Power Magazine, International January 2014

Janu

ary 2014 • Vo

l. 158 • No

. 1

Vol. 158 • No. 1 • January 2014

2014 Industry Forecast: Global Forces Shape Generation

U.S. Regulations to Watch

Global Shale Outlook

Generating Company Advisory Team Insights

PRBCUG Award-Winning Plants

01_PWR_010114_Cover.indd 1 12/17/13 12:43:07 PM

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On the coverThe power industry generates power locally but operates within a global market. This true-color image shows North and South America as they would appear from space 22,000 miles above the Earth. The image is a combination of data from two satellites. An instru-ment aboard NASA’s Terra satellite collected the land surface data over 16 days, while a NOAA satellite produced a snapshot of Earth’s clouds. Source: NASA

COVER STORY: 2014 induSTRY fORECaST20 a Rising Tide of Regulation and the “Kick-the-Can” Gambit

U.S. power generators are bracing for an onslaught of new federal environmen-tal regulations in 2014, but instead of scrambling to meet new requirements, they may be faced with months of legal wrangling and extended uncertainty about final rules.

25 Black & Veatch foresees u.S. and Global OpportunitiesDean Oskvig, president and CEO of Black & Veatch’s Energy Business, sees this year’s business outlook improving both globally and in the U.S.

26 How u.S. Power Generators are Preparing for 2014Our Generating Company Advisory Team (GACT) members, who have agreed to serve two-year terms and provide strategic input to the editorial team, are seasoned professionals with an understanding of both plant-level concerns and big-picture business challenges. They represent a variety of regions, regulatory environments, generation portfolios, and business types—giving you insight into both situation-specific and common concerns.

29 Burns & Mcdonnell Sees u.S. Market in Transition While asian Market GrowsGrant Grothen and Block Andrews look at the market drivers both domestically and in overseas markets experiencing load growth.

32 Europe faces Capacity and Cost Challenges in 2014The European Union (EU) has long been on the forefront of efforts to reduce green-house gas emissions and transition away from fossil and nuclear generation. It now faces not only economic consequences and future infrastructure needs resulting from individual EU country goals but also overcapacity and undercapacity scenarios.

35 day & Zimmermann focuses on flexibilityMichael McMahon, president of Day & Zimmermann ECM, discusses the value for the industry’s future of alliances, partnerships, and workforce development at all levels.

36 Shale: The Rock That Rocked the WorldThe U.S. is the first nation to fully enjoy the benefits of accessing shale gas economi-cally, but it won’t be the last. Here’s a look at where you’re likely to see the earliest second-wave action.

SPECiaL REPORT: POWER in CHina41 China’s Shale Gas development Outlook and Challenges

As one of the world’s largest and fastest-growing energy consumers, China is focus-ing on securing new and diverse supplies of energy to maintain a healthy rate of economic growth and societal development. Though the nation hopes shale gas will be part of its future, significant challenges need to be met.

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FEATURES PRBCUG AwARdS62 TransAlta’s Centralia Plant Earns PRBCUG Award

Completing the careful transition to 100% Powder River Basin coal earned TransAlta’s Centralia plant in southwest Washington the Powder River Basin Coal Users’ Group (PRBCUG) Plant of the Year award in the Large Plant category.

63 OPPd’s North Omaha Station Takes PRBCUG HonorsThe PRBCUG Plant of the Year winner in the Small Plant category introduced materi-al-handling and other upgrades to increase safety. Its measures can be a model for others burning the low-sulfur coal.

dEPARTMENTS SPEAkiNG OF POwER6 Global Change Agents

GLOBAL MONiTOR8 iEA’s world Energy Outlook 2013: Renewables and Natural Gas to Surge

Through 20359 Future of Australia’s Carbon Pricing Scheme Hangs in the Balance9 EPRi Plans High-Burnup Spent Fuel demonstration10 THE BiG PiCTURE: Regulation Reckoning12 Milestones for Major Nuclear Projects1 2 A Novel Solar-Fossil Hybrid Power Plant14 POwER digest

FOCUS ON O&M16 Upgrading a wired Public Address System with a wireless Option

LEGAL & REGULATORY18 Financial Performance-Based Utility Bonuses: Unnecessary Exposure

By Steven F. Greenwald and Jeffrey P. Gray, Davis Wright Tremaine LLP

66 NEw PROdUCTS

COMMENTARY72 is distributed Generation Really the Future?

By Ted Nordhaus, Michael Shellenberger, and Alex Trembath, The Breakthrough Institute

Redefining Priorities for Québec’s Hydro Power Cluster

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

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This sponsored report by Global Busi-ness Reports (p. 45) examines the Canadian province of Québec’s vast re-newable energy portfolio, long history with hydro power, and the industry’s plans for sharing its expertise with de-veloping countries.



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With worldwide energy consumption expected to double to an estimated 39.0 billion MW hours by 2040, Fluor’s experts are committed to providing industry-leading solutions, innovation, and technologies that bring strategic value to our clients’ capital projects. With more than 20 years of experience building gas-fired power plants, Fluor recently completed Dominion’s 590 MW combined cycle project, the Bear Garden Generating Station. www.�uor.com

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FLUOR’S LEGACY AS YOUR ASSET

Fluor’s Power Business – Fossil Generation, Renewables, Alternate Technologies, Nuclear, Transmission, and Operations & Maintenance.

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SPEAKING OF POWER

Global Change Agents

Now more than ever, the power generation business is a global business. Supply chains are more international than in the last century. Thanks to more easily retrievable re-

serves of shale gas, the prospect of increased liquefied natural gas exports from countries on six continents promises to shake up global fuel markets. Cyber crime knows no borders. Even hu-man capital is subject to global dynamics—remote equipment monitoring can be managed a continent away, and skilled work-ers take temporary or permanent assignments wherever demand for their talents is strongest.

Responding to a Changing IndustryEven as many regions seek to source more energy locally, the technologies and services for both distributed and centralized generation—from American-designed boilers to Chinese-manu-factured solar modules—are being provided by companies that conduct business globally. U.S. companies are participating in that trend, in part as a consequence of nearly flat load growth and limited opportunities for new project construction at home. As less-electrified nations, especially in Asia, have accelerated their economic development plans, the biggest markets for many companies in this industry, and some of the most interesting projects, now lie beyond North American borders.

Does that spell the decline of U.S.-based businesses serving the industry? Not necessarily. Shifts in economic growth from one nation to another are nothing new. Major players that have long been involved globally are simply looking abroad for a larger chunk of new business. Westinghouse, for example, in a Novem-ber promotional release said it sees a promising future for nuclear energy in Brazil. Other companies may find themselves involved in new lines of business closer to home—perhaps more retrofit and upgrade work rather than new builds.

Do low demand growth and increased regulation in the U.S. mean domestic power plant workers have hit a career dead end? Not necessarily. Those willing to acquire new skills and, yes, maybe even move, should find jobs, especially given the overall aging industry workforce.

Global Fuel DynamicsThe shale revolution is typically acknowledged as the biggest near-term industry disruptor. Every nation with any reserves, it seems, is at least considering its options for developing shale gas. South Korea, for example, plans to mitigate its reliance on energy imports by focusing on the unconventional gas, and Chi-na is cautiously optimistic about development of its substantial shale reserves. Europe in particular has reason to hope that the evolving global gas market will break the linkage between natural gas and oil prices while increasing fuel diversity.

Though shale is the most obvious global change agent in the fuel arena, the escalating demand worldwide for coal-fired gen-eration makes it imperative to use this resource in ways that ad-dress environmental, health, and climate change concerns. Europe has made arguably the fastest switch from coal to cleaner fuel

sources—though not without some backtracking and higher-than-promised costs. But the story doesn’t end with Europe. To under-stand the need for improved coal combustion practices globally, you only need to look at the daunting challenge China faces with air pollution, especially during the winter heating season. Though coal-fired facilities providing heat and power are not solely re-sponsible for air through which you cannot see the person next to you, they are certainly a major contributor in parts of China.

Growing economies are unlikely to abandon coal anytime soon. That means the global market opportunity for affordable and truly cleaner coal usage is huge. Of course it’s not a simple problem to solve—especially while also protecting other resources, like water. But that’s exactly where the best and brightest from all nations can contribute new solutions to a mature industry. After all, those shiny tech gadgets continue to depend upon electricity, and reli-ance on those gadgets is growing globally, along with standard of living improvements.

After the 2011 Fukushima disaster, it seemed that event would go down in history as a long-term negative change agent for nuclear generation globally. In Japan, recovery for the nuclear in-dustry is proving very slow. But it appears that other nations are proceeding more or less according to previous agendas. Though several European nations, including the historically nuclear-heavy France, are holding firm to post-Fukushima nuclear pull-backs, the UK is moving forward with plans for new nuclear genera-tion. In the U.S., the handful of unit shutdown announcements have been prompted by poor economics and equipment problems rather than fears about nuclear energy, and the development of small, modular reactors is making slow but deliberate progress.

Renewables will continue to have a disruptive effect disproportion-ate to the megawatt-hours generated. Adding large amounts of grid-integrated intermittent sources creates challenges both for countries like China that are faced with building new transmission infrastructure and those like the U.S., coping with some of the oldest lines. Wherever wind and solar power become significant contributors to the grid, the market for affordable, flexible technology solutions—from energy storage to hybrid generation schemes to smart grid–enabled demand response—presents an opportunity for new business.

Pro� ting from Global ChangeIn response to the changing market, POWER continues to expand its coverage of developments around the world while remaining committed to the industry’s success in North America, where, like them or not, new regulations present new business opportunities for some as they pose threats to others. This industry forecast issue offers insights into the levers of change not just in the U.S. but also in selected, key international markets.

Change is rarely easy, but it’s inevitable—even in the power industry—and it can be good for business. Whatever role you play in the global power generation industry, we wish you a hap-py, healthy, and prosperous New Year! ■

—Gail Reitenbach, PhD is editor of POWER. Follow her on Twitter @GailReit and the editorial team @POWERmagazine.

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IEA’s World Energy Outlook 2013: Renewables and Natural Gas to Surge Through 2035By 2035, renewables will hold a 30% share of the global power mix, but only 1% of the world’s fossil fuel–fired power plants will be equipped with carbon capture and storage (CCS), reports the International Energy Agency (IEA) in its newly released World Energy Outlook (WEO-2013).

The annual report presents a central scenario in which global energy demand rises one-third by 2035, driven higher by the growing populations and expanding economies of India and Southeast Asian countries rather than by China. Mean-while, more than half of the projected increase in global primary energy demand will come from the power sector (Figure 1), the agency projects.

Coal is expected to remain a cheaper option than natural gas for power genera-tion in many regions, though that could change, depending on policy interventions to improve efficiency, curb air pollution, and mitigate climate change. Coal demand is set to increase 17% by 2035, with two-thirds of that increase occurring by 2020. While coal use will decline by half in Eu-rope (despite current price dynamics) and plateau in China by 2035, India is poised to become the world’s largest coal im-porter by 2025. In the U.S., coal use is expected to decline by 14%.

