

“We can say what the technical risks are. Put-

ting sulfates in the stratosphere can accelerate

the depletion of ozone that comes from the

chlorine that we’ve already put up there from

CFCs. It could change atmospheric circula-

tion in ways that are hard to predict. . . . The

bigger risks have to do with misuse. People

often talk about using these technologies to

return temperatures to pre-industrial levels. If

you did that, that would be a dramatic climate

cooling, with bad consequences, like reduc-

ing precipitation a lot.”

Keith also takes on the moral question.

“Nothing plausible we do to reduce emis-

sions in the next, say, quarter-century is

going to materially reduce the risk for real

people, especially some of the poorest and

most vulnerable on our planet from climate

change. So yes, the potential moral hazard is

a major problem. But the fact that it’s a major

problem is hardly an argument for foregoing

a technology that might substantially reduce

risk for those living now.”

A Geoengineering Retrospective“Geoengineering” sounds like a new and

somewhat radical, frightening to some, ap-

proach to the potential problem of global

warming. But using technology, often at large

scale, to confront environmental and human

issues, is nothing new. Mankind has long

moved the environment to suit its needs.

Writing in the Bulletin of the Atomic Scien-

tists, biologist Robert Carlson says, “Humans

have a long history of modifying the living

systems they rely on. Forests in Europe and

North America have been felled for timber

and have regrown, while other large tracts of

land around the world have been completely

cleared for use in agriculture. The animals and

plants we humans eat on a regular basis have

been selected and bred over millennia to suit

the human palate and digestive tract. All these

crops and products are shipped and consumed

globally to satisfy burgeoning demand.”

In the field of power generation, it’s hard

to view big hydro as anything other than

terrestrial geoengineering. China’s Three

Gorges Dam spanning the Yangtze River is

the world’s largest generating station in terms

of capacity at 22 GW. As is the case of many

large dams (including those in the Tennessee

Valley Authority territory and along many of

the rivers of the U.S.), Three Gorges has mul-

tiple purposes, including power generation,

flood control, improved shipping, and pro-

viding irrigation water. According to the Car-

bon Planet website, the dam displaces some

31 million metric tons of coal annually.

The most audacious early approach to

geoengineering came in the 1960s and 1970s

from the U.S. Atomic Energy Commission’s

(AEC’s) Lawrence Livermore National Lab-

oratory. Legendary nuclear physicist Edward

Teller (the inspiration for Terry Southern’s

satirical movie Dr. Strangelove Or: How

I Learned to Stop Worrying and Love the

Bomb) concocted and ran a multibillion dol-

lar, multi-decade program, supported by the

U.S. Congress, to use hydrogen bombs to re-

arrange the landscape around the world. He

called it “Operation Plowshare.” Teller want-

ed to create a new port in Alaska, blast out

natural gas storage in Pennsylvania, and re-

route the Panama Canal. He ultimately failed,

as detailed in my 2012 book, Too Dumb to

Meter: Follies, Fiascoes, Dead Ends and

Duds on the U.S. Road to Atomic Energy.

It’s oddly ironic, but several of the promi-

nent advocates of modern geoengineering,

including Jane Long and Ken Caldeira, have

close ties to the Livermore lab, although well

after Teller exited the direct management of

the Department of Energy lab (as successor

to the AEC). Teller remained closely associ-

ated with Livermore until his death in 2003.

Caldeira was a Teller disciple, although Long

joined the laboratory staff after Teller died.

There is no direct connection to Teller’s ag-

gressive ideas about geoengineering and

those of Caldeira or Long, who is a senior

advisor to the Environmental Defense Fund.

What’s Next in Geoengineering?In addition to the “smoke and mirrors” (par-

ticulates and clouds) approach to geoengi-

2. Point counter point. Clive Hamilton

(left) of Australia’s Charles Sturt University

argued against geoengineering while David

Keith of Harvard spoke in favor of it during an

October 2013 event. Courtesy: Harvard Public

Affairs and Communications



neering, technologists are looking to move

beyond preventing sunlight from penetrating

the atmosphere and warming the climate. Call

it “that giant sucking sound,” or direct carbon

capture from the atmosphere. In 2007, flam-

boyant British entrepreneur Richard Branson

put $25 million into a competition for “an en-

vironmentally sustainable and economically

viable way to remove greenhouse gases from

the atmosphere.” The idea is not to capture

carbon before it is emitted, but after.

One of the 11 finalists for the “Virgin Earth

Challenge,” is Carbon Engineering in Calgary,

Alberta, Canada. David Keith is the president

of the company. Keith comments, “We hope

this technology will make it cheaper to reduce

carbon emissions from parts of the transpor-

tation infrastructure such as aircraft that are

otherwise hard to decarbonize, and we see

ourselves competing with other ways to ac-

complish this goal, such as biofuels.”

The company describes its process as fol-

lows: “Our capture technology brings atmo-

spheric air containing CO2 into contact with a

chemical solution that naturally absorbs CO2,

in a device called a contactor. This solution,

now containing the captured CO2, is sent to a

regeneration cycle that simultaneously extracts

the CO2 while regenerating the original chemi-

cal solution, for re-use in the contactor. The ex-

tracted CO2 is combined with all the CO2 from

the system’s energy use and both are delivered

as a high-pressure pipeline-quality product.” (A

video of the company’s technology is available

at http://carbonengineering.com/).

In their Harvard debate, Hamilton sug-

gested that sucking carbon dioxide out of the

atmosphere could attract private investors,

which he implied would be a bad idea. He

noted that N. Murray Edwards, a Canadian

oil sands mogul, recently invested in Keith’s

Carbon Engineering. Hamilton argued that

private interests would pursue profits and

ignore the role of governments in guiding

climate policy.

Keith countered that there is nothing

sinister about the Edwards investment,

which is a matter of “hedging his bets” if

fossil fuels prove to be a bad investment. In

his book, Keith said he sees “a sharp dis-

tinction in the role of private enterprise in

solar geoengineering and carbon removal.

The development of solar geoengineering

should be as public and transparent as pos-

sible. The extraordinary global power of

these technologies means that they can-

not be effectively governed by the local

rules appropriate for more conventional

technology. I believe that private, for-

profit development (and patenting) of the

core technologies for solar geoengineering

should be strongly discouraged.”

But carbon removal is different, says

Keith. “Succeed or fail, the technology we

are developing in Carbon Engineering is a

contained industrial process with local risks

similar to other industrial or mineral pro-

cessing technology. Our job at Carbon Engi-

neering is to develop a technology but not to

decide how or if it’s used.”

The Great GambleIs there any last word in this burgeoning dis-

pute? Perhaps it comes from the legendary

scientist Freeman Dyson in his 1981 book

Disturbing the Universe.

“Science and technology, like all original

creations of the human spirit, are unpredict-

able. If we had a reliable way to label our toys

good and bad, it would be easy to regulate

technology wisely. But we can rarely see far

enough ahead to know which road leads to

damnation. Whoever concerns himself with

technology, either to push it forward or to

stop it, is gambling with human lives.” ■

—Kennedy Maize is a POWER contribut-ing editor and blogger.

Potential is limitless.An idea has no momentum until talented people start chasing it. It’s then that

one begins to glimpse what’s possible, and the future begins to take shape.

Today, we are thousands of people sharing ideas, dedicated to finding new

ways to meet the needs of an ever-demanding Power sector. Which is why,

when it comes to nuclear, natural gas, coal, renewables, hydroelectric and

electric delivery systems, more people are turning to us to get it done.

We are URS.

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Blurring the Line Between Temporary and Permanent PowerTemporary power may be the most widely distributed “distributed” generation

worldwide, and its distribution is spreading, thanks to its ability to quickly meet urgent needs not only for event, construction, and post-disaster emer-gency power but also for fast-growing economies and stressed grids. That’s making it a serious competitor for “permanent” power in some situations.

Gail Reitenbach, PhD

When “temporary power” supplies

nearly a quarter of a grid’s demand,

is it still temporary power? How

about when a project lasts 10 years?

Those questions were prompted by an an-

nouncement on Mar. 31 that temporary power

provider Aggreko was increasing its grid-

connected generation capacity on Bali to 170

MW—representing 23% of the island prov-

ince’s total electricity demand. The appeal of

power rental in Bali is directly connected to

an economy that is growing at roughly 9.75%

per year, according to Scotland-based Ag-

greko, which has been in business for more

than 50 years.

As for the 10-year-long project, that was a

Cummins contract at a gold mine in Bulghah,

Saudi Arabia, located hundreds of miles from

the country’s electrical grid, that produced

82,000 ounces of gold per year using what

Cummins calls its “Prime Power System.”

The project was particularly challenging,

Cummins General Manager for Rental Proj-

ects Rick Duncan said, due to the environ-

mental challenges associated with ambient

temperatures of 55C (131F) and excessive

dust levels.