Though several initiatives to mitigate climate change are under way—as with the U.S. Climate Action Plan, China’s plans to limit coal’s share in its domestic energy mix, Europe’s debate on 2030 energy and

climate targets, and Japan’s discussion of a new energy plan that may or may not include nuclear power—global energy-related carbon dioxide emissions will still rise by 20% by 2035. That means, accord-ing to the IEA’s New Policies Scenario, which takes into account the impact of al-ready announced climate change measures and other policies, the world will be on a “trajectory consistent with a long-term average temperature increase of 3.6C, far above the internationally agreed 2C tar-get,” the report says.

Though the global average efficiency of fossil fuel conversion in power plants is fore-cast to improve by 15%, the IEA makes the significant, if dismal, admission that wide-spread deployment of CCS technology could stall. Only about 1% of global fossil fired–power plants (about 67 GW) will be equipped with CCS by 2035, mostly in the U.S., China, and the European Union (EU). CCS appears “well-suited” to resolving at least some of the tension between rapidly increasing power demand and the need to limit carbon emissions and local pollution, “yet many significant challenges have still to be over-come,” the agency says. These include the need to “integrate component technologies effectively into large-scale projects, identify viable storage sites and put the necessary financial incentives in place.”

By 2035, natural gas demand will out-pace that of any other individual fuel and end up nearly 50% higher than in 2011. Demand for gas will come mostly from the Middle East—driven by new power generation—but also from Asian coun-tries, including China, India, and Indone-sia, and Latin America. Power generation

continues to be the largest source of gas demand, accounting for around 40% of global demand over the period. New gas plants, meanwhile, are expected to make up around a quarter (or 1,000 GW) of net capacity additions in the world’s power sector through 2035.

Nuclear generation will also increase by two-thirds, reaching 4,300 TWh in 2035, led by China, South Korea, India, and Rus-sia. But demand for nuclear power will be driven mostly by expansion in just a few countries. China accounts for around half the global increase, while South Ko-rea will see the next-largest increase, fol-lowed by India and Russia. The prospects for nuclear power are less uncertain than after Fukushima in 2011, the IEA notes. What remains murky, however, is how the sector could be affected by further policy changes, implications of the ongoing safe-ty upgrades for plant economics and pub-lic confidence, and notably, the impact of increased competition from shale gas.

Nearly half of the increase in global power generation will be from renew-ables—and generation from wind, solar, and hydro will make up an expected 30% share of the global power mix by 2035. That will put it ahead of natural gas and just behind coal as the leading fuel.

China will lead the world in renewables installations by 2035, its total renewable output totaling more than in the EU, the U.S., and Japan combined. Overall, the massive renewables increase will likely create challenges, the IEA foresees, rais-ing questions about current market design and its ability to “ensure adequate invest-ment and long-term reliability of supply.”

Electricity prices will also vary, the agency forecasts. By 2035, average Japa-nese, European—and even Chinese—in-dustrial consumers will pay twice as much for power as their counterparts in the U.S., “which could have important ramifications for competitiveness,” the report says.

The report also notes that substantial investments in the power sector will be required over the projection period to sat-isfy rising power demand and to replace or refurbish aging infrastructure. By 2035, around 50% of today’s grid infrastructure will have reached 40 years of age, the agency notes. Cumulative global invest-ment could amount to as much as $17 tril-lion through that period, averaging $740 billion per year. New plants will account for 58% of the total, while the rest will be

10,000

8,000

6,000

4,000

2,000

0 Coal

OECD (2011) OECD (2035) Non-OECD (2011) Non-OECD (2035)

Gas Oil Nuclear Hydro Other renewables

1. The changing face of world power generation by source. The power gen-eration mix (in TWh) in member countries of the Organisation for Economic Co-operation and Development (OECD) and non-members is expected to evolve variedly. Source: IEA


needed in transmission and distribution networks.

Future of Australia’s Carbon Pricing Scheme Hangs in the BalanceAustralia’s freshly elected prime minister, Tony Abbott, introduced a bill in Novem-ber to scrap the nation’s controversial carbon pricing plan, which is slated to transition to an emissions trading scheme (ETS) in July 2014. But the government also declared it won’t extend the carbon tax beyond June 30, even if the Senate does not pass the repeal legislation by then—prompting alarm among generators and other stakeholders, who say the possi-bility of a retrospective repeal, even for a short period, will create risk for all partici-pants and complicate the repeal process.

Abbott was elected in September partly on an election pledge to repeal the pre-vious Labor government’s pricing plan, which sought to reduce greenhouse gas (GHG) emissions in coal-rich Australia by 5% below 2000 levels by 2020 and 80% by 2050 (Figure 2). The carbon-pricing scheme became effective in July 2012 as part of a broad energy reform pack-age called the “Clean Energy Plan.” It currently taxes 370 major carbon emit-ters the world’s highest carbon price of A$24.15 per metric ton of emitted carbon dioxide and is set to switch to an ETS this July, moving from a fixed carbon price to a floating price of about A$6.

But Abbott has instead called for a so-called “direct action plan,” which includes an emission reduction fund and a market-based incentive for businesses to reduce GHG emissions. Observers in November noted that the bill is expected to easily

pass the lower house, where the Liberal-National Coalition has a clear majority, but could face a standoff in the Senate, which is dominantly held by the Labor, Greens, independents, and several smaller parties. Abbott has promised to call a double dis-solution of parliament if the Senate blocks the bill, which would mean elections to both the lower and upper houses.

If, however, the repeal bill has not been passed by July 1, 2014, the fate of the legislation will be handed to a new Sen-ate that will meet on that date. But for the country’s power and gas transmission industries, that could mean confusion and uncertainty. “This stated intention to backdate repeal to 30 June 2014 does not mean that businesses can ignore the car-bon tax while it remains law,” a number of industry groups said in a joint statement on Nov. 4. “The possibility of retrospective repeal, even for a short period, will create risk for all participants in the market and complicate the repeal process. If repeal cannot be secured well in advance of 30 June 2014, the industry is eager to work with the Government to find ways to ad-dress the challenges this will create.”

The groups are opposed to the car-bon price, which they said already posed several uncertainties. It has increased the costs of fossil-fueled generators and therefore increased wholesale prices as af-fected generators sought to recover their increased costs. They noted, however, “it is impossible to precisely quantify the extent to which the carbon price has in-creased wholesale energy prices, as they vary based on the changing mix of gen-eration output.” Further complicating this scenario is the “inability to attribute” a specific value to the carbon price at the time of trade. “Where a forward contract is all-inclusive, as is the case for exchange-traded products, each participant makes their own assessment of the value of the fully-inclusive price, including the impact of the carbon tax,” the groups said.

According to Matthew Warren, CEO of the Energy Supply Association of Australia, a more efficient means of reducing GHG emissions than putting a price on carbon has been to increase the renewable energy target (RET) to 20% by 2020, which he noted has already “forced in” 1.8 GW of large-scale renewable generation into the electricity market. “But there’s a problem,” he said. The RET was passed in 2009 when it was assumed demand for energy would soar. “With demand falling, the RET target is now approaching 30%. This means we will have to build even more renewable

power stations trying to sell electricity into an already over-supplied electricity market. The higher cost of gas means in many instances more efficient, more mod-ern and lower emissions gas generators are being stranded and older, cheaper coal generators remain online,” he observed.

“The kicker is that with no carbon price, the oversupply means that the wholesale price is likely to drop so low that even the value of Renewable Energy Certifi-cates won’t be enough to pay for more new renewables,” he said. “You could try and fix this with a carbon price, but now with higher gas prices it would need to be $70 or more per tonne of carbon. Austra-lia’s current fixed carbon price is $24.15 a tonne. If we link to the European scheme in 2015, it will fall to less than $10.”

Around the world, meanwhile, Austra-lia’s proposed retreat on its climate plan has been received with mixed reactions. Canada, which withdrew from the Kyoto Protocol in 2011 and has failed to meet its own international GHG emissions tar-gets, issued a formal statement in mid-November applauding Australia’s move to repeal the carbon tax. The decision will be “noticed around the world and sends an important message,” said Paul Calandra, parliamentary secretary to Canada’s prime minister, Stephen Harper. Canada in 2009 agreed to align its climate plan with the U.S. target to slash GHG emissions 17% from 2005 levels by 2020.

And in November, Japan’s Minister of Envi-ronment announced that country was chang-ing its own carbon emission reduction target from 25% below 1990 levels by 2020 to a 3.1% increase from 1990 levels, or a 3.8% reduction from 2005 levels. Japan’s shifting stance was prompted by the country’s shut-down of all 50 nuclear power plants, which has forced the resource-poor country to rely on vast imports of coal and liquefied natural gas. The country’s power sector carbon diox-ide intensity soared to levels in 2012 that were 39% greater than when the country’s nuclear plants were operational.

EPRI Plans High-Burnup Spent Fuel DemonstrationA study proposed by the Electric Power Research Institute (EPRI) could shed more light on how safe it is to store high-burn-up used nuclear fuel in dry casks.

In an August 2013–released draft test plan developed by the research institu-tion for the Department of Energy (DOE)–sponsored study, EPRI proposes using a specially instrumented dry storage cask to

2. Curbing carbon. While the future of coal-rich Australia’s carbon pricing scheme remains murky, the country is forging ahead with demonstration projects to capture and store carbon dioxide. The A$208 million Callide Oxyfuel Project at the Callide A Power Station in Queensland, shown here, began a two-year-long demonstration of oxyfuel carbon capture in December 2012. Courtesy: CS Energy


THE BIG PICTURE: Regulation ReckoningES

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MATSFinalized in February 2012 (and

later updated in March 2013), MATS sets the first nationwide limits on power plant mercury emissions. Coal and oil generators of more

than 25 MW are required to slash emissions of mercury, arsenic, and

metals by 2016.

CSAPR/CAIRTightens limits on emissions of fine

particulates, sulfur dioxide, and nitrogen oxide from power plants in 28 states in the eastern U.S. CAIR remains in place as the

Supreme Court reviews a federal court’s decision to vacate the

2011-finalized CSAPR.

BOILER MACTFinalized in January 2013, the

Boiler MACT rule requires stringent emissions reductions of hazardous

air pollutants from industrial, commercial, and institutional

boilers in the U.S.

This rule proposed in April 2011 under Section 316(b) of the Clean Water Act could require more than 670 fossil fuel and nuclear power plants that withdraw at least 2

million gallons per day of cooling water and use once-through cooling systems to retrofit to closed-loop cooling via cooling towers. A final rule is expected in January 2014.

ESTI

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Finalized inn February 2012 (and TighMMMATS

n February

EPA:

$35B upfront capital

spending

INDUSTRY: $84B–$130B

for MATS and CAIR combined

$11.9B per year by 2015

(25% more than EPA)

$9.6B per year by

2016

$3.6B per year in 2015 for

CAIR

$14B–$18B per year by

2020 for combined CSAPR and various rules

(~400% more than EPA)

$1.9B per year for

major sources in

2013

PR

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$2.7B per year in 2013

(42% more than EPA)

No estimate

MACTry 2013 thf fine

BOBOBOOFinalized in Januar

OOOOIIILER Min Januar

INDUSTRY:

$14.3BEPA:

$5.1B

EPA: No estimate

INDUSTRY:

$149B

COAL ASHWhen finalized as expected in 2014, the EPA’s June 2010–proposed rule

could be first-ever national mandate that governs the disposal and management of coal ash from

coal-fired power plants under the nation’s primary law for regulating solid waste, the Resource Conserva-

tion and Recovery Act (RCRA).

$7.6Bper year

(~400% more than EPA)

$1.5Bper year under

Subtitle C

$587Mper year under

Subtitle D

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When finalizedWhSH

d as expected in 2014OOOAL ASd as exp

INDUSTRY: $33.4B

EPA:

$20.3Bfor Subtitle C

$8.1Bfor Subtitle D

Notes: MATS = Mercury and Air Toxics Standards; CSAPR = Cross State Air Pollution Rule; CAIR = Clean Air Interstate Rule; MACT = Maximum achievable control technology; NAAQS = National Ambient Air Quality Standards. Sources: POWER, Environmental Protection Agency, National Manufacturing Association, Electric Power Research Institute, NERA.


COOLING WATER INTAKE This rule proposed in April 2011

under Section 316(b) of the Clean Water Act could require more than 670 fossil fuel and nuclear power plants that withdraw at least 2

million gallons per day of cooling water and use once-through cooling systems to retrofit to closed-loop cooling via cooling towers. A final rule is expected in January 2014.

EFFLUENT GUIDELINESTechnology-based effluent

limitations and guidelines proposed in April 2013 could set the first

federal limits on the levels of toxic metals in wastewater discharges

from steam electric plants. A final rule is expected in May 2014.

OZONE NAAQSMore stringent ambient air quality

standards for ozone that were proposed in January 2010 were deferred by President Obama to

lighten the “regulatory burden.” The EPA is expected to finalize the rule in

2014.

$90B per year

No estimate

$0.3B–$4.6B per year

$8B per year

(74% more than EPA)

$499M per year for

bottom ash only (Option 4a)

$942M per year for Option 4a (88% more than EPA)

WATER INTAKEKEKE posed in April 2011

EPA: No estimate

INDUSTRY: $149B

EFFLUENT GUIDELINEEESSSTechnology based effluent

INDUSTRY:

$6Bfor Option 4a

EPA:

$2.6Bfor Option 4a

When finalized as expected in 2014, the EPA’s June 2010–proposed rule

could be first-ever national mandate that governs the disposal and management of coal ash from

coal-fired power plants under the nation’s primary law for regulating solid waste, the Resource Conserva-

tion and Recovery Act (RCRA).

400% more than EPA)

014d

c

standards for ozone that wereproposed in January 2010 weredeferred by President Obama to

lighten the “regulatory burden ” The

a

OZONE NAAQSMore stringent ambient air quality

standards for ozone that were

$90B $er yeaar p

No estimate

M

$1T per year

(~1,000% more than EPA)

The Environmental Protection Agency (EPA)

has justified promulgating sweeping proposed and final new rules for air

emissions, water use, and the disposal of combus-

tion residuals by conclud-ing that the benefits of these emerging rules

would far outweigh their costs. But the power

industry contends that, while estimated health

and economic benefits are highly uncertain, the

cumulative impact of the EPA’s rules could cost, by conservative measures, roughly $100 billion

annually—and that that cost burden conflicts with

the Obama administra-tion’s pledges to

strengthen the nation's economy. —Copy and

artwork by Sonal Patel, a POWER associate editor


monitor conditions and changes to high-burnup used fuel stored for a test period of a decade or more.

The plan calls for a Transnuclear TN-32 demonstration cask and fuel, supplied by AREVA and Westinghouse, to be placed at the independent spent fuel storage instal-lation (ISFSI) at Dominion Virginia Power’s North Anna nuclear energy plant. However, Dominion Virginia Power (which is part of the EPRI team) must first secure a license amendment request for the existing ISFSI from the Nuclear Regulatory Commission (NRC) by 2015 for the test cask to be loaded by July 2017, as planned. Measure-ments of conditions inside the cask and the state of the stored fuel at the end of the storage period will be compared with data on about two dozen “sister” fuel as-semblies examined at the beginning of the test. The DOE, meanwhile, has sought comments from public stakeholders to en-sure project resources are invested wisely.

The project is part of efforts that are gaining more urgency to demonstrate the ability to safely store—for many de-cades—and then transport spent nuclear fuel (SNF). The U.S. has stored lower-bur-nup SNF of less than 45 GW-days per met-ric ton uranium since 1986 in dry casks (Figure 3), but dry storage of high-burnup SNF has been more recent. About 200 dry storage casks (out of more than 1,700 na-tionwide) were loaded with at least some high-burnup SNF as of December 2012. “Furthermore, almost all SNF being load-ed in the U.S. is now high burnup,” EPRI points out. “Thus, industry needs data on high burnup SNF under typical condi-tions.”

EPRI’s planned test would update the results of a similar study, concluded by the

Idaho National Laboratory (INL) in 1999, that examined fuel with characteristics that were typical at that time, the Nuclear Energy Institute notes. “Since that study, the industry increasingly has been able to extract more energy from nuclear fuel by operating reactors at higher power levels and by using longer cycles between refuel-ing. The resulting higher-burnup used fuel is both more radioactive and hotter.”

But another reason the study is impor-tant is a continuing need for a permanent solution for the disposal of used nuclear fuel from reactor sites, “which makes it more likely that fuel is stored in dry casks for periods longer than the original 20-year license,” the nuclear industry group said. “Based on the INL study and other information, the NRC in 2011 revised its used fuel storage regulations (10 CFR Part 72) to increase the licensing period for dry casks to 40 years with the option for ad-ditional renewals of up to 40 years.”

EPRI said the data obtained from the test could also help answer NRC requests for information from applicants for dry storage license extensions on the condi-tion of high-burnup SNF after the initial 20-year license period.

Milestones for Major Nuclear ProjectsSeveral new nuclear plant construction milestones were recorded worldwide in October and November.

CPR-1000. On Nov. 23, China’s 18th large reactor, Hongyanhe 2, was connect-ed to the grid. The $8.2 billion CPR-1000 pressurized water reactor began construc-tion in 2008. Two more units are under construction nearby in northern Liaoning province, about 420 kilometers from Bei-jing across the Bo Hai Sea.

AP1000. On Nov. 4, safety-related con-crete was poured for the basemat of the sec-ond AP1000 unit at the V.C. Summer plant in South Carolina. Later that month, Georgia Power poured safety-related concrete for the basemat of the second AP1000 unit at Plant Vogtle. Meanwhile, four AP1000 reactors are being built in China, at Sanmen and Hai-yang. Sanmen Unit 1 (Figure 4) is expected to be the world’s first AP1000 to begin op-erating when it goes online in 2014. The U.S. AP1000 units will come online between 2017 and 2018, while the Chinese reactors will all be operational by 2016.

AES-2006. The foundation slab of the first of twin Russian reactors at Ostrovets in Belarus was poured in November at a site in the Grodno region close to the Lith-

uanian border. The 1,200-MW AES-2006 reactors are being built by AtomStroyEx-port and mark the first major milestone for the project after the turnkey contract was finalized between Belarus and Rosatom in July 2012 for the supply of the two reac-tors. Construction of each unit could take up to five years.

EPR. On Oct. 24, the AREVA-Siemens consortium that is building the Olkiluoto 3 EPR for Finnish power company Teol-lisuuden Voima Oyj (TVO) installed the reactor vessel head, marking completion of the installation of heavy equipment. The project has been besieged by delays since it began construction in 2005. TVO has warned that the plant may not be op-erational until 2016.

At Flamanville 3, where AREVA is build-ing France’s first EPR, the reactor vessel was delivered to the construction site. Civil engineering work is now almost complete at the Normandy site. Though originally expected to begin operation in 2013, the reactor’s construction is expected to be completed in 2016. Taishan 1, which is an EPR under construction in China, has been under construction since 2009 and is ex-pected to start up in 2014, while Taishan 2 is scheduled to begin operating in 2015.

A Novel Solar-Fossil Hybrid Power PlantThe Pacific Northwest National Laboratory (PNNL) is developing a promising solar-fossil hybrid power system for integration with a conventional combined-cycle power plant. The hybrid system uses concentrat-ed solar power (CSP) from a parabolic dish to drive the endothermic steam-methane reforming (SMR) reaction (see Equation 1) in a reactor mounted at the focal point of the dish (Figure 5). The mixture of carbon

3. A dry cask task. Since 1986, the U.S. has stored lower burnup spent nuclear fuel in dry casks like these at the Diablo Canyon site near Avila Beach, Calif. But “almost all” spent nuclear fuel being loaded in the U.S. is now high burnup, the Electric Power Research In-stitute notes in a draft test plan to study the safety of high burnup fuel dry storage. Source: NRC

4. The first of a bevy. Construction at the State Nuclear Power Technology Corp.’s Sanmen Unit 1 in China’s eastern Zhejiang province is nearing completion. When the plant is commercially operational in 2014, it will be the world’s first nuclear power unit to employ Westinghouse’s third-generation AP1000 tech-nology. Courtesy: Sanmen Nuclear Power Co.


monoxide (CO) and hydrogen (H2) result-ing from the reaction, called syngas, has 27% more chemical energy than the enter-ing methane. The syngas is then routed to the combustion turbine instead of using methane (natural gas) directly.

Equation 1: CH4 + H2O = CO + 3H2

The hybrid power system has several advantages that suggest promise for de-veloping a cost-effective system. The parabolic dish concentrator is always pointed directly at the sun, which results in 50% more solar energy reaching the so-lar receiver on an annual basis, per unit of concentrator area, compared to fields of heliostats pointing to a receiver on top of a tower or parabolic troughs, the most commonly implemented CSP tech-nology to date. This performance advan-tage is particularly important because the concentrator, with its mirrored surface, is typically the most costly component in a CSP system.

The parabolic dish provides the so-lar concentration necessary to reach the temperature (an estimated 800C) required

to drive the reforming reaction forward. High heat and mass transfer rates made possible via small channels in the reac-tor allow a compact design to minimize cost and thermal losses. After recovering most of the thermal energy in the product stream by preheating the reactants, ther-mal losses are minimal compared to that experienced in other CSP piping systems. Best of all, capture of solar energy in syn-gas allows its conversion to electricity via a combined-cycle power plant. Col-lectively, these advantages translate into solar-generated chemical energy (i.e., the solar fraction of syngas chemical energy) that is projected to cost no more than forecast natural gas prices in the U.S. over the lifetime of the power plant, assuming a site with solar insolation typical of the Southwestern U.S.

PNNL has completed the first of three research and development phases planned in work funded by SolarThermoChemical LLC and the U.S. Department of Energy through its SunShot Initiative. Much of the first phase was spent fabricating and assembling the single dish system (shown in Figure 5). The system uses an early ver-

sion of a parabolic dish concentrator de-veloped by Infinia Corp. of Ogden, Utah. Infinia developed the concentrator to mate with its Stirling engine generators, but it works equally well providing concentrated solar energy to the PNNL steam-methane reformer.

Phase 1 testing achieved solar insola-tion to chemical energy conversion ef-ficiency as high as 69% for periods of

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5. SolarSMR test system in late afternoon. Source: PNNL


several hours, which is believed to be a world record. One objective of Phase 2 will be to achieve similar or better per-formance for more extended operations. Developing control methods for automatic operation is another. Phase 1 activities also included computer simulations of the reactor, manufacturing cost studies of the reactor and recuperator (for preheating reactor feed stream with reactor product stream), and laboratory investigations of reaction catalyst durability and regenera-tion. The results of these activities have identified several design changes for im-proving performance and reducing cost that will be implemented in Phase 2.