APR Energy Chief Operating Officer Brian

Rich directly addressed the shifting focus of

the major players in this sector when he com-

mented, “We view many of our plants to be

semi-permanent in that they can integrate

seamlessly into existing permanent infra-

structure (Figure 1), using the same technol-

ogy [gas turbines], and run reliably for many

years if needed, just as permanent infrastruc-

ture would. Many of our customers are run-

ning our plants as a baseload operation, where

we are supplying a significant portion of the

country’s electricity and providing power to

millions of people.”

A somewhat newer but ambitious player,

10-year-old Saudi Arabia–based Altaaqa,

explained that its business, too, is respond-

ing to the “continuously increasing” gap be-

tween supply and demand, especially in light

of significant economic development in spe-

cific regions. “This increase in demand that

sometimes cannot be catered for by the avail-

able grid is causing temporary power solu-

tions to have longer timeframes, and the term

‘temporary’ can sometimes extend to several

months or even years,” said Andrew Keddis,

business development manager.

Defining “Temporary”Calling power service temporary doesn’t

quite capture all of its distinguishing attri-

butes. It’s temporary rather than permanent,

rented rather than owned, and mobile rather

than fixed. It’s also modular and easily scal-

able. Ask some of the major companies

in the power rental space how they define

temporary power, and some even shy away

from that term because their projects run six

months or longer and range up to 450 MW

in size.

APR Energy’s Rich explained, “When

we think of ‘temporary’ power, we think of

short-term rental contracts, typically of a year

duration or less, including event power. APR

Energy has removed ‘temporary power’ from

our vernacular. Rather than focus on short-

term rental projects, we instead work to de-

velop long-term, larger-scale power projects

that bridge customers until their permanent

infrastructure is in place.”

Cummins’ Duncan told POWER, “In the

1. “Semi-permanent” power. APR Energy’s 200-MW mobile turbine plant in Uruguay

sits next to the permanent turbine plant of national utility UTE in Punta del Tigre. The utility had

a strong preference for dual-fuel gas turbines given its familiarity with the technology and the

country’s strict environmental regulations. It also needed a solution that would integrate into its

current site and infrastructure. Courtesy: APR Energy



past, temporary power mainly constituted

‘mobile’ power, which was required to be

made available quickly and for very short du-

ration. Today temporary power also includes

long-term requirements by utilities whose

capital constraints make investment in per-

manent sources of energy difficult.”

Renting vs. BuildingThere’s no question that when speed is of the

utmost importance, temporary power has the

edge even over relatively easy to site, permit,

and construct gas-fired peakers. In an inter-

view with Utilities-me.com last October,

Altaaqa Managing Director Steven Meyrick

noted that it took 23 days from contract to

plant commissioning at Aden, Yemen—re-

portedly the fastest installation of a temporary

power plant in Yemen. Another project—a

24-MW temporary peaking power plant in-

cluding district cooling for the Sultanate of

Oman—took four days to complete.

Even when new capacity isn’t needed

on very short notice, power rental offers an

advantage to utilities worldwide. Cummins’

Duncan noted: “Utilities typically lever-

age temporary power in a couple of differ-

ent ways. Many leverage temporary power

where they have a significant gap between

supply and demand, typically while they

are investing in expanding grid capacity or

to supplement existing capacity if they are

capital constrained. There are also utilities,

particularly in the Middle East, who leverage

temporary power to address seasonal shifts in

demand, effectively acting as additional ca-

pacity during peak periods.”

Compared with building new grid-con-

nected generation—even distributed solar or

wind generation—renting power (and, often,

distribution infrastructure) offers far faster

deployment. It also eliminates maintenance

headaches. As Keddis noted, even when grid

power isn’t an option over a longer term,

customers may opt to continue renting rather

than purchasing the power supply because

they can count on a specialized provider to

handle operation and maintenance.

Venkie Shantaram, Aggreko’s group busi-

ness development director, also noted that

global mobile power providers are selling not

just power but also reliable operation: “One

day a generator can be found at a cement

factory in the United Arab Emirates having

to withstand 50C-plus heat, and the next the

same generator is providing power to a gas

production plant in Russia’s Arctic region,”

so providing consistently reliable power de-

spite the environment is critical.

But what about costs of power compared

with power from traditional fossil plants? As

with permanent generation sources, costs vary

not only by country and region but also in re-

sponse to fuel costs, regulatory environment,

size of installation, and other factors. But, ac-

cording to GE’s Dan Kempf, general manager,

LM2500 and Small GT Program, as with all

onsite generation, line losses, up to 5%, are

saved, so “[t]his can result in the temporary

power units having a higher overall efficiency

than centralized/remote power generation.”

And in many cases, cost comparison is

moot, because, as Shantaram noted: “The

consequences of power interruptions for

utility-related companies responsible for the

timely delivery of electricity could run into

millions of dollars’ worth of penalties in a

very short amount of time, with no respite

until the disruption is fixed. At the end of the

day, our customers’ main concern is having

access to guaranteed reliable power so that

they can get on with the task at hand, be that

repair of onsite permanent equipment, refur-

bishment, replacement, or new builds.”

An Expanding MarketAccording to an April power rental mar-

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ket research report by MarketsandMarkets

(M&M), the global power rental market is

expected to grow from “an estimated $7.8

billion in 2012 to $17 billion in 2017 with a

compound annual growth rate of 17% during

the same period.” Global power rental market

revenue—generator rental plus revenue from

the temporary power plant—was estimated

at $6.4 billion in 2011. Roughly half of that

revenue derives from peak load installations,

with prime load and standby service making

up the other half.

To put those numbers in perspective, Ag-

greko, the largest player in the market, says

that in 2013 it served customers in about 100

countries and had revenues of approximately

$2.5 billion.

There’s good reason to be skeptical of

market report figures, in part because, as Al-

taaqa’s Keddis noted, the barriers to entry in

this industry “are fairly low,” especially for

local, small-scale generation rental. “Also,

this business is very dynamic with high

transaction rate. The combination of these

factors, in addition to the lack of transpar-

ency in many countries, makes the industry

extremely difficult to track and size.”

And, as Cummins’ Duncan noted, the size

and location of the market varies from year

to year. He said market studies he’s seen es-

timate that the temporary power opportunity

is in the region of $5 billion globally; this

can vary significantly by year, with large op-

portunity existing in North America, Europe,

Middle East, Africa, and Asia Pacific. When

looking at market opportunity, it is important

to distinguish between local hire (short-term

rental) and power project markets (longer-

term rental) because the market drivers, ap-

plications, and geographical presence are

significantly different, he added.

The most familiar uses of temporary power

are for construction sites, events, disaster re-

covery, off-grid mining operations, and the

like. But utilities are also major customers.

These days, according to Aggreko, the larg-

est provider of temporary power, aging in-

frastructure, grid instability, seasonal peak

shaving, transmission and distribution limita-

tions, planned maintenance, weather events,

and unplanned outages are all driving the mar-

ket. (See “Shifting Sands: The Middle East’s

Thrust for Sustainability” in this issue.)

The M&M report found that the utility

sector is the largest user of temporary power,

followed by the oil and gas industry and the

industrial sector. Utilities and the event in-

dustry are the fastest growing markets.

Geographically, according to M&M, the

largest markets are, in order: North America,

Middle East, and Asia-Pacific. However, the

report also found that the Middle East is the

fastest growing market.

At country level, the report finds that

the U.S. accounts for the largest revenue

share, followed by China, India, and Can-

ada. That list shouldn’t surprise anyone, as

it includes the two largest industrializing

nations and the two countries experiencing

unprecedented shale resource exploration

and development. In fact, just last year, Ag-

greko opened new service centers in Sas-

katchewan and Texas to be closer to its oil

and gas mining customers.

And although temporary power is the prima-

ry focus here, some firms also offer related ser-

vices, such as cooling and heating equipment,

compressors, heat exchangers, and remote

monitoring—markets that are also growing.

Changing Project ProfilesTemporary power has long been a staple in

the global resource development industry,

and that remains the case. But at least for the

market leaders, both the sizes and types of

projects have expanded recently.

Size. One of the biggest changes in the

industry over the past decade or two is the

scale of installations. Previously, GE’s

Kempf noted, they were small by necessity,

but “electricity has become more and more

critical to sustaining the modern way of life.

The world’s economy is electrifying and ur-

banizing, creating large potential demand for

temporary power on short notice.”

GE has handled projects in excess of 600

MW in a single order, with first power put to

the grid within 60 days, Kempf said.

APR Energy’s largest installation to date

was more than 450 MW across six sites in

Libya in summer 2013, but its largest single-

site installation was 200 MW in Uruguay,

part of an overall 300-MW project (see Fig-

ure 1). The plants installed as part of these

two projects are still in operation.

New Roles for Temporary Power. GE’s

Kempf identified two major trends his com-

pany is seeing that were not part of the busi-

ness just 10 or 20 years ago:

■ Emerging economies that are attempting

to electrify and are challenged to meet

near-term power needs and get ahead of

anticipated growth.

■ Rapid and unexpected needs driven by

natural disasters.