Phase 2 will use the same concentrator as Phase 1, which is a quarter of the size of Infinia’s commercial-scale unit, but an im-proved reactor design. During Phase 3, the reactor and recuperator will be scaled up to match a commercial-scale concentrator. If all goes well, the system will be ready for commercial demonstration in 2016.

—Contributed by Daryl Brown ([email protected]), a senior staff engineer at

the Pacific Northwest National Laboratory.

POWER DigestJordan Picks Russian-Built AES-92 For First Reactor. Jordan in early November chose Rosatom’s reactor export subsidiary AtomStroyExport to supply AES-92 nucle-ar technology for its first nuclear power plant. Rosatom Overseas will be strate-gic partner and operator of the plant. The plant’s financing has yet to be finalized, but an official of the Jordan Atomic En-ergy Commission (JAEC) told local media that Russia could contribute at least 49% of the project’s $10 billion cost with the remainder from the Jordanian government. The first reactor of the two-unit plant could begin operating in 2020. The JAEC had narrowed down possible vendors for the plant to an Areva-Mitubishi Heavy Industries consortium for the ATMEA 1 and Russia’s AtomStroyExport for the AES-92 or VVER-1000.

RWE Shelves 1.2-GW Atlantic Array Project. RWE on Nov. 26 halted develop-ment of the 1.2-GW Atlantic Array, one of the UK’s largest offshore wind farms, citing technical challenges that made the proj-ect “uneconomic.” The facility planned in southwestern England would have featured 240 wind turbines, but it had faced fierce opposition from environmental and heri-tage groups, which said the 722-foot-high turbines could cause lasting damage. RWE Innogy said technical challenges within

the Bristol Channel Zone are “significant,” pointing to substantially deep waters and adverse seabed conditions. “Costs to over-come such technical challenges are pro-hibitive in current market conditions,” it added. RWE also said, however, that it will continue building the 576-MW Gwynt-Y-Mor offshore wind farm in the UK, a project that is slated for completion in 2014. Re-newables made up 15.5% of the UK’s total generation portfolio in mid-2013. The gov-ernment wants to meet 30% of its electric-ity needs with renewable power by 2020.

Italy Looks to Sell Eni Stake. Italy’s government on Nov. 21 approved plans to sell up to €12 billion ($16.13 billion) in assets, including a 3% stake worth €2 billion in energy giant Eni, in an effort to ease austerity measures and cut its na-tional debt. The electricity sector in Italy was nationalized in 1962 with the creation of the state-controlled generation, trans-mission, and distribution company ENEL. In 1999, the sector was liberalized with the Bersani decree. In 1995, the Italian government sold a 63% share of Eni earn-ing €21 billion. The Treasury and the pub-lic Cassa Depositi e Prestiti own a 30.1% stake in Eni, which is a power generator in addition to engaging in a number of oil and gas operations. Eni’s installed power generation capacity was 5.3 GW at the end of 2012, which represents a fraction of the country’s total installed capacity of about 118 GW.

Malaysia to Increase Electricity Tar-iffs by 15% in 2014. Electricity charges in peninsular Malaysia will increase by 14.89% on average in 2014 as part of “subsidy rationalization” measures out-lined in the country’s annual budget, the country’s energy minister, Maximus Ong-kili, said on Dec. 2. Prime Minister Najib Razak’s budget announced in October tar-geted cuts of 15.6% in the government’s total subsidy bill in 2014. It also calls for a new consumption tax that could be en-acted in 2015. The tariff hike is expected to save the government $1.25 billion in subsidies next year, even though 71% of consumers in peninsular Malaysia would be affected by the increase due to exemp-tions for low-income Malaysians.

Vietnam Implements New Electricity Law. Vietnam in late October issued a de-cree implementing the “Law on Electricity,” which essentially provides a master plan for investment in electricity development, power purchases and sales, power prices, power operating licenses, and state admin-istration of power activities and power use. Under the decree, the country’s master plan

on power development will be amended ev-ery five years or in shorter cycles. The Min-istry of Industry and Trade (MoIT) will carry out the preparation and approval of a proposal and cost estimate to amend the national master plan. MoIT will also admin-ister the master plan and guide preparation of an annual plan on investment in electric-ity development. Among its key attributes, the decree requires investors in generation projects to provide adequate funding for site clearance, compensation payment, and relocation and resettlement assistance. It replaces Government Decree 105/2005/ND-CP (17 August 2005). For more on Vietnam’s power sector, see “Vietnam Works Hard to Power Economic Growth” in POWER’s March 2012 issue at powermag.com.

India’s NHPC to Commission De-layed Hydro Projects by 2018. India’s largest hydro power producer NHPC ex-pects to commission five projects of more than 3,800 MW that have been mired in environmental or contractual gridlock by 2018. The projects include the 2-GW Sub-ansiri Lower project in Assam, which was expected to be commissioned by Decem-ber 2012 but will now likely come online by December 2017. The controversial proj-ect’s costs have doubled since 2002 to an estimated $1.9 billion because it has been held up by issues about the dam’s safety and downstream impact, NHPC said. The 520-MW Parbati-III project in Himachal Pradesh, which was stalled due to contractual issues, will now be commis-sioned in March 2014—a delay of more than three years. The 800-MW Parbati-II, which should have been commissioned this March, is now scheduled for commis-sioning in March 2018. The 160-MW Teesta Low Dam Project-IV in West Bengal and the 330-MW Kishanganga in Jammu & Kashmir are to be completed by November 2014 and November 2016, respectively.

Brazil Could See $8B Grid Boost.Brazil’s energy research agency Empresa de Pesquisa Energética (EPE) predicts that the country will need to spend up to $7.8 billion to build more than 13,000 kilometers of new transmission lines and 39 substations by 2018 to ensure grid re-liability. The Transmission Expansion Pro-gram announced on Nov. 26 will be open for bidding in 2014. The country is looking to mitigate delays affecting expansions to the National Interconnected System. The projects outlined by the EPE refer to proj-ects whose feasibility studies have been completed but not yet bid. ■

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

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Upgrading a Wired Public Address System with a Wireless Option

The management at a 1,094-MW coal-fired power plant in the Midwest sought to aug-ment their hardwired public-address (PA) system. With hundreds of employees work-ing in varied conditions, a means of com-municating messages to everyone on site was needed, whether their normal daily activities were limited to a few blocks or if they traversed the entire 200 acres and multiple buildings. What the plant found was a wireless PA system so effective that it actually supplanted the original model.

A Mixed BagCommunications in this facility, as in many plants where components are added over the years, was a mixed bag. There was a hardwired PA system in place, but the staff wanted to supplement it with a system that could interface with it. The new system had to be loud enough to be heard by employees wearing hearing pro-tection, but soft enough for those working in confined areas like trailers or offices.

Messaging had to be broadcast through-out the 200-acre facility, even reaching employees who might be traversing de-commissioned areas of the plant. Addi-tionally, many (though not all) employees carry portable radios, which needed to be integrated into the new system. As an added wrinkle, the plant was planning to upgrade to a digital radio system and wanted the ability to integrate the new radios into the supplementary PA system. Given the many nuances of the “messag-ing footprint,” coupled with installation concerns and pricing questions, the proj-ect was neither routine nor easy.

Site officials contacted Cardinal Wire-less, which supplied a demonstrator model of a Ritron LoudMouth wireless PA system to test at the facility. Plant and Cardinal Wireless representatives toured the site, stopping in areas where communications were a concern—like those with high am-bient noise, elevated temperatures, and the decommissioned areas. After the dem-onstration, the company decided to pro-ceed with the system.

Installation Benefits of a Wire-less SystemInstallation of the wireless PA system was far simpler than for a traditional hardwired

PA and was accomplished at a fraction of the price. Still, one challenging aspect was finding suitable mounting surfaces.

Though the facility has abundant I-beams and catwalks, it was not replete with flat mounting surfaces. So instal-lation crews from the local electrical contractor used beam clamps and other innovative methods to secure the wireless speakers (Figure 1). Each installation, in the absence of a difficult mounting sur-face, took about 30 minutes.

Significant time was saved due to the wireless nature of the product, which avoid-ed trenching and re-wiring the entire facility. Installation costs were reduced by eliminat-ing the need for thousands of feet of copper wiring and the labor required to install it.

Can You Hear Me Now?The wireless system did not sacrifice sound volume or clarity. Recall that many of the employees are equipped with two-way ra-dios, so it could be argued that reaching these personnel would be more effective with a radio broadcast than with a tradi-tional PA announcement.

Areas with high ambient noise posed additional problems because employees in these areas wear foam ear inserts to protect their hearing. Again, the wireless nature of the system makes it easy to add additional speakers to ensure that messages are clear-ly audible even when employees are wear-ing hearing protection (Figure 2).

Wireless PA Speeds Response TimeAnother advantage is that the LoudMouth allows faster response times because of its ability to make announcements through the two-way radios from a nonspecific lo-cation. Previously, personnel would have had to travel to one of the PA stations to make an announcement. With the wire-less system, any radio-equipped employee can make an announcement, eliminating travel time and allowing emergency mes-saging to occur in real time.

Flexibility Yields Additional BenefitsBecause portions of this plant built in the 1920s, many areas posed a challenge for locating PA speakers. There were portions of the plant that had been decommis-sioned but through which personnel rou-tinely travel, so these were included in the messaging footprint.

Certain areas of the cavernous facility were where the flexibility of the speak-er installation really came into play. Some of the zones had large open areas where speakers needed to be located. In some instances, installers were able to locate speakers on alternate floors and still achieve adequate coverage. In other cases, there were rooms within rooms, so they had to deal with each area individually.

1. Public address speakers mount-ed on an I-beam. Courtesy: Ritron Inc.

2. Public address speakers mount-ed in a high-noise area. Courtesy: Ri-tron Inc.


The ability of each receiver to support two PA speaker horns was helpful in cus-tomizing areas with appropriate sound levels. With two speaker horns installed, and though effective sound pressure level is reduced by half, the PA speakers can each be positioned independently—for example, 180 degrees from each oth-er—providing added flexibility to cover more areas with a single installation point (Figure 3).

Each receiver can be fine-tuned for volume as well, depending upon ambi-ent noise and environmental conditions. Speaker volume was set at 90% for the first 225 speakers installed, though those in office areas or control rooms were much lower. Following some complaints, volume was turned down in four or five areas—mainly job trailers and control rooms—while speakers in areas like the gas turbine facility continue to blast their messages at a high level.

While many of the receiver installa-tions are protected from the elements, those that are not can be put into all-weather boxes. It is also possible to place them within National Electrical Manufacturers Association enclosures, when necessary.

Nuts and Bolts of the InstallationThe contract was signed in November 2012 and the project—including 300 speakers—was delivered in January 2013.

The facility uses approximately 100 por-table radios with two or three repeaters, providing four or six talk paths. This Loud-

Mouth system uses one analog repeater, which provides communication capability throughout the facility based on its stra-tegic location.

The new wireless PA system has been so successful in delivering messages that it has supplanted the hardwired system that it was originally intended to aug-ment. It was installed in much less time and at a fraction of the cost of a tradi-tional hardwired PA system. In addition to delivering audible messaging through-

out the 200-acre, multi-building facility, each receiver is fine-tuned to the ambi-ent noise and working environment in which it is located. This allows delivery of routine and emergency messages—in real time—to all of the facility’s hun-dreds of employees, regardless of where they work. And although the time and cost savings are important, the ability to safeguard employees is the most impor-tant aspect of the new system. ■

—Steve Rice is president of Ritron Inc.

3. Public address speakers posi-tioned 180-degrees. Courtesy: Ritron Inc.

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ELEMENTSWE’RE ENHANCING THE

OF STRENGTH.



Steven F. Greenwald Jeffrey P. Gray

Financial Performance–Based Utility Bonuses: Unnecessary Exposure

A series of derivative lawsuits has recently been filed against the officers and directors of Pacific Gas and Electric Co. (PG&E) based on the explosion of a PG&E gas transmission

line in San Bruno, Calif., in September 2010. The incident caused eight deaths and destroyed approximately 35 homes.

Derivative lawsuits are brought on behalf of a company’s shareholders. They assert that management’s breaches of their fiduciary duties and other misdeeds have financially harmed the company’s owners (the shareholders) and request that the court order the defendant management to alter their ways.

Misdirected Incentives Expose UtilitiesThe allegations highlight important utility industry issues that transcend the San Bruno explosion—to what extent should bo-nuses for utility management be based on financial performance? In economic theory, correlating bonuses on financial perfor-mance should incent utility managers to benefit ratepayers by increasing operating efficiencies and implementing cost-saving measures. Conversely, rewarding financial performance exposes utility managers to claims of sacrificing safety.

The plaintiffs argue that the tragedy at San Bruno was precipi-tated by the emphasis on financial performance that the PG&E Short-Term Incentive Plan (STIP) offers management. Prior to San Bruno, PG&E based 50% of STIP bonuses on financial perfor-mance (the remainder reflected safety and customer satisfaction criteria). The lawsuits contend that PG&E inappropriately reduced maintenance and other infrastructure expenditures to meet fi-nancial performance criteria.

Plaintiffs allege that PG&E “diverted” more than $100 million intended for natural gas pipeline maintenance to other purposes, including bonuses. Bluntly stated, plaintiffs accuse PG&E manage-ment of intentionally sacrificing public safety for company profit and personal gain. Plaintiffs contend that linking company financial achievement and personal compensation made a San Bruno–magni-tude catastrophe inevitable: “It was not a question of if there would be an explosion, it was only a question of when and where.”

The lawsuits accuse PG&E management of promoting “an at-mosphere and culture in which short term profits, cost cutting, and personal profiteering was put ahead of the proper manage-ment.” Plaintiffs ridicule a particular PG&E “backwards” incen-tive program, alleging it rewarded employees for electing not to “report or fix leaks, or otherwise report any dangerous conditions that would cost PG&E money to fix.”

This article does not comment on the possible (or lack of) merits of these allegations; the objective is to alert the utility in-dustry that it must extricate itself from the untenable position of defending against accusations that senior executives sacrificed safety for personal profit.

Utilities Are Different The economic theories that cost cutting should increase profits and that shareholders should correspondingly reward management

for increasing profits makes sense for most unregulated industries. However, an initiative by Apple or Ford to cut costs to increase profits is constrained by the reality that any resulting decline in product quality risks a decrease in sales and revenues, and corre-spondingly, profits. Thus, economically rational entities cut costs only if they can produce the same product at a lower cost or be-lieve that consumers will continue to purchase a lesser product.

In contrast, the captive customer base within its exclusive service territory enables a utility to reduce operating costs, es-sentially without risk of customer loss due to product decline—customers cannot forsake electricity and have extremely limited alternative purchase options. Moreover, when expenditures are cut on maintenance of infrastructure, the utility customer has no notice of the resulting deterioration of service.

Zero Tolerance for Financial Performance-Based BonusesOver the last several decades, utility compensation has tended to mimic financial and technology companies, transitioning pay from almost all salaries and benefits to appreciable per-centages of total compensation being bonus-based and the bonus in part being based on financial performance. For in-stance, even after San Bruno, PG&E’s STIP remains based at 30% on financial performance.

The best industry practices and stringent regulatory oversight should reduce the occurrence of accidents such as San Bruno. However, the combination of aging infrastructure, population growth, and increased demands on existing facilities renders it statistically likely that a tragedy of the magnitude of the San Bruno explosion will again occur.

In the wake of the San Bruno event, utilities must appreci-ate that even the slightest nexus between “cost cutting” and executive bonuses poses undue risk. The California Public Utili-ties Commission and likely the courts will ultimately determine liability for San Bruno. Regardless of the outcomes, plaintiffs’ arguments that PG&E’s management sacrificed safety for personal gain will continue to attract disparaging headlines, incite critical political rhetoric, and encourage additional legal actions, wheth-er the financial performance component in the incentive program is 50%, 30%, 10%, or even less.

Utilities would best serve their customers, employees, and shareholders by eliminating company financial performance as a criterion for bonuses altogether. Financial incentives for util-ity management and employees should be based on safety, reli-ability, and customer satisfaction. The public relations and legal nightmare PG&E confronts daily in the media, legislature, regula-tory agencies, and the courts should persuade utility executives to demand “zero tolerance” and totally delink financial perfor-mance from incentive compensation programs. ■

—Steven F. Greenwald ([email protected]) and Jeffrey P. Gray ([email protected]) are partners in Davis Wright Tremaine’s

energy practice group in the firm’s San Francisco, Calif., office.

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2014 INDUSTRY FORECAST

A Rising Tide of Regulation and the “Kick-the-Can” Gambit An array of federal regulation is coming down the pipe in 2014, but whether any of this represents real change remains to be seen.Kennedy Maize

A tidal wave of pent-up federal regula-tions could surge across much of the electricity industry in 2014.

In recent years, Congress has been unable to enact new laws in energy, which has led a frustrated executive branch to substitute the slow-motion process of regulation for new legislative authority. The judiciary has be-come deeply involved in second-guessing the executive branch and Congress, introducing new delays in policymaking. In Washington, this pattern of active inaction has become known as “kicking the can down the road.”

While 2014 likely will be busy, that does not mean that major new rules will be firm-ly in place at the end of the year. The tools of delay remain available to partisans and policy advocates of all stripes. In the most complex and contentious rulemakings, such as carbon dioxide reductions from coal-fired plants, new rules won’t be scheduled for full implementation until 2015 and 2016. Court challenges could easily boot any resolutions further into the future.

Complicating this picture is that 2014 features a midterm election. All 435 seats in the House of Representatives are in play (at least nominally), along with a third of the 100-member Senate. The partisan balance of power in Washington is tenuous. All sides will scrutinize upcoming executive branch rules and regulations not just for their sub-stance and economic impact but also for how they play politically.

Environmental Protection AgencyAs has been the case for many years, the U.S. Environmental Protection Agency (EPA) will be the locus of the most contentious regula-tory battles impacting the electricity sector in 2014. At the top of the EPA’s agenda are a brace of rules aimed at reducing carbon di-oxide emissions from power plants, known to many of the combatants as the “war on coal.” But the metaphorical rhetoric may be overstated, as coal’s real troubles today are a product of market forces, including the rise

of natural gas and lagging demand for new electricity. The EPA’s new regulations will add to the weight, but they may not prove decisive.

Nonetheless, the EPA, lacking new legis-lative authority, is attempting to use the 1990 Clean Air Act as the foundation for limits on CO2 emissions from both new and existing coal plants. President Obama outlined his ap-proach last June, calling for a regulatory as-sault on carbon dioxide emissions.

The EPA has already rolled out its plan for new plants. In September, it arrived at a somewhat-altered proposal from one an-nounced in April 2012. Under the Septem-ber plan, new coal-fired plants must meet a limit of 1,100 pounds of CO2 per MWh and use carbon capture and storage as the “best available control technology.” These rules are likely to be the first the EPA promulgates this year for carbon reductions, probably in the first quarter.

But the rules for new plants, yet to be published, face congressional and legal road-blocks. The U.S. Chamber of Commerce is pushing legislation, sponsored by Sen. Joe Manchin (D-W.Va.), and Rep. Ed Whitfield (R-Ky.), to scuttle the carbon capture and sequestration requirements as unachievable. Coal interests will also challenge the EPA rules in federal court. They argue that carbon capture and sequestration technology is not proven, so the EPA rule is invalid.

Complicating the subject is a recent find-ing from the House Energy and Commerce Committee that the EPA’s conclusion that carbon capture is a commercially proven technology may be illegal. The committee in late November sent the EPA a letter assert-ing that provisions of the 2005 Energy Policy Act say the EPA may not base a determina-tion that a coal technology is commercial if the projects on which that determination is based have been funded by the Department of Energy’s (DOE’s) clean coal technology program. According to the letter, all three of the projects the EPA has cited have received

DOE clean coal funds. The EPA is on a slower schedule for its plan

for existing plants. This rule is likely to reach deeper into the ways the industry operates and the prices consumers pay for electricity, because coal remains the major generating fuel in the U.S., with about 40% of the mar-ket. While utilities are willing to close older plants that are no longer competitive, they are unwilling to shutter viable plants that the new regulations, by themselves, would render ec-onomically unproductive.

The structure of the Clean Air Act makes it difficult for the EPA to come up with clear and consistent rules for existing units, according to many analysts. The agency must work through state governments to implement its rules, and many states—particularly those with large coal producers or generators—are unlikely to go easily into the new regime. So the agency will have to negotiate many different state ap-proaches to carbon dioxide reductions.

That sets up a nasty political collision. In the meantime, the EPA is under White House orders to come up with the plan for existing plants by June 1 and implement them a year later, with the rules going into effect by June 30, 2016. At that point, Barack Obama will have long been a lame duck president. Much of the nation’s attention will be focused on who will replace him.

Several industry groups have made it clear they will sue to overturn the rules for existing plants. Litigation will add more uncertainty and more delay.

Climate rules are not the only big-ticket items on EPA’s Clean Air Act agenda that have an impact on electricity. Ozone pollu-tion crossing state boundaries, a thorny issue that goes back to before the second Bush ad-ministration, is still a regulatory uncertainty. The U.S. Supreme Court is likely to weigh in on the topic early this year. The D.C. Cir-cuit Court of Appeals has rejected both the Bush administration’s plan for cross-border pollution and the Obama administration’s somewhat different follow-up on the topic,




known as the Cross-State Air Pollution Rule (CSAPR). Once the high court rules to unravel the legal knot it has tied for itself, that’s likely to kick off a regulatory sprint at EPA to put something in place that will satisfy the court.

Next comes regulation of coal ash stor-age, a vexing non-air EPA issue long en-tangled in the courts. The EPA has toiled for years on new rules for coal ash disposal under the Resource Conservation and Re-covery Act. The impetus for the regulation comes from a massive 2008 collapse of a coal ash pond belonging to the Tennessee Valley Authority. Following four years of EPA regulatory wheel-spinning, environ-mental groups in 2012 sued the agency to expedite an agency rulemaking. Late last year, U.S. District Court Judge Reggie Walton gave the agency 60 days to publish a plan and schedule for final rules. The litigants will be poring over the EPA plan early this year. Action may kick off again in the first or second quarter.