Another newer role that Cummins is heav-

ily involved in is providing prime power to

U.S. military bases in war zones like Iraq and

Afghanistan. Cummins’ largest installation

to date was at Victory Base Complex-East,

Iraq, a 74-MW Prime Power Plant. The proj-

ect consisted of a new 54-MW plant designed

and constructed by Berger/Cummins (a joint

venture between Cummins Power Generation

and The Louis Berger Group), an integrated

and previously existing 20-MW plant, an

electrical infrastructure upgrade consisting

of a new 100-MW bus/switchgear, 40-MW

substation, six new 11-kV overhead distribu-

tion feeders, and a fuel farm constructed to

supply the power plant.

According to Duncan, the plant resulted in

the removal of 103 spot generators, resulting

2. Cross-border power delivery. Aggreko’s 232-MW temporary power project on the

border of Mozambique and South Africa supplies power to both countries as well as Namibia.

Courtesy: Aggreko



in a savings of millions of dollars a year in

fuel and operation and maintenance expenses

for the U.S. military. At the time, this plant

was the U.S. military’s largest expeditionary

prime power plant serving a military base.

Like other global players in this market,

Cummins also provides temporary power

solutions to public utility companies where

projects are awarded for terms of three years

or more. “A couple of decades ago, custom-

ers relied more on ‘spot’ generation, which

involved placing small generators near a

place of power demand. This was quick and

easy, but resulted in fuel consumption inef-

ficiencies, lower reliability, and high cost of

equipment. The trend now is to have consoli-

dated ‘prime power plants,’ where a central

power plant is leveraged and power is sup-

plied through a distribution network. This

has resulted in high plant load factors, high

plant utility factors, and high reliability, driv-

ing down capital costs as well as operation

and maintenance costs.”

Keddis told POWER that in Saudi Arabia,

the type of power demand is driven by the

“change in socioeconomic trends and gov-

ernment spending. For example, we have

noticed a significant increase in Saudi Ara-

bia’s entertainment industry business that

we didn’t have few years ago. Furthermore,

new types of projects such as railway and

metro projects are starting in Saudi Arabia

and are using Altaaqa’s services; supplying

power to tunnel boring machines for metro

projects, for example, is a unique new expe-

rience for Altaaqa. Saudi Arabia is working

towards diversifying its economy from be-

ing heavily dependent on petroleum to other

sources of revenue such as mining, petro-

chemicals and other industries. That in turn

reflects on the diversity of projects requiring

power.”

Altaaqa is the official Caterpillar partner

for power rental and temporary power solu-

tions in Saudi Arabia, and all Altaaqa ser-

vices are provided by CAT diesel engines. Its

longest-running project is a 16-MW tempo-

rary power station supplying a mall in Jed-

dah, Saudi Arabia, that has been operating

for six years.

Another type of new playing field is the

multinational one. Aggreko is producing and

delivering cross-border power to three util-

ity companies in Southern Africa (Figure 2).

Shantaram explained that the 232-MW tem-

porary power site “uses natural gas from the

Temane gas fields as a fuel source and is lo-

cated on the Mozambique and South African

border at Ressano Garcia. The project is pro-

ducing and delivering power to Electricidade

de Mozambique (EDM), Eskom, and Nam-

Power (the Namibian power utility). This is

thought to be the first project by a private

company to supply power to multiple utilities

in Southern Africa, underlining the potential

benefits that can accrue to countries sharing

resources.”

Technology TrendsShantaram noted that Aggreko’s basic busi-

ness of “delivering flexible power solutions

anytime, anywhere” hasn’t changed much

over five decades, but the technology has.

“Today we have generators that range from

10 KW right up to 1 MW, and deliver our

solutions in stackable, 20-foot containers

for efficient transportation by road, rail,

ship, or plane.”

Diesel-powered internal combustion en-

gines have been the go-to technology in this

part of the generation world. However, gas

gensets and turbines are becoming much

more common.

APR’s Rich argued that one of the biggest

innovations in this sector has been the use of

mobile turbines: “Before 2011, utilities were

forced to use smaller-MW reciprocating en-

gine power modules because that was the

only feasible fast-track solution. As mobile

turbine technology has developed and be-

come available, utilities have turned to them

3 Turbine on wheels. GE’s trailer-mounted (TM) mobile gas turbine generators, includ-

ing the TM2500 shown here, supply power for 50-Hertz and 60-Hertz applications using essen-

tially the same technology as that used in “permanent” gas turbine power plants employing the

LM2500 turbine. Courtesy: GE Power & Water

Clean Diesel?

Diesel engines—whether in vehicles or

stationary power systems—have a reputa-

tion for dirty emissions. But when it comes

to the latest generation of technology,

that reputation is becoming outdated.

The Diesel Technology Forum (DTF), a

U.S. industry group formed in 2000 that

promotes the use of “clean diesel,” says

that today’s diesel generators “emit 26

times less particulate matter than those

manufactured 10 years ago.”

Diesel generators used for other than

emergency use are subject to a variety

of federal, state, and local regulations

in the U.S. and abroad. “In 2006, the

EPA finalized the first national emission

standards for new stationary diesel en-

gines under the New Source Performance

Standards (NSPS),” the DTF notes. “The

NSPS requires all new diesel engines to

be certified to emission standards that

generally follow EPA’s non-road or marine

mobile emissions standards which gener-

ally require over 90 percent reduction in

emissions of particulate matter and ni-

trogen oxide.”

The DTF notes that “[o]ver the 2011–

2015 period, EPA requirements will mean

that emissions for all non-emergency diesel

generators regardless of horsepower rating

will be approaching a near-zero level.”

It adds that, since October 2010, most

diesel fuel used in diesel-powered gen-

erators has been ultra-low-sulfur diesel

(ULSD) fuel (no more than 15 ppm sulfur).

Using ULSD in existing units reduces par-

ticulate matter emissions by 10% to 20%,

and when cleaner fuel is used in today’s

new technology lower-emissions engines,

the DTF says that particulate matter will

be reduced by 90% compared to engines

made before 2011.

“Clean diesel,” is appears, is more than

just a catchy slogan.



rapidly. . . . Since 2011, turbine share has

grown rapidly, from zero in 2010 to a 35%

share of the 100-MW+ deal space in 2013.

Approximately 20% of all fast-track power

deals since 2012 have been for gas turbines.

Utilities prefer the grid stability and power

density that turbines provide, and it is a tech-

nology that they understand.”

He also noted that the aeroderivative tur-

bine technology used in many APR plants is

the same technology used in many perma-

nent plants; “the only difference being that it

is mobile and can be moved if needed.”

Another advantage of mobile gas turbines

Rich mentioned is that they are “opening

doors to new markets and opportunities in

developed countries, where emissions and

scale are of importance.”

In fact, in October 2013, APR Energy an-

nounced it had agreed to acquire GE’s power

rental business, which will tie it even more

closely with gas turbine technology. Today,

APR Energy’s fleet is about 55% mobile

gas turbines and 45% gas or diesel power

modules—primarily GE and Caterpillar

equipment, as the company currently has a

strategic alliance with GE and a global agree-

ment with Caterpillar.

Even non-utilities are turning to gas tur-

bines. In September 2005, when Hurricane

Rita flooded and caused the shutdown of

the Valero Energy Corp. refinery in Port

Arthur, Texas, and when utility power was

unavailable, Valero looked for a quick yet

simple option. GE’s Aeroderivative Gas Tur-

bine business provided the refinery with a

TM2500 gas turbine (Figure 3), a blackstart

diesel generator, and an automatic transfer

switch. The 22.5 MW supplied was, accord-

ing to a GE press release, “more powerful

and much less sprawling than a cumbersome

string of diesel generator sets.” Six days after

Valero signed the temporary power contract,

the unit was fully installed and delivered aux-

iliary power for three months until the utility

could resume supplying permanent power.

Typically, Kempf said, units can be ready

to enter commercial operation in about 30

days. GE has also supplied its trailer-mount-

ed, mobile aeroderivative gas turbines in

other countries. For example, two of the four

dual-fuel (gas and diesel) TM2500+ units

involved in a $135 million project for Gen-

eral Electricity Co. of Libya were installed

and commissioned within six weeks after site

selection in December 2013. The project will

provide more than 100 MW for the summer

peak by expanding the Zawia and W. Trip-

oli power plants. GE notes that the mobile

units can be moved anywhere in the country

to supply emergency backup power or as a

“base-load bridge to permanent power instal-

lations.” The TM2500+ can produce more

than 26 MW of power—a 31% increase over

the TM2500, GE says.

GE also offers gas engines from 300 kW

to 10 MW. Kempf said, “A containerized gas

engine solution, for fast installation/reloca-

tion, can be supplied up to 4.4 MW and with

efficiencies up to 46%.”

Whatever the prime mover, squeezing

maximum efficiency out of the technol-

ogy is key. Aggreko, which manufactures

its own equipment, last year launched the

G3+, a 1-MW engine that the company

says provides customers with up to 14%

more power and 12% lower cost per MW

than previous models. Aggreko says it be-

lieves its G3+ reciprocating engine is the

most efficient engine on the market “and

provides fuel efficiencies surpassing that

of mobile turbine technology.”