Nuclear Regulatory CommissionThe EPA is not the only federal agency with an agenda driven by court oversight of its ad-ministrative actions. The Nuclear Regulatory Commission (NRC), and its predecessor, the Atomic Energy Commission, for half a cen-tury have been entangled in the tendrils of nuclear waste disposal policy. Today, spent fuel from power plants is again at the top of the agency’s regulatory agenda.

The NRC is under order from the D.C. Circuit to resume licensing activities at the Yucca Mountain site in Nevada, which the Obama administration and the NRC have largely abandoned. In a 2-1 decision in Au-gust, the court said the NRC did not have the authority to halt its licensing proceed-ings. The court said that the president “may not decline to follow a statutory mandate or prohibition simply because of policy objec-tions.” So the agency is restarting review of the underground activities at the site.

But the NRC is caught in a bureaucratic and political trap. Congress has never repealed the 1982 Nuclear Waste Policy Act and the 1987 amendments that singled out Yucca Mountain for storing the nation’s high-level nuclear waste. But Congress has also not appropriat-ed any money for the NRC to move forward, driven by the opposition of Senate Majority Leader Harry Reid (D-Nev.), and the Obama administration to the Yucca Mountain project. NRC Chair Allison Macfarlane has said her agency has only about $11 million in hand for Yucca Mountain activities, a pittance given the scope of the regulatory activities required for licensing. Nevertheless, the NRC in late November ordered a restart of the licensing

for the Nevada repository. But shortly afterward, the same court

threw another monkey wrench into the pro-cess. The D.C. Circuit said the federal gov-ernment no longer has any justification for collecting a 1 mill/kWh fee on consumers of nuclear power to fund the waste program, be-cause the DOE has essentially abandoned it. The court ordered the DOE to ask Congress to zero out the fee. But Congress is not likely to act, since the $750-million-per-year fee is used to finance general government activi-ties, not the nuclear waste program.

Meanwhile, the blowback from the March 2011 catastrophe at Japan’s Fukushima nu-clear station continues. The NRC is imple-menting a series of regulatory tweaks from its examination of the disaster. The units that melted down were of the same design as many General Electric boiling water reactors in the U.S.

Macfarlane recently told the American Nuclear Society, “We’re reassessing our licensees’ ability to mitigate seismic and flooding events and requiring them to en-sure adequate emergency response training and communication to cope with prolonged accident conditions. They’re strategically placing backup equipment on-site to help maintain reactor cooling in the event of a loss of power. We’ve also required enhanced instrumentation to better measure the water level in spent fuel pools. While many of these activities are well on their way to com-pletion, we’ll need to address some items through rulemaking at our agency.”

Federal Energy Regulatory CommissionWhile the Federal Energy Regulatory Com-mission (FERC) flies under the public atten-tion given to the EPA and the NRC, FERC’s activities have major impacts on the electric-ity sector. That looks like a pattern that will persist in 2014.

The agency in November gave final ap-proval to the latest version of the North Amer-ican Electric Reliability Corp.’s (NERC’s) Critical Infrastructure Protection (CIP) stan-dards, which will begin to go into place in the spring. These are the fifth generation of rules designed to protect the bulk electric system from cyberattack. CIP 5 takes a new, more-integrated approach. Prior rules on cy-bersecurity were often formalistic, checklist-oriented procedures that both NERC and the National Institute of Standards and Tech-nology found cumbersome and ineffective. FERC Commissioner John Norris described the new CIP standards as shifting “from man-aging compliance to managing risk.”

CIP 4 was scheduled to go into effect this April, but FERC decided that CIP 5 was such

an improvement that it gave a green light for the latest version to hopscotch over version 4. The latest rules will see phased implemen-tation, although the commission has not yet decided on a timetable. The proposal will re-quire three years to become fully implement-ed. The commission wants public comments on that schedule, hoping to collapse it some-what. While highly technical, the cybersecu-rity rules, in FERC’s judgment, are among the most important facing the utility industry and the nation in the years ahead.

Also on FERC’s regulatory agenda is NERC’s implementation of a commission order aimed at protecting the grid and ma-jor infrastructure depending on electric grid services from solar storms and geomagnetic disturbances. The commission had in mind the 1989 solar storm that damaged grid in-frastructure from Canada to the Middle At-lantic states, including major blackouts and millions of dollars to transformers and grid support equipment.

FERC’s May 2013 Order 779 has two phases. Phase one charges NERC with com-ing up with day-to-day actions that system operators can take, such as instituting new procedures or training staff, to protect the grid in the short term. The second phase of the FERC order focuses on hardening equip-ment and identifying engineering protections that go beyond soft training and procedures. NERC must come up with “benchmark” standards regimes for utilities to protect against geomagnetic storms. These should be tailored to utility specifics, such as geogra-phy or the configuration of the utility system.

Like It? Share It!Did you know that you can easily share links to your favorite POWER print and digital-only stories via social media using the colorful widgets on powermag.com? During the month of November, our story on Top Plant Award-winner Bruce Nuclear Generating Station was the most shared award article while “Electrical Area Classification in Coal-Fired Power Plants” was the most shared overall!



Then each utility must develop a plan to deal with the benchmark solar flux events.

FERC adopted the new solar flare rules in anticipation of a round of higher solar activity. The 11-year solar activity cycle suggested that 2012–2014 would see a burst of solar flares. While things started slowly, NASA at the end of November re-ported a surge of major activity, including a strong solar eruption, not directly aimed at Earth, which caused a brief but wide-spread radio blackout.

FERC could become a wild card this year, providing some regulatory and politi-cal surprises. Chairman Jon Wellinghoff, an aggressive regulator, departed in late No-vember. That leaves the five-member com-mission at a 2-2 partisan tie, with Cheryl LaFleur, the most senior Democrat, as act-ing chairman. The agency has generally avoided the political rancor of the rest of Washington over the past few years, but there are still important ideological splits between the Democrats and Republicans on the commission, particularly over the role of state regulators in the federal system.

Following the failed nomination of for-mer Colorado regulator Ron Binz, the White House has shown little interest in FERC. Under the law, the commission has five members, with a majority and the chairman appointed by the president. Whether the deci-sion by Senate Democrats to end filibusters on most executive branch nominees will has-ten action on FERC appointments is unclear at this writing.

The timing for FERC appointments could be tricky. LaFleur’s term is up in June, so the administration must come up with re-placements for both her and Wellinghoff (she could be reappointed). Traditionally, the White House, regardless of party, has tried to pair partisan nominations to FERC, matching a Democrat and a Republican nominee. That won’t be possible this year with two Demo-cratic seats in play. So a 2-2 division could remain for some time.

One topic has proven to be divisive: Order 1000, Wellinghoff’s signature accomplish-ment, which requires regional coordination and planning of interstate electric transmis-sion. The commission’s two Republicans,

Philip Moeller and Tony Clark, have consis-tently objected to major aspects of the order, including its revocation of the long-standing precedent that incumbent transmission pro-viders can direct the process through a pre-sumption of the “right of first refusal” in transmission cases. With Wellinghoff gone, Moeller and Clark may try to convince LaF-leur or John Norris, a Democrat who is also a former Iowa utility regulator, to reexamine the issue.

Follow the Bouncing CanAll told, 2014 looks like a year with plenty of regulatory action in Washington. Will the regulatory churning, which provides full em-ployment for many inside the Washington beltway, result in real changes in behavior on the part of electric companies, investors, or consumers? Or will Washington resume its characteristic game of delay, booting issues down the road for decisions or delays by fu-ture administrations and regulatory agencies? Follow the bouncing can. ■

—Kennedy Maize is a POWER contributing editor.

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2014 industry forecast

Black & Veatch Foresees U.S. and Global Opportunities Dean Oskvig

B lack & Veatch expects sustained growth across global energy markets in 2014 with several ongoing themes

continuing. Key market drivers support-ing power infrastructure spend remain the same, centering on emerging market growth, regulations (including clean air and water), aging infrastructure, and the advancement of unconventional gas tech-nologies. Competition will continue glob-ally as engineering and construction com-panies grow backlog in traditional markets and with global expansion.

The U.S. Outlook Is ImprovingIn the United States, modest demand for new generation capacity will primarily be met with natural gas and solar photovoltaic generation given regulations, renewable port-folio standards, and other market dynamics. U.S. transmission market investment will be strong at nearly $200 billion from 2014 to 2023. The continued upgrade and expan-sion of existing infrastructure, presence of renewable resources, and Federal Energy Regulatory Commission Order 1000 are key contributors to sustained growth.

Opportunities to support clients in their efforts to improve reliability and efficiency, as well as upgrade facilities and expand the use of renewables/distributed generation—all while keeping costs competitive—will be significant. The air quality control retrofit market will be driven by owners’ decisions to upgrade assets or retire them altogether.

Industry observers anticipate that 2014 will bring improved economic growth in the U.S. as well as a collision between coal-fired plant shutdowns and system-supply reliabil-ity. Several years of weak overall demand growth, hindered by the slow pace of eco-nomic recovery, have held reserve margins in check. Without GDP recovery, margin overhang will persist through 2020 in most regions of the U.S., except the Electric Reli-ability Council of Texas.

Projections of exactly how many giga-watts of coal-fired capacity will come of-

fline through 2020 in the U.S. vary, but one thing is certain: The economics associated with continuing to operate coal assets and upgrades to preserve life will remain in fo-cus. A large-scale shift away from coal to natural gas and renewables will require so-lutions ranging from new pipeline and trans-mission development to energy storage and increased use of on-site liquefied natural gas (LNG) storage to ensure system reliability.

Global FactorsGlobally, there are several factors shaping the 2014 power outlook. While estimates vary, roughly $12 trillion will be spent on power infrastructure around the world from 2014 to 2020, according to IHS Global In-sight. Worldwide, we are witnessing the larg-est economic transformation ever seen as the population of cities in emerging markets expands and incomes rise—producing a size-able wave of middle-class consumers with spending power. As such, rapid urbaniza-tion will be the biggest worldwide driver of infrastructure spending over the next several decades as urban populations expand by 1.5 billion, to 60% of the world’s population.

On the demand side, the tsunami-related Fukushima Daiichi event in March 2011 con-tinues to impact the future of many nations’ energy mixes. From Germany to Japan, nu-clear power remains under scrutiny. Although safeguard efforts continue at many existing U.S. facilities for Nuclear Regulatory Com-mission compliance, new build programs are proceeding with caution in the U.S. and else-where. Economics-based retirements are also a consideration.

Gas, as a cleaner alternative to coal and oil, and more suited to baseload power gen-eration than renewables, likely has the most potential for sustained long-term growth. Worldwide interest in reducing greenhouse gas emissions and improving air quality, as well as global efforts to increase fuel diver-sity, will drive continued investments in ex-ploration, LNG import terminals, and supply contracts. Gas-rich regions, the countries that

produce gas cheaply, prefer to sell it at high value rather than generate electricity with it. Therefore, gas processing and LNG export projects represent a strong market opportu-nity as gas moves from those who have it to those who need it.

In addition, $3.50 to $4.00 per MMBtu for U.S. shale gas means domestic project opportunities in gas processing, floating LNG/LNG storage, ammonia processing, and continued growth in the transportation LNG market.

Yet, natural gas alone will not meet the world’s power generation needs, particularly in developing regions experiencing load growth ranges from 3% to 5% and more. As such, significant new generation opportunities, pri-marily low-cost coal fuel, will be sought near term. These new capacity opportunities also carry follow-on opportunities to expand power delivery services in transmission, distribution, and grid stability.

Workforce TrendsIn addition to project work, two other trends to monitor in 2014 include the pace of per-sonnel retirements across the energy industry and continuing skills and knowledge transfer (SKT) efforts. A large number of workers in developed regions are at or nearing retirement age, and their departure will mean experience gaps in many critical positions. Conversely, developing regions are furthering SKT pro-grams to grow the pipeline of technically trained, indigenous workers, thereby reduc-ing expat dependence.

Whatever 2014 may bring, Black & Veatch is optimistic about the global power industry and the company’s future. Plan-ning and implementing the world’s most complex infrastructure projects and man-aging the significant realignment of re-sources and infrastructure needs will create opportunities for engineering and construc-tion firms capable of providing sustainable energy solutions. ■

— Dean Oskvig is president and CEO of Black & Veatch’s Energy Business.



2014 Industry Forecast

How U.S. Power Generators Are Preparing for 2014Pundits, journalists, and researchers can opine about what the future holds for power generation, while engineering, equipment, and service companies can comment on how their businesses are building for the new year. But in the end, it’s generating companies that must address complex, ever-changing realities and keep the power flowing.Gail Reitenbach, PhD

The business environment for generat-ing companies worldwide continues to become increasingly complex, and

not just as a result of regulations. Even in the U.S., the concerns and constraints faced by generators are many and varied. Some, like new federal regulations, are shared by all. Others derive from regional and state-spe-cific factors. To provide our audience with a big-picture view of what some major power producers see in the year ahead, we have de-veloped a new partnership.

The POWER Generating Company Ad-visory Team consists of a variable number of seasoned industry leaders who have both power plant management experience and higher-level business side responsibilities. Members agree to serve two-year terms, con-tribute their insights to our January forecast-ing issue, and consult with the editor when we plan the coming year’s content calendar.

Our inaugural group includes represen-tation from three different North American Electric Reliability Corp. regions that have both shared and unique operating concerns:

■ Melanie Green, Director, Strategic Plan-ning & Analysis, CPS Energy

■ Randal S. Livingston, Vice President of Power Generation, Pacific Gas & Electric (PG&E)

■ Sharon Pfeuffer, Director and Chief Engi-neer, Fossil Generation, DTE Electric

In mid-November, the team members responded via email to the following set of questions. Their comments have been edited for style.

Several federal and state regulatory changes will affect U.S. power producers in the coming year. Which ones are you and your company most focused on, and what do you expect their impacts will be?

Melanie Green: Obviously, as a power generator we are closely monitoring all the

pending environmental regulations that could significantly impact our business, for exam-ple, greenhouse gases (GHG), Clean Water Act 316(b), and coal combustion residuals being the highest visibility. While we par-ticipate in the process, we are also preparing project options to comply with the potential outcomes. Fortunately, we have seen some positive moves in terms of 316(b) compli-ance requirements here in Texas.

Additionally, as a member of the Electric Reliability Council of Texas, we are moni-toring the discussions surrounding resource adequacy and potential changes to market de-sign. Current issues revolve around incenting development of new generation in a very soft market, primarily driven by low gas prices and significant wind capacity.

Randal Livingston: At the federal level, we will be closely following the Environmen-tal Protection Agency’s (EPA’s) roll-out of the GHG new source performance standards. PG&E has one of the cleanest energy port-folios in the nation from a carbon standpoint and currently operates under California’s cap-and-trade program for carbon emissions.

At the state level, California will reach an unprecedented level of renewable portfolio standard (RPS) generation, led by solar, and the operational impacts of this are still being evalu-ated. PG&E will continue to work to integrate these intermittent resources into our customer supply, which will drive a need for greater flex-ibility on all electric resources in the state.

The California Public Utilities Commission also recently established a policy decision on a 1,325-MW energy storage target that the state’s largest investor-owned utilities must meet by 2020 through new storage facilities.

It is still too early to quantify the impact the storage mandate will have on the energy business, as some storage technologies are still in the early stages of deployment. What’s important to note is that energy storage is just one component in California’s overall strat-

egy of integrating renewables and that the comprehensive solution needs to be afford-able for customers.

Sharon Pfeuffer: We will be watching the EPA CO2 rules for existing generation sourc-es; we’re expecting the impacts to be sig-nificant for existing coal generation, and will favor gas generation. With the recent ruling in U.S. District Court as well as the Steam Electric Guidelines coming out of the Clean Water Act, we’re also expecting the EPA to move more quickly on ash regulations, which will certainly impact the cost of, and how, we manage ash at our coal-fired plants, as well as our wastewater streams.

Combining these regulations with Mercury and Air Toxics Standards (MATS) and National Ambient Air Quality Standards (NAAQS), as well as the economic realities of an aging fleet, we continue to look at our portfolio both for environmental compliance and reliable, cost-effective generation for the customers we serve.

It seems that every talking head is saying that the large U.S. shale gas re-serves and currently low natural gas prices are “game-changers” for the pow-er industry. How do you see the shale effect playing out in the next couple of years for your company?

Green: Texas has an abundance of shale gas, which is benefitting the consumer by keeping gas cost well below earlier forecasts. As we continue our move to a cleaner fleet, the ready availability of gas will maintain a dependable, long-term energy resource for the power sector and our customers.

Livingston: With short- and longer-term gas futures dropping, electric wholesale prices have likewise declined. This will continue to put pressure on some of the less-economic assets to either provide additional value (for example, operational flexibility), become more economic, or retire. Assets with greater degrees of flexibility and dispatchability can expect to be higher valued in the marketplace.



Pfeuffer: As gas generation becomes more competitive, there’s no doubt it will put increasing pressure on coal-fired genera-tion. As we look at projections on natural gas prices, coming regulations, and renewables, we will be firming up plans to add combined cycle gas generation to our fleet, probably early in the next decade.

What, if any, supply chain concerns does your company have for 2014?

Green: One change I have seen over time is the increased challenge of managing parts and goods deliveries with many of our plant com-ponents being sourced overseas. This can cre-ate significant delays in obtaining replacement parts and really forces us to become much bet-ter at inventory management. Identification of critical spare components and looking for new opportunities to “co-opt” with other utilities in shared ownership of large spare parts (like transformers) is one solution.

Livingston: Events like Hurricane Sandy and Katrina and other similar large-scale events have emphasized the need for mul-tiple supply chain sourcing. As a result, we are identifying additional suppliers in 2014 that can support our supply chain needs in the event that our vendors are not available to supply a product due to circumstances be-yond their control.

Pfeuffer: If I had to pick one, I would say vendor quality control. We’ve seen an increasing trend of reliability challenges re-lated to vendor QA/QC. This has had impacts across our company, in steam turbines, gen-erators, transformers, and wind. In response, we’re amping up our own efforts to monitor vendor quality.

Describe the anticipated changes to your fleet for 2014 in terms of additions, retirements, refuelings, and dispatch priorities.

Green: CPS Energy currently has an ex-tremely well-balanced and diversified fleet with nuclear, coal, gas, and significant re-newable capacity in terms of wind and solar. CPS Energy has committed to shut down two

of its large coal plants by 2018 and transi-tion towards highly efficient combined cycle natural gas plants. In addition, CPS Energy is the largest wind off-taker in the state, with over 1,000 MW in its portfolio, and is the largest solar off-taker, with nearly 100 MW in its portfolio and another 350 MW in devel-opment. This enables us to continue to serve our customers with a variety of products to keep costs low.

Livingston: There will not be any sig-nificant changes to the makeup of PG&E’s utility-owned generation fleet in 2014, but we can expect a number of changes in Cali-fornia’s electric supply overall. The recent retirement of San Onofre Nuclear Generat-ing Station (SONGS), the build-out of many new solar generation assets, primarily photo-voltaic (PV), and the addition of recent dis-patchable gas-fired plants will all change the face of daily dispatch. California is closing out of one of its driest years, and depending how 2014 shapes up, the water and snowpack could have a large impact on our available hydro generation.

Pfeuffer: We will be retiring our Harbor Beach Power Plant at the end of this year and will be idling Trenton Channel Unit 8 in 2014. We continue to optimize fuel blends that will lower cost to our customers and al-low us to be environmentally compliant.

If increased levels of renewable gen-eration in the territories you serve affect how you operate your generation fleet, what do you see as the results of those

operational changes in the near future?Green: CPS Energy has over 1,000 MW

of wind under contract and nearly 100 MW of solar in our portfolio. In addition, we are actively engaged in projects that will add an-other 350 MW of solar. We have a strong de-mand response program as well. All of these resources are components of a strong genera-tion plan. Regardless of how much renewable generation is available, as of today, it is still an intermittent source. We must manage our baseload fleet to provide the foundation ser-vices and continue to integrate our growing renewable commitments. To successfully ex-ecute on this plan, we must continue to do a great job of forecasting our demand.

Livingston: As an increasing proportion of new solar PV comes online to meet the RPS, California will see a dramatic increase in supply in the 0800 to 1600 timeframe. Other dispatchable generation will need to be able to ramp up and down around the daily “shoulder periods” and back down at noon. We are working towards increasing dispatch-ability of our own solar PV facilities and exploring how energy storage can support renewable integration.

Pfeuffer: We have continued to add to our renewable portfolio, primarily wind genera-tion in the “thumb” region of Michigan, and will meet our target of 10% renewable gen-eration by 2015. We’ve been able to integrate wind without measurable impact on the rest of the generation fleet.

What will staff in your power plants notice that’s different in 2014, and why—procedures, equipment, staffing levels, focus on enhanced physical and cyber security, other?

Green: We continue to focus on improving safety processes and procedures for our em-ployees and improving overall engagement. The coming year will include new training initiatives and opportunities for growth, con-tinued emphasis on knowledge transfer, and increased flexibility of our staff.

We will be focused heavily on becoming compliant with the North American Electric Reliability Corp. Critical Infrastructure Pro-tection (NERC CIP) version 5 standards and are looking at not only implementation but

“One change I have seen over time is the increased chal-lenge of managing parts and goods deliveries with many of our plant components being sourced overseas.”

—Melanie Green, Director, Strategic Planning & Analysis, CPS Energy

“We are working towards increasing dispatchability of our own solar PV facilities.”

—Randal Livingston, Vice President of Power

Generation, PG&E



also the additional training requirements to meet the standards.

With the announced retirement plans for two of our coal units, we are working to manage our workforce and staffing levels to prepare for that event. Recognizing that plant operations is a highly specialized skill set, we need to maintain high levels of performance and prepare for the shutdown in a manner that will enable us to continue to utilize that talent in our fleet.

Livingston: Our plant staff are already seeing the differences in dispatch with more cycling on and off, with units coming on later in the day. They are being continually challenged to provide better turndown char-acteristics and faster ramping rates. We’re implementing new controls and procedures to help with this and the skills, knowledge, and ingenuity of our employees will be key in accomplishing this.