Fuel OptionsBecause it is available almost everywhere,

diesel has been the traditional fuel of choice

for temporary power (see sidebar). However,

it’s not the most cost-effective, so the global

players are adding alternatives.

“We were the first company to develop and

produce in volume 1-MW gas-fired genera-

tors in 20-foot containers, and we now have

over 900 MW on rent in our Power Projects

business—far ahead of any competitor,” said

Shantaram. In the second half of 2013, gas-fu-

eled plants generated 35% of Aggreko’s Pow-

er Projects rental revenue, “having grown at a

compound growth rate of over 55% between

2007 and 2013. Utilities using our gas tech-

nology are enjoying all-in costs per kilowatt-

hour from our plants, which is often cheaper

than some of their permanent capacity, and far

below diesel-fueled power plants.”

Aggreko has been investing heavily in the

development of temporary power generation

that can use natural gas and heavy fuel oil

(HFO). In 2010, Aggreko began looking for

a fuel that was cheaper than diesel but more

easily available than gas. “The answer was

HFO, which is widely used for both power

generation and shipping, Shantaram said.

“We overcame some significant engineer-

ing challenges to develop an engine capable

not only of running off HFO, but of doing

so inside a 20-foot container, and launched

our new product in March of 2013. Customer

reaction has been very favorable, as we are

able to save them millions of dollars in fuel

cost—we believe that this product will be-

come a very important part of our portfolio

over the next five years.”

Cummins has also delivered natural gas

and biogas turnkey power plants for dedi-

cated installations. The company has seen

increased demand for gaseous fuels over the

past five years, particularly natural gas and

biogas. As Duncan noted: “Two factors influ-

ence the viability of this as an option; firstly,

there has to be a reliable source of fuel avail-

able locally, either via pipeline or through lo-

cal production. Secondly, the contract length

has to be long enough to justify any addi-

tional infrastructure investments required to

support these fuels.”

“There may be long-term potential in

dual-fuel technology,” he said, “which could

allow operators to minimize operating costs

by changing fuel substitution rates to most

effectively respond to fuel price economics.

4. Powering growth. This photo shows Altaaqa’s largest single temporary power plant,

95 MW, being installed in May 2014 in Al-Kharj, Saudi Arabia. Courtesy: Altaaqa



Currently, up-front technology choices are

significantly influenced by capital cost, and

the economic viability of these options often

mean that substitution rates are constrained,

limiting potential fuel saving upside.”

APR Energy has plants running on both

natural gas and diesel fuel. Rich said cus-

tomers choose and provide the fuel. As APR

Energy’s mobile turbines are dual fuel, “they

can operate on either diesel or natural gas

with the ability to change at the flip of a

switch. We also offer power modules that use

either diesel or gas.”

“Fuel is the most expensive part of the

kilowatt-hour,” Rich added. “So fuel effi-

ciency improvement is the main focus. The

flexibility to operate with dual fuel is vital,

and in this market only the turbine can de-

liver that ability.”

Both Supporting and Competing with Grid PowerEstimating what percentage or capacity of

temporary power is grid-tied generation for

traditional utilities is difficult because of the

temporary nature of the market and because

plant deployments can change overnight.

However, it’s clear that—especially in re-

gions with fast demand growth or unreliable

infrastructure or fuel supply—temporary

power can be an important utility partner.

One example is Uruguay, where the elec-

tricity sector is largely based on domestic

hydropower, leaving the country vulnerable

to seasonal rainfall patterns. To help bridge

the gap between supply and demand, APR

Energy supplies a total of 300 MW of mo-

bile turbine power for peaking and backup

generation. The semi-permanent plants (see

Figure 1) integrate seamlessly into national

utility UTE’s existing infrastructure and uti-

lize demineralized water solutions to com-

ply fully with Uruguay’s strict emissions

standards.

Another is Saudi Arabia, where demand

increases significantly in the summer, “it

becomes very difficult for the grid to cope

with that change,” explained Keddis. “On

an annual basis, Altaaqa re-enforces the

Saudi Arabian grid during the high season

with an average of 250 MW to 300 MW

in different parts of the country.” In fact,

its largest project to date at a single site,

currently under development, is 95 MW in

Al-Kharj, Saudi Arabia, for Saudi Electric

Co. (Figure 4).

And in May, Aggreko announced that it is

providing 30 MW of power to a hydro site

located 3,423 meters above sea level. That

project will provide continuous power to the

Santa Teresa Hydroelectric site, located in

the Cusco region 715 miles from Lima, Peru

(Figure 5). High altitudes affect generators

by reducing their output. According to Ag-

greko, the derating typically results in a pro-

duction loss of 10% for every 1,000 meters

of altitude. Aggreko says its engines provide

a minimum reduction of power at 3,400 me-

ters, with just 10% loss, according to a com-

pany press release. Aggreko says it mobilized

the equipment in just five days, using trailers

specially designed for loads of up to 26 tons.

Another factor behind the growth in the

power rental market that Cummins’ Duncan

mentioned is growing interest in microgrids

to meet temporary (and more permanent)

power needs. A microgrid consisting of

multiple distributed energy resources feed-

ing single or multiple electrical loads, and

operating as an autonomous/island grid can

provide its operator with the flexibility to

leverage different technologies with com-

plimentary characteristics. “One example

is using solar power with diesel generators,

providing the fuel savings and emission

benefits associated with renewable energy,

but addressing the challenges of intermit-

tency and energy density by leveraging the

reliability and power density associated

with diesel generators.”

Depending on who is contracting for the

microgrid, this scenario could either sup-

port a utility or steal potential load growth

from it.

Surmountable ChallengesAs in the permanent power world, regula-

tory issues were the most frequently men-

tioned challenge. Aggreko’s Shantaram

noted that even though the company’s ex-

pertise is in working across borders, “chal-

lenges can present themselves when having

to adapt to local regulations or require-

ments that differ from country to country.”

However, with “over 50 years’ experience

working in almost every country and in

every industry . . . we can obtain permits

whether it be in Mozambique, Romania,

USA, or Brazil.”

APR’s Rich noted that “The nature of to-

day’s market is that our contracts are often in

developing countries, which typically makes

them challenging from the start, particularly

in terms of logistics, labor, and security.”

GE’s Kempf pointed out that in “bridg-

ing” solutions, the time required for power

purchase agreement negotiation in many

regions can create challenges to rapid de-

ployment. “Fuel handling, transportation,

and other issues can also present chal-

lenges at times, but solutions are almost

always available.”

Then there’s weather. Temporary power

is often the only option in remote areas, and

those areas are often “remote” for obvious

reasons of climate or terrain. Temperature

extremes and poor or absent infrastructure

present challenges for logistics and opera-

tion. Luckily, temporary power plants are

mobile and modular, so any damaged equip-

ment can be replaced quickly. ■

—Gail Reitenbach, PhD is POWER’s editor (@GailReit, @POWERmagazine).

5. Supporting hydro. A 30-MW project for a hydro site in Peru, shown here during de-

livery, was mobilized in five days using trailers specially designed for loads of up to 26 tons.

Courtesy: Aggreko



Springerville Generating Station Earns PRBCUG 2014 Honors The Springerville Generating Station has been a work in progress since the first

unit entered service in 1985. The PRBCUG recently recognized Springerville with its 2014 Plant of the Year award for implementing industry best practices, continual improvements, and worker safety.

By Dr. Robert Peltier, PE

The presentation of the Powder River

Basin Coal Users’ Group (PRBCUG)

Plant of the Year award is always the

highlight of the PRBCUG Awards Banquet,

held the night before the kickoff of the Annu-

al Meeting held in conjunction with ELEC-

TRIC POWER Conference & Exhibition.

Each year, since 2000, the PRBCUG has

recognized one to two power plants for their

innovation and the implementation of “best

practices and continual improvements in ar-

eas including safety, environmental perfor-

mance, coal handling, boiler and combustion,

and risk management” for Powder River Ba-

sin coal (see sidebar). The selection is made

after an extensive review by the PRBCUG

Board of Directors. Membership of the PRB-

CUG is composed of users of PRB coals as

well as prospective consumers (generating

companies or industrial energy consumers).

This year, the PRBCUG 2014 Plant of the

Year was awarded to the Springerville Gen-

erating Station (SGS). SGS, located in the

high desert of northeastern Arizona near the

border with New Mexico, consists of four

units with different owners but a single op-

erator, Tucson Electric Power (TEP), a sub-

sidiary of UniSource Energy Corp. Units 1

and 2 are sister units, each 380 MW. Unit

1, owned by a consortium led by TEP, and

Unit 2, owned by TEP, were constructed in

1985 and 1990, respectively. Unit 3, rated at

417 MW, is owned by Tri-State Generation

and Transmission and entered commercial

service in the summer of 2006. Unit 3 is a

prior recipient of POWER’s Plant of the Year

award (see “Tri-State Generation and Trans-

mission Association’s Springerville Unit 3

Earns POWER’s Highest Honor” in the Sep-

tember 2006 issue). Tri-State is a Denver-

based wholesale power cooperative with

member distribution systems in Colorado,

New Mexico, Wyoming, and Nebraska. Unit

4, also 417 MW, was completed in Decem-

ber 2009 and is owned by Salt River Project,

which is the third-largest public power utility

in the U.S. (Figure 1).

All four units at SGS operate with an

excellent heat rate under 10,000 Btu/kWh,

and the plant’s 2013 net capacity factor was

80.3%, which ranks it as one of the best of

its class, according to PRBCUG. The plant

burns about 7 million tons/year of coal of

which 3.7 million tons is PRB coal burned

in Units 3 and 4. Units 1 and 2 burn coal

sourced from the El Segundo Mine in north-

west New Mexico. Coal is delivered by unit

train and unloaded with a rotary car dump.

The plant maintains seven separate coal piles

and uses 51 conveyors to stack, reclaim, and

move coal to each of the four units (Figure

2). Magnetic metals separation is also a re-

cent addition (Figure 3).

The plant has 350 employees, including

about 130 multi-skilled operators who are

also trained to perform non-intrusive preven-

tative maintenance (PM) evolutions that will

take less than two hours (about 27% of all

PM). SGS is very selective when it comes to

new employees. New operators are hired from

one of three sources: those completing a two-

year training program, those with experience

at other plants, or those with military expe-

rience. The plant also employs 120 contract

employees, of which about 90 are employees

of Southwest Energy Solutions, a TEP sister

company. This team is responsible for plant

housekeeping, ash handling, and mobile fleet

operation and maintenance activities.

Recent AccomplishmentsThe coal unloading and transfer system is, for

outage planning purposes, treated as a virtual

“Unit 5,” and is scheduled for an annual out-

age lasting between four and 14 days. This

approach allows SGS to plan, procure, and ex-

ecute coal handling upgrades at predictable pe-

riods of time each year rather than piecemeal.

Over the past few years, a number of upgrades

have been completed that have significantly

improved coal-processing operations:

■ Revised operation procedures reduced

equipment wear and tear as well as subse-

quent housekeeping chores. The contractu-

ally required train-unloading rate is six to

Benchmark Your PRBCUG Plant Against Industry Peers

The Powder River Basin Coal Users’ Group

(PRBCUG) was formed to “promote the

safe, efficient, and economic use of Pow-

der River Basin coal by generating compa-

nies that currently use, or are considering

the use of sub-bituminous coal.” One of

the objectives of the group is to identify

and establish industry best practices re-

lated to safe and efficient handling, burn-

ing, and using PRB coals.

Membership in the PRBCUG and attend-

ing the annual conference offers PRB coal

users the opportunity to network with

industry peers, learn from other operat-

ing plants, obtain access to industry best

practice guidelines, and increase safety

and risk awareness.

Every plant that burns PRB coal will

benefit to some degree from the insight-

ful case studies on successful deployment

of the right technology and industry best

practices presented at the PRBCUG annual

conference. Not every solution is appropri-

ate for every plant, but there is one best

solution for your particular “challenge.”

And where better would you find peers to

compare notes than with members of the

PRBCUG? Additional information on the

PRBCUG and its awards program is avail-

able at www.prbcoals.com.



eight hours, but some operators would speed up feeders and conveyors

such that a train was being unloaded in significantly less time. Fast

is good, but only up to a point. Rapid unloading caused a significant

increase in wear and tear on the equipment and increased fugitive

emissions that overpowered the surfactant spray system, in addition to

causing coal spills that required an additional six hours of cleanup. A

simple operational change to limit the unloading feeder speed reduced

coal-handling system operating and maintenance costs.

■ Installation of wireless vibration monitoring on all large electrical

motors is expected to minimize unexpected catastrophic failures.

■ Standardized guarding around coal-handling equipment, convey-

ors, idlers, and tail pulleys were designed and installed. All the

conveyor belts were also standardized. Also, water drain lines on

the tripper decks and conveyors were increased in size to improve

water removal as part of housekeeping. Cleaning these areas was

problematic because water would not drain properly through too-

small drains or those with too many bends. The end result was that

housekeeping time for this task was reduced by 50%.

■ The housekeeping staff has been integrated into the safety culture

of the plant. The 10 or so members of the housekeeping staff on

duty at any time observe much of the plant everyday and report

safety and maintenance problems as part of their work responsi-

bilities. In addition, housekeeping staff are now assigned to a spe-

cific area of responsibility for two months rather than routinely

rotated. The result is workers taking ownership of a particular area

and better-maintained areas. One of the PRBCUG directors noted

in his trip report that “the team that maintains the tripper gallery

takes great pride in maintaining its cleanliness. I saw no coal dust

on the walls nor on any exposed structural steel.”

■ An Engart dust extractor replaced two existing baghouse dust collec-

tion systems to improve safety, lower maintenance, and provide bet-

ter dust collection efficiency. Winds that often exceed 60 mph at the

site have necessitated other process improvements, such as adding

dust suppression spray nozzles. Site drainage to the periphery of the

coal storage areas was also added. In addition, F500 extinguishers

were added around the entire coal storage area with training on how

to use the extinguishers scheduled every six months.

1. High desert operation. The Springerville Generating Station

is located in northeastern Arizona, close to the border of New Mexico,

at an elevation of 7,000 feet. The net power generation of the plant’s

four units is about 1,600 MW. Units 3 and 4 share a common stack.

Courtesy: Salt River Project, photograph by Matthew Ideler

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2014



■ Permanent vacuum lines were installed for

areas that require routine cleanup. Also,

LED lights were installed in many work

areas. If you can’t see it, you can’t clean it.

■ SGS is located in the high desert—7,000

feet high. Winter temperatures are often

below freezing, but many portions of the

plant building were not designed to keep

the heat in and the coal dust out. Portable

heaters now keep unheated buildings above

freezing and many conventional external

doors, dangerous to open in high winds,

have been replaced with sliding doors (de-

signed with emergency escape features)

that meet the life safety code. Elevated

grating was also installed throughout the

plant to improve traction when walking,

particularly in conveyor areas.

Safety Is ValuedThe plant’s incident and severity rates (cur-

rently 1.5 and 0, respectively) are historically

well below the industry average and may also

be considered as best in class, according to

the PRBCUG. The plant’s safety organiza-

tion each year selects a volunteer to be the

plant’s “Safety Rover.” The Rover’s role is to

spend the day where work is being performed

in order to be a resource to workers in identi-

fying and addressing potential hazards.

An employee-based safety program has

been rolled out to workforce to encourage

routine safety observations with immediate

feedback to fellow employees. The Southwest

Energy Solutions branch of SGS has achieved

over 75% employee participation since 2012,

while the TEP workforce implemented the

program in January 2014. The observations

are used to develop future safety education

programs, improve job hazard analysis, and

expand overall awareness of safety among

the plant staff. Employees complete a job

hazard analysis for each job prior to perform-

ing it. Signs are posted throughout the plant

reminding employees that everyone has the

authority, including contractors and visitors,

to call a “Safety Time Out” when an unsafe

work situation or act is observed.

The plant’s remote location requires self-

protecting emergency preparedness and

equipment. SGS houses onsite a stand-alone

communication system (trailer), industrial

fire brigade (advanced exterior and interior),

and EMTs and two paramedics. The plant

is equipped with trained personnel for fire,

emergency medical, technical rescue, and

hazardous materials, including specialized

equipment and apparatus, all housed in an

11,000-square-foot building. Emergency

Response Plans are in place, and drills are

conducted regularly. A modern enhanced

emergency notification system is intercon-

nected to the plant’s GAI-Tronics system and

communicates through four large speakers

strategically placed around the facility. The

emergency responders are embedded within

the workforce 24 hours per day.

Sustained, Superior PerformanceCongratulation to the Springerville Generat-

ing Station for being named the 2014 PRB-

CUG Plant of the Year. The award recognizes

years of hard work by the plant staff and

major capital investment by the plant own-

ers to improve the performance and safety of

the plant’s operations and maintenance. I’m

told the Fuels Group set an internal goal to be

named the PRBCUG Plant of the Year over

two years ago—and reach that goal they did.

The plant staff has demonstrated that rela-

tively small, incremental improvements over

time will pay huge dividends. Congratula-

tions from POWER for a job well done. ■

—Dr. Robert Peltier, PE is POWER’s consulting editor.

2. Automatic car unloading. A unit

train entering the rotary car dumper build-

ing is shown. The coal is then conveyed and

stored on one of the seven coal piles present

at the plant. Units 1 and 2 burn coal produced

by the El Segundo Mine in northwest New

Mexico. Units 3 and 4 burn PRB coal, so there

are separate coal storage piles for each coal.

Courtesy: Salt River Project, photograph by

Matthew Ideler

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3. Separating metals. A new magnetic

separator system was recently installed to

monitor the two 72-inch conveyor belts. This

system traps any metals early in the handling

system to prevent damage to equipment and

ignition of fires. Courtesy: Salt River Project


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COAL

Does IGCC Have a Future?Once touted as the savior of coal power and the future of clean coal generation, in-

tegrated gasification combined cycle (IGCC) technology has seen its prospects swamped by soaring costs and technological challenges. Though it remains controversial, its proponents are not ready to give up.