Pfeuffer: We will be adding activated car-bon/dry sorbent injection (ACI/DSI) to several of our plants as part of our MATS compliance strategy, and the equipment will start to show up at our plant sites in 2014. We will also be adding additional measuring/monitoring equipment to our flue gas streams to support our compliance efforts. As far as staffing, we’ll continue to try to match attrition to the changes that we see coming in our fleet, with a focus on the cost to our customers.

What workforce and training needs do you anticipate in 2014 and why?

Green: Results of employee surveys have indicated a strong desire for additional oppor-tunities. In response, we have recently rolled out our CPS University to further provide op-portunities for our team to improve both their technical skills and develop leadership skills. We have a robust e-learning program of computer-based training modules that works extremely well with our workforce, enabling

them to stay current on required training at their work locations. We find that investments in our staff development directly translate to improved performance and engagement.

Livingston: Skilled craft and technical workforce will continue to be in demand, both for employees and the suppliers who support this industry. We need to continue to bring in and train entry level employees and modernize our training programs to be relevant to both the technology and genera-tional differences we’re all experiencing. At the same time, we need to continue to be able to capture and pass on the knowledge and experience of our current workforce to a new generation.

Pfeuffer: We are taking a sharper, more focused look at the skills and training of our leaders. We’ve changed the training program for our new leaders and are now focused on our existing leaders. We’re putting a lot of our training focus on human performance (HP) and continuous improvement, as well as our regulatory required training.

Our training areas of focus include business and technical skills as well as soft skills, sup-porting our aspirations in the area of employee engagement. Our approach to professional development includes targeting knowledge transfer and how technology can be applied to facilitate this effort, redeveloping an in-house training program for difficult-to-staff positions like instrumentation and control (I&C) techni-cians, and linking HP events and resets to our professional develop of all employees. This very much includes a stronger effort towards our skilled trade positions.

What changes in how you interact with original equipment manufactur-ers (OEMs), engineer/procure/construct firms (EPCs), and other industry partners would be most helpful to you in 2014 and beyond? Do you have a wish list for products, services, or contracts?

Livingston: OEMs and other partners that work to understand our business and work with us in an open, transparent way will al-ways be valued. If a unit is down for an over-haul and we can’t verify where a critical part

is or when it’s due back, it’s a real problem. Partners that work with us to figure out how to do something rather than explain why they can’t will be valued.

I also think that our partners who collec-tively generate power for California and the nation can continue to work together better. Continuing to support our professional asso-ciations, their committees, work groups, and councils is critical for operating these facili-ties safer, more reliably, and more affordably for our customers.

Pfeuffer: We would like to see a much stronger focus on QA/QC, in addition to a fo-cus on cost. We’ve had several projects with significant performance challenges related to what we are calling “vendor quality.”

What other concerns keep you up at night when you look ahead to the new year?

Green: It’s always about the people. With so much change occurring in the power in-dustry, it is essential that we continue to maintain our focus on safety as our highest priority. Building strong work teams, encour-aging new ideas, and promoting creativity in how we accomplish our goals are all compo-nents of a healthy organization.

Livingston: This will be an exciting year for us in the West. It will be an important transition year in the expansion of California-certified RPS resources, a transition for some of California’s legacy resources, like SONGS, and some of the natural gas once-through cool-ing units, and if we have another dry hydro year, we’ll have some very unique challenges ahead of us. I know this industry is up for it!

Pfeuffer: We work really hard to mini-mize the environmental impacts of produc-ing electricity, while at the same time trying to improve costs for our customers, many of whom struggle to pay their bills. Balancing those two priorities is increasingly challeng-ing. I also worry about trying to capture the knowledge of the really talented people who are retiring, many of them with 35 to 40 years of experience in our industry. ■—Gail Reitenbach, PhD is POWER’s editor

(@GailReit, @POWERmagazine).

“We are taking a sharper, more focused look at the skills and training of our leaders.”

—Sharon Pfeuffer, Director and Chief Engineer,

Fossil Generation, DTE Electric

Building the 140-Turbine Macarthur Wind FarmThe remarkable 30-month construction of the A$1 billion Macarthur Wind Farm in Victoria, Australia—a December 2013 POWER Top Plant—is chronicled in a 5-minute video on the powermag.com homepage.


2014 Industry forecast

Burns & McDonnell Sees U.S. Market in Transition While Asian Market Grows

The U.S. power generation market is experiencing a unique set of transitional drivers, the biggest being the current economics within the energy market.

U.S. Market DriversA significant portion of the U.S. operates in a second-day energy mar-ket. There are some differences in how these markets operate, but the intent is to have a generator compete against other generation sources to provide low-cost power. Therefore, generators typically operate when there is the demand for power and the generator’s production costs beat the market price. Some markets also have a capacity market, which provides some revenue, but not sufficient to cover fixed costs. Supply and demand market principals are at work in these markets.

Another driver is the integration of intermittent renewables, which has accelerated the aggregation of load-balancing entities within the transmission independent system operators. While creating more effi-cient dispatch of generation resources, this transition more importantly mitigates the overall system impact from integrating intermittent wind and solar generation. This approach mitigates system ramping issues, but it also facilitates the ability of wind generation to operate profitably in these open markets at a negative power price (due to subsidies from production tax credits), greatly eroding profitable hours and capacity factors for baseload generation, particularly nuclear and large coal.

Those baseload sources are often required to run at less-than-opti-mum loads to balance renewable energy variability or, in the case of nuclear energy, run for many hours while production costs are higher than the market price. Generators with higher costs will operate little, if any, in a second-day market. Generating sources with higher fuel costs will be affected most. With current natural gas prices, many higher-cost Eastern coal units are particularly impacted.

Even if variable costs can be covered by market prices, little is left to cover financing fixed costs of large capital investments. This has

been demonstrated in a variety of recent decisions, including nuclear plant shutdowns, decisions not to pursue nuclear power uprates, shut-ting down coal plants instead of investing in environmental project retrofits (because doing so would make them less competitive in the marketplace), and market power prices that don’t even support com-bined cycle gas plants in many regions of the country.

In contrast, the larger power markets and renewables penetration has created market opportunities for projects addressing transmission con-straints and ancillary service markets, leading to a new class of flexible gas generation resources to balance wind. Some areas—where there is load growth demand or utilities are looking for a more even fuel genera-tion balance—will be building natural gas combined cycle facilities.

Another factor is that distributed generation is growing in many areas to the point where the traditional rate structures have changed. Electric utilities may not be providing continuous energy to the cus-tomer in these instances yet are still on the hook to provide occasional energy and maintain a reliable and safe infrastructure. That situa-tion has led to questions about the fairness of the rate structure being brought before state public service commissions.

In 2014, we expect these trends to continue.

Growth AbroadOn the demand side, little, if any load growth is occurring in the U.S., for a number of reasons, including more efficient appliances, industri-al processes, and other energy uses; distributed generation; lackluster economic growth; and demand-response programs. We expect muted load growth in the U.S. to continue in 2014. However, overseas mar-kets are seeing a large load growth increase, mainly in Asia, and these areas are providing opportunities for new, large baseload units.

The blessing of cheap natural gas forecasted for the U.S. market is unique within the world market. The Asian market continues to march forward with significant coal, nuclear and natural gas genera-tion projects.

While growth in some Asian countries is moderately constrained by world economic conditions, in many cases the growth of the middle class in these countries has led to increased demand that outstrips this constraint and results in a significant market opportunity. Burns & Mc-Donnell continues to leverage this growth and has greatly expanded our international presence and market, especially within Asia (Figure 1). The expertise gained in designing and building large-scale, highly effi-cient and environmentally exceptional generation facilities common in the U.S. market can be leveraged in Asian markets, as many countries now have grids of sufficient size to accommodate integration of these modern, large, efficient, and clean generating units. ■

—Grant Grothen ([email protected]) is principal in the Energy Global Practice and Block Andrews (bandrews@

burnsmcd.com) is strategic environmental solutions director at Burns & McDonnell.

Grant Grothen Block Andrews

1. Malaysian coal plant. The 1,400-MW Jimah plant in Malaysia was completed in 2009. Burns & McDonnell provided independent en-gineering services, including technical assessment, consulting, certifica-tion, and audit services for the project. Courtesy: Burns & McDonnell

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Europe Faces Capacity and Cost Challenges in 2014In a financial climate that sees state-of-the-art combined cycle gas plants slated for closure, the diverse nations of Europe continue to make steady progress towards ambitious climate goals.Charles Butcher

This is expected to be the year when modest economic growth at last re-turns to a recession-hit Europe. Recent

depressed power demand from industry has already allowed the 27 countries of the Eu-ropean Union (EU) to meet their 2020 target of a 20% cut in greenhouse gas (GHG) emis-sions compared to 1990 levels, but the good news stops there. Power producers are suf-fering low or zero margins on their gas-fired plants, while their customers complain of the burden of green taxes.

The recession has been bad news for the EU’s wish to have integrated internal markets for electricity and gas in place by the end of 2014. Infrastructure investment to support the single energy market needs to increase by 30% for gas and 70% for electricity com-pared to 2010 levels, yet it is not clear where the money will come from. More important-ly, a single market would have to unravel a patchwork of national regulations and sup-port mechanisms (see below for examples from the UK). It could take decades.

Sooner to materialize could be an end to the deadlock that has paralyzed biofuels in-vestment in Europe. In November, a consor-tium of six major car manufacturers and oil companies published a “biofuel roadmap” that links the oil and automotive industries and promises significant GHG reductions. This could help to overcome the fragmen-tation of national transport policies across Europe. It would also reassure the biofuels industry, which is fighting the European Commission over the extent to which biofu-els should be allowed to displace food crops and natural carbon sinks.

As in previous years, decarbonization and loss of nuclear capacity are the main threads linking European energy policy and politics. As POWER went to press, the EU was close to publishing a first draft of its 2030 energy and climate framework, which will work to-wards a GHG cut of 80% to 95% below 1990 levels by 2050.

Accompanying the new policy is likely to

be a change in the way the EU supports green energy research and development. The pres-ent system of funding for “strategic energy technologies” (the “SET-plan”) has helped to cut the cost of solar power and cellulosic bio-ethanol but has failed to make carbon capture and sequestration (CCS) happen. 2014 will see a new roadmap based instead on energy services—heat, light, transport—plus a new funding mechanism known as Horizon 2020.

Another reason for lack of investment in low-carbon technologies is the continuing failure of the EU’s emissions trading scheme (ETS). CO2 prices are now below €5/met-ric ton (mt), whereas a level of €40 to €55/mt would be needed before new coal-fired plants could justify CCS, experts say. The European Commission has now agreed that structural reform of the system is needed, so higher carbon prices are at last on the cards. The six options tabled for the reform include direct price management, perhaps similar to a scheme the UK adopted in 2013: a “floor price” of €18/mt, rising progressively to €83/mt by 2030.

Denmark, one of the countries furthest along the green track, plans by 2050 to get half its electricity from wind and to be free from fossil fuels altogether. Even France will cut the share of nuclear energy in its gener-ating mix to 50% by 2025, from more than 75% at present. An investment package esti