Thomas W. Overton, JD

If you’re an energy sector observer with an

interest in integrated gasification combined

cycle (IGCC) generation, the last few years

have been much like attending a performance

of Samuel Beckett’s classic play, Waiting for

Godot, in which the performers spend two

acts tediously waiting for someone who never

appears. And, much like Beckett’s characters,

who are never quite sure if they’re waiting in

the right place or are unknowingly repeating

the same scene each day, the generators work-

ing on IGCC have been struggling for years to

find a viable path forward.

The newest operating IGCC plant in the

U.S., Duke Energy’s Edwardsport Generating

Station in Indiana, has struggled to maintain

consistent operations since coming online last

June (though it was still named a POWER Top

Plant for 2013). Duke stated at the time that

it planned to slowly ramp the plant up to full

operation, and in that at least, it has fulfilled

expectations. It reached 60% capacity in Au-

gust, only to suffer mechanical failures this

past winter that reduced output to a trickle

in January and February. Duke said things

improved later in the spring, but CEO Lynn

Good acknowledged in the company’s first-

quarter earnings call, “Edwardsport is a large,

complex project, and it has taken time to work

out technical issues.”

Ballooning BudgetsEdwardsport reached commercial operations

two years late and about $1.5 billion over bud-

get, but that record fairly shines in compari-

son to Mississippi Power’s Kemper County

project, which will be the first to incorporate

carbon capture and storage (CCS) technology

(Edwardsport is “CCS-ready” but does not

have it installed). The Kemper County plant

has seen costs spiral from an initial estimate

of $2.2 billion to more than $5.5 billion in

the most recent revision in April. That update

again pushed out the plant’s in-service date

to May 2015, a year beyond the original plan.

Missouri Power’s parent, Southern Com-

pany, blamed early miscalculations on the

type and amount of piping needed for many

of the problems. With the state having set a

cost cap of $3.87 billion, the overruns have

cost Southern about $1.6 billion.

None of this has stopped the U.S. Depart-

ment of Energy (DOE) and the Environmen-

tal Protection Agency from touting IGCC

with CCS as the future of coal generation.

“I consider seeing this plant a look at the

future,” DOE Secretary Ernest Moniz said

at an event at Kemper County last Novem-

ber. “We’re going to need not 10, maybe 100

more of these plants across the country.”

Yet only two other such plants are under

active development in the U.S., the Texas

Clean Energy Project (TCEP), near Odessa,

and Hydrogen Energy California, planned

for a site near Bakersfield; both are still in

search of financing despite years of work

(see “Is Polygeneration the Future for Clean

Coal?” in the March 2014 issue). Most re-

cently, in April, developer Summit Power re-

quested yet another extension from the DOE,

with financial closing now hoped for in June

2015. Director of Projects Laura Miller said

the company’s goal between now and then is

to cut “hundreds of millions” of dollars from

the current $3.5 billion estimate.

These numbers are naturally a deterrent

to future investment. Jeff Phillips, manager

of the Electric Power Research Institute’s

(EPRI’s) Advanced Fossil, Carbon Capture,

Utilization and Storage research program,

told POWER, “The combination of the sub-

stantial cost overruns at the two U.S. IGCC

projects built this decade and relatively low

natural gas prices present in North America

has dried up interest in IGCC among U.S.

power producers.”

Mixed RecordOverseas, the picture is more nuanced.

According to the Gasification Technolo-

gies Council (GTC) database, there are only

six commercially operating coal-fired IGCC

plants worldwide, including Edwardsport. Of

those, four came online in the 1990s and one,

at Nakoso, Japan, in 2007 (Figure 1).

A seventh plant, China’s GreenGen project

in Tianjin, has mostly completed the second

phase of its development in which the first,

250-MW unit has been successfully fired on

syngas, though it is not yet fully commis-

sioned. A second, 400-MW plant is under

development on the same site.

Worldwide, according to DOE and GTC

data, about a dozen coal-fired IGCC projects

are in various stages of active development,

though the commercial prospects for several

of these are doubtful. About five or six ap-

pear to be under construction, though reports

conflict. Nearly all of them seem to have ex-

perienced varying degrees of cost overruns,

delays, and doubts about their viability.

GreenGen, for example, was originally

planned for full operation in 2015, but com-

pletion has now been pushed out to 2020. The

cost overruns for the project are not publicly

known, but reports suggest they have been

substantial. (The developer, Huaneng Group,

is a state-owned firm.)

There are success stories, however. Mit-

subishi Heavy Industries’ thermal power di-

vision (now part of Mitsubishi Hitachi Power

Systems, MHPS) began developing the 250-

MW IGCC demonstration plant at Nakoso in

Fukushima Prefecture in the early 2000s, and

brought it online in late 2007 (when it was

named a POWER Top Plant). The plant uses a

single MHPS 701DA turbine that burns syn-

gas from an air-blown gasifier. It operates at

42% net efficiency and has achieved very low

SOx and NOx emissions of 1.0 ppm and 3.4

ppm, respectively.

MHPS is actively marketing its IGCC

technology and believes that efficiencies

over 48% are achievable with its advanced

G-series gas turbines operating at higher inlet

temperatures. Despite the high costs experi-

enced with current IGCC projects in the U.S.,

1. Trailblazer. The 250-MW IGCC dem-

onstration plant at Nakoso, Japan, owned by

Mitsubishi-Hitachi Power Systems, has been

operating successfully since 2007. Courtesy:

MHPS


COAL

MHPS believes such plants can be competi-

tive with conventional coal generation.

According to Terry Fujino, project coordina-

tor and manager, boiler and IGCC engineering,

for MHPS, the Nakoso plant has met and ex-

ceeded all performance guarantees and targets

since it began initial operation. In April 2013,

it was transferred to commercial operation and

renamed as Unit 10 of Nakoso Power Station.

Based on the results at Nakoso, Tokyo Elec-

tric Power Co. has announced plans to build

two new coal-fired IGCC plants in Fukushima

Prefecture with outputs of approximately 500

MW each, using the same air-blown MHPS

gasification technology as the Nakoso plant.

Room for ProgressOne thing on which there is agreement is

that IGCC is a technology with a lot of ef-

ficiencies and improvements remaining to

be captured. A 2012 report from EPRI lists a

number of areas in which IGCC plants can be

made more economical and productive:

■ Advanced air separation methods to im-

prove efficiency of oxygen firing.

■ Improved designs and materials to increase

gasifier component life and to allow larger

gasifier sizes and higher gasifier pressures.

■ Use of flue gas or other low-grade heat

sources to reduce costs and energy con-

sumption for coal drying.

■ “Dry solids” pumps or use of supercriti-

cal CO2 instead of water for preparing coal

slurry.

■ Higher-temperature particulate removal

devices and hot gas desulfurization.

■ Advanced shift catalysts using less steam,

and membrane separation of CO2 and H2.

■ Hydrogen-firing gas turbines, improved

aerodynamics, and materials advances

to allow higher firing temperatures and

larger blade sizes that improve efficiency

and output.

Research into all of these areas is ongo-

ing, though commercialization is closer for

some than for others. Recent improvements

in natural gas–fired turbine performance are

also applicable to this field, and advanced

turbines optimized for IGCC are in develop-

ment by GE, Siemens, and MHPS. Gasifier

technology is also a robust area of research

and development.

Moving ForwardWhat happens next may depend in large part

on the success of the new Asian plants. “If

those projects can avoid the large cost over-

runs that were encountered by the U.S. IGCC

projects,” Phillips said, “it will open the door

to more IGCC projects not only in Asia but

possibly elsewhere. If they cannot, it could

doom the technology.”

The generators and manufacturers are so

far undaunted. Fujino said MHPS “contin-

ues to move forward on IGCC and gasifica-

tion projects.”

Duke Energy’s Good, for her part, was op-

timistic about Edwardsport in the same earn-

ings call. “Since the in-service date we have

been monitoring our success by progress-

ing through GE’s new product introduction

protocol, conducting detailed performance

testing and optimization procedures, and ob-

taining valuable operating experience with

the new facility,” she said. “All major tech-

nology systems have been validated and we

continue to focus on final performance test-

ing and optimization. We are on track to be

within the total revised project estimate of

$3.5 billion.”

Stay tuned. Godot may yet put in an ap-

pearance. ■

—Thomas W. Overton, JD is a POWER associate editor (@thomas_overton,

@POWERmagazine).


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Global Business Reports

July 20142 Global Business Reports // POWER BRITISH COLUMBIA

seeking to stem the inevitable tide of rate

increases for customers.

Under its current plans, BC Hydro plans to

spend C$1.7 billion per year over the next

10 years on capital improvements while

rates are expected to rise by 28% by 2019.

“There is a direct, unassailable connec-

tion between investment in infrastructure

and rates,” said Bill Bennett, BC’s Minister

of Energy and Mines. “The cost of infra-

structure is the main driving factor in deter-

mining rates. The Rates Plan was brought

about to bring certainty to electricity rates

for the residential, commercial and indus-

trial consumers of BC.”

Even with the rate increases, BC’s elec-

tricity will remain amongst the cheapest in

North America.

The plans fail, however, to clarify two very

important issues: the upcoming inal deci-

sion for whether BC Hydro’s Site C, a long-

proposed 1,100 MW project on the Peace

River, is approved, as well as the develop-

ment of substantial gas reserves through

the construction of electricity-intensive

LNG export facilities.

The Last in a Legacy’s Line: The Push for Site CSite C is a project decades in the making.

There are dozens of ways in which the pro-

ject can be viewed, and a wide variety of

stakeholders, each with differing concerns.

If the project is approved, everyone in BC

from First Nations to ratepayers to envi-

ronmentalists to engineering, construction

and procurement irms (EPCs) to independ-

ent power producers will feel an impact.

Site C was originally proposed as the third

of four major dams on the Peace River

in the mid-twentieth century. Two other

dams, the 2,876 MW W.A.C. Bennett Dam

and the 700 MW Peace Canyon Dam, were

completed in 1968 and 1980 respectively.

In 1982 and 1989 the British Columbia Utili-

ties Commission, BCUC indeinitely tabled

proposals for developing Site C, but BC

Hydro announced plans for Site C’s resur-

rection in April 2010. The debate amongst

stakeholders has not ceased since.

Following the approval of the IRP in No-

vember 2013, BC Hydro is currently work-

ing on securing the next round of permit-

ting and social licenses for Site C. “The

approved IRP contemplates that BC Hydro

would proceed with various processes and

stages to advance Site C to a stage that

would enable the government to make an

informed inal decision on whether Site C

should proceed sometime in 2014 or 2015,”

commented Charles W. Bois, a partner at

Miller Thomson LLP.

If approved in the aforementioned time-

frame, BC Hydro plans to bring the project

online by 2024. “Site C is dispatchable

and it produces 1100 MW of irm capacity,

which makes it higher quality than run of

river or wind, which are both intermittent

resources,” said Doug Little, vice president

of energy planning and economic develop-

ment at BC Hydro.

The government, meanwhile, is conscious

that rosy growth projections made at the

height of the commodities boom are un-

trustworthy. The resource-rich province re-

covered exceedingly well from the Global

Financial Crisis, posting GDP growth ig-

ures of 5.1% and 4.4% in 2010 and 2011

respectively. However, lower commod-

ity prices have partially been responsible

for the province’s slowed growth; the

Royal Bank of Canada estimates 2.1%

growth for 2014.

Although most indicators point towards

Site C’s approval in the coming months,

there are still some hurdles to overcome.

BC’s independent power producers (IPPs)

are closely monitoring the situation. “Con-

ditions have changed; I would not clas-

sify myself as an advocate of the [Site C]

project. It is my job to assess whether Site

C is the best way to generate 1100 MW

of electricity at the point in time when it

would be built and operating. Over the

last several months I have been busy try-

ing to develop alternative packages of ide-

as, combinations of generation that I can

take to the Cabinet and let them make the

choice whether to pursue Site C or another

option,” commented Minister Bennett.

Stantec, BC Hydro 2L22 Emergency Rebuild Project from the north side, Surrey, British Columbia. Photo courtesy of Stantec.

www.gbreports.com


July 20144 Global Business Reports // POWER BRITISH COLUMBIA

POWER BRITISH COLUMBIA

with supplying LNG facilities with grid-based power according to

McTavish: “Northwest BC [where the LNG sites are located] is

dependent on a single radial 500 kV transmission line from Prince

George to Terrace that is subject to numerous small outages dur-

ing the year. As the LNG sector moves forward, we will probably

see the industry rely on their own gas generation for their power

needs; so there is signiicant opportunity for gas generation and

renewables combined with local transmission and distribution up-

grades in and around Kitimat, Terrace and Prince Rupert. A lim-

ited transmission infrastructure in the north is also affecting the

construction of new industrial and IPP projects in much of BC.

The large costs and timelines required to interconnect into the

BC Hydro grid has signiicantly reduced the viability of some of

these projects.”

As the Liberal government faced the realities of its LNG promotion,

BC has revised some of its ambitious efforts to reduce the prov-

ince’s greenhouse gas emissions. In 2012, the Clean Energy Act of

2010, which outlined an objective “to generate at least 93% of the

electricity in British Columbia from clean or renewable resources,”

was amended to allow for gas generation at LNG facilities to be

considered a “clean source” of energy. “Certainly the decision to

label LNG as a clean fuel source and the upcoming decision on

whether or not to allow as-yet-to-be-built LNG export plants to

power inside the fence will have an effect on IPPs,” commented

Jason Jones, business development director - power transmission

and distribution sector - environment practice, at Tetra Tech EBA.

Waxing or Waning?: The Role of IPPs

In the early 2000s, the Liberal government under Premier Gordon

Campbell took the view of developing IPPs to meet generation

demands. Although IPPs have had a presence in the province

since the 1980s, this strategy enabled private sector players

to make a signiicant impact in the market for the irst time.

Presently IPPs account for approximately 20% of BC’s power

production.

In 2008, 27 electricity purchase agreements (EPAs) were award-

ed to IPPs in a Power Call put out by BC Hydro. Of these 27, 14

projects have come online or are expected to come online in

the near future. The rest have had their contracts terminated

or deferred by mutual agreement between BC Hydro and the

respective developer.

Glen Ichikawa, president of Kawa Engineering, a Vancouver-based

engineering irm specializing in work with IPPs, explains the at-

trition rate from the 2008 Power Call. “The irst is inancing;

some of these projects are millions (of dollars) over budget and

no one is making much money on them. Some companies have

gone belly up in the process. Lenders realize this and do not want

the exposure, so it is harder to get money. The other side is the

First Nation relationships; usually projects that fail have offended

bands at an early stage and thus the project is always ighting up-

hill. Third, are construction costs. Contractors have lost money in

the past, so they have raised prices to de-risk themselves when

someone cannot pay.”

The project-developer model of British Columbia’s IPPs

has had mixed success. Some projects begun by smaller lo-

cal companies never made it off the ground, while other pro-

jects, such as GDF Suez’s purchase of the Cape Scott wind farm

from Sea Breeze Power, were attractive M&A options for global

players. The province’s IPP sector has consolidated to fewer,

larger players; namely Innergex Renewable Energy, Alterra Power,

AltaGas, Brookield Renewable Power and Capital Power.

Compared to earlier power calls, John Carson, CEO of Alterra

Power, sees the attrition rate as a structural reality: “The contract

structure of any power call will affect the number that succeed,

whether it is being more generous on dollars per MWh or the

times of year when certain ‘revenue buckets’ can be illed. In the

2006 versus 2008 call for power, contracts were totally different.

w w w . g e a . c a engineering hydropower

weirs ¥ intakes ¥ gates ¥ lake taps ¥ pressure tunnels

penstocks ¥ powerhouses

1 to 100 MW

5July 2014 5Global Business Reports // POWER BRITISH COLUMBIA


2006 was more developer-friendly showing a lower attrition rate,

2008 was tougher and had a higher attrition rate.”

While M&A activity in the IPP sector was robust from 2010 to 2013,

most opportunities for a well-capitalized buyer to snatch a long term

EPA at an attractive price have passed, even with Site C on the hori-

zon. “Site C should have little impact on M&A activity in respect of

current projects with EPAs, as the current IPPs are locked into EPAs

ranging from 25 years to 40 years, guaranteeing their cash low,” said

G. Henry Ellis, a partner at Gowling Laleur Henderson LLP’s

Vancouver ofice.

As BC Hydro moves forward with Site C, it will likely dampen the

prospects of IPPs in the province according to Ellis: “The bigger

issue is that as Site C progresses, BC Hydro will reduce its em-

phasis of engagement with IPPs, as it is conident that Site C

will supply most of the incremental power required for the next

20 years. The government’s focus on LNG, coupled with the re-

sults of existing power calls and BC Hydro’s current interest in can-

Lex Engineering design for a BC Hydro 69 kV, 25 MVA substation at Langley, British Columbia. Photo courtesy of Lex Engineering.

celling some EPAs where the opportunity presents itself, suggests

that the government will place less emphasis in the future on con-

tribution from IPPs and greater reliance on Site C for the extra

required capacity.”

Vancouver-based Alterra Power, which plans on delivering its 62

MW Jimmie Creek run of river hydro project in 2016, is in many

ways the quintessential example of an IPP navigating the cock-

tail of confusion in BC through geographic diversiication and de-

risking its assets. However, the company has a desire to continue

its growth in BC if political decisions allow it. “If there is a call for

more power input, Alterra is ready,” commented Carson.

Regardless of the course of action for Site C, opportunities for IPP

developments, albeit small ones, remain under BC Hydro’s Standing

Offer Program, SOP. The SOP is designed to allow small projects a

streamlined, ad-hoc EPA process with BC Hydro, rather than having

to bid through a power call. Recently, the size of projects allowed

under the SOP was increased from 10 MW to 15 MW and the gov-

ernment is reviewing the program with the relevant stakeholders

to create a more impactful program. “The IRP may have shut the

front door to IPPs; the side door is still open via First Nations op-

portunities, as well as the SOP,” observed Michael Walsh, principal

and international managing partner at Midgard Consulting.

While the SOP will be an option for IPPs, it will be a niche market

and will take the right developer to execute the project according

to Mark Bohn, managing partner at Travelers Capital Corporation.

“There are some mid-market developers that have the experience

www.gbreports.com


7July 2014 7Global Business Reports // POWER BRITISH COLUMBIA


skills, but we need a strong project

base in this province on which to build.

It is essential that we do not lose

the knowledge base that now resides in

our young engineers.”

Although not an insurmountable challenge,

extreme weather conditions in the cen-

tral and northern parts of BC, with snow

lasting from November to March,

adds another layer of complexity when it

comes to infrastructure build. Guy Lemieux,

president of Lex Engineering that special-

izes in the design and build of substations

and transmission lines explains some of the

special adjustments needed for their

work in the province, “Lex transmis-

sion line and substations are designed to

accommodate extreme temperatures

of minus 50 ‘C and plus 40 ‘C. Transmis-

sion line conductors are sagged to not over

tension at minus 50 ‘C and to provide

the required vertical clearance at maximum

sag during full load at maximum ambient

temperature.”

Engineering irms also tend deal with the

winter conditions by building as much of

the substation and transmission line com-

ponents at a manufacturing facility before

transporting it to the remote locations

where it is then assembled.

Infrastructure precedes development,

which makes getting it out a challenge.

“Arguably, the biggest problem with

removing old infrastructure, especially

in the metropolitan areas, is that site

access conditions have signiicantly changed

since infrastructure installation. Historically,

transformers were moved by rail or

barge; rail sidings have since closed, and

barge sites have been replaced with

condominiums,” commented David Stroud

of Apex Industrial Movers.

As BC Hydro and the IPP sector are both

active in developing projects, the province’s

logistics sector has seen an increased

workload as massive generation and

transmission components are imported

from around the world and often sent in-

land via rail, river and/or road. “Our growth

has come from both BC Hydro and IPPs.

BC Hydro has been enacting system

upgrades, new sub-stations as well as

replacing old infrastructure. When work-

ing with IPPs, there are additional site is-

sues tending to be more in rugged remote

terrain and dificult to access areas; BC

Hydro’s locations are easier to access,

being generally near major infrastruc-

ture, but BC Hydro’s equipment is usually

much larger,” added John Brise of Apex

Industrial Movers.

Given BC’s closer proximity to Asian manu-

facturing centers, it is surprising that much

of Western Canada’s oversized indus-

trial components arrive in a port such as

Houston and are moved overland. Canadian

companies such as Apex, Triton Transport,

T-Lane Transportation and Amix Heavy

Lift are working to make British Columbia

Mobile hoppers being lifted onto Amix’s Arctic Tuk barge. Photo courtesy of Amix Heavy Lift.

more accessible.

Amix Heavy Lift acquired a ringer-crane

in 2005 and placed it on its Arctic

Tuk barge in order to move heavy

equipment, including transmission

cable spools, and generation turbines of up

to 380 mt. “Thereare substantial savings in

time and money; companies can import

straight into a British Columbian port,

utilize our services of heavy-lifting equip-

ment, and then truck the cargo to site,”

said Clarke Longmuir, president of Amix

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COMMENTARY

As Clean Energy Accelerates, a New Era of Choice Is Upon UsFred Krupp

Though our current power grid is more sophisticated and reliable than when Thomas Edison designed it nearly a century ago, it uses the same model: A company burns

fuel to create electricity, which is then sent hundreds of miles along inefficient wires to customers who are given a single energy choice: on or off. Now, finally, that is chang-ing, as our energy system becomes a two-way flow of both power and information in which customers both receive and produce electricity.

The U.S. will spend a projected $2 trillion in the next 20 years upgrading its power grid. We must make sure those investments are not spent on replacing old, dirty infrastructure with more of the same. The electricity systems we built in the last century, and the regulations that govern them, are no longer adequate to ensure reliability, fight climate change, or accommodate rapid changes in both technology and consumer demand. We need new rules, new ideas, and new approaches to overcome a century of the carbon-based “business as usual.”

New RulesThe landmark Clean Power Plan proposed in June by the federal Environmental Protection Agency is one crucial rule of the road that will help ensure that we stay on the fast track to a clean energy economy. Placing limits on power plant pollution is the single most important thing we can do right now to avoid irre-versible climate change. From 2005 to 2013, the U.S. reduced its power sector carbon dioxide emissions by around 15%, thanks in large part to advances in energy efficiency and fuel switching from coal to natural gas. But to date, the power industry has had no limits on the amount of carbon pollution it can emit, even though power plants account for nearly 40% of U.S. carbon di-oxide emissions from energy—more CO

2 than all of our factories,

homes, and businesses combined. These common-sense limits on carbon pollution from existing fossil fuel power plants deserve to be put in place straight away.

When adopted, these standards will be a landmark achievement for climate stability and public health; they could also go down in history for providing the tipping point in our nation’s transition to a clean energy economy. Retiring the most highly polluting coal-fired power plants presents a unique opportunity for clean energy solutions to fill this gap in generating capacity.

Real-world deployment of clean energy technologies is dem-onstrating that issues such as the variability of solar and wind energy can be addressed affordably, in ways that make the grid smarter, more efficient, and more reliable. Renewables are now the “fastest growing power generation sector,” with more solar panels installed in the U.S. over the last 18 months than the previous 30 years. The costs of solar and wind energy are falling rapidly, while electric vehicle sales are climbing, with 100%-

electric U.S. car sales up nearly 450% in 2013. Energy efficiency, the “lowest-cost electricity resource” for utilities, can also sig-nificantly reduce energy use. A recent report from the American Council for an Energy-Efficient Economy showed that energy effi-ciency measures can slash carbon emissions from the U.S. power sector by 26% with no net cost to the economy.

Energy Sector InnovationAmerican companies are also playing an important role in our transition to clean energy by developing products and services that people want to buy. Products like Google’s Nest learning thermostat allow homeowners to control appliances remotely to help reduce peak load, while tools like demand response save money by putting consumers in the driver’s seat. Companies like SolarCity, with its groundbreaking solar leasing approach, and SCIenergy, with its innovative business model of providing en-ergy efficiency as a service to commercial customers, are making cleaner energy affordable today.

These companies and others are transforming the way we make, move, and use energy. For example, in Austin’s Mueller neighborhood, a living consumer energy lab run by nonprofit Pecan Street Inc., some residents power their homes using little to no electricity from the grid over the course of the year, simply because they’ve installed home energy management systems and solar panels on the roofs of their houses.

This new reality requires a new business model—one that fair-ly values efficiency and clean, renewable energy. This means re-vising the current model, which measures success by the amount of megawatts sold, to one that rewards utilities for generating and selling energy more wisely, sustainably, and efficiently. After all, the cleanest and cheapest megawatt is the one utilities don’t have to generate.

Perhaps most importantly, public support for clean energy is at a record high. According to a 2013 poll by Yale University, 61% of Americans said developing sources of clean energy should be a high or very high priority for the president and Congress. People care about energy because it touches everything that we do, and Americans are tired of hearing sad, old myths about why we can’t move forward.

History and experience tell us that America can navigate this transition without threatening our non-negotiable commitment to safe, affordable, reliable energy. American ingenuity is second to none—and it will be supercharged when the U.S. pioneers an open, vibrant market for new, advanced energy that sparks pri-vate capital and technological innovation. My colleagues and I at Environmental Defense Fund look forward to working with our partners in the power industry to meet the challenges and enjoy the opportunities of this new era. ■

—Fred Krupp is president of Environmental Defense Fund.

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Experience the Power of Zeeco.

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Explore our global locations at zeeco.com

Zeeco, Inc.

22151 E 91st St.

Broken Arrow, OK 74014 USA

+1-918-258-8551

[email protected]

©Zeeco, Inc. 2014

Fact is natural gas is the new standard to meet emissions regulations.

Let Zeeco’s talented engineering and design team take the anxiety out

of switching to or adding natural gas to your power facility’s fuel sources

with our low and ultra-low NOx boiler burners.

ZEECO® boiler burners are the logical choice to convert coal-fired power

to natural gas, or add gas-fired capability to existing burners that meet

all emissions and efficiency targets. In a combined cycle facility,

ZEECO low-NOx duct burners also assist in meeting clean-air standards.

It’s time you introduced the ultra-low emissions and fuel flexibility that

keep power and steam generating for years to come.

Global experience. Local expertise.

ZEECO Free-Jet Boiler Burner

ZEECO Low NOx Duct Burner


PowMagazine 07 2014

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Transcript of PowMagazine 07 2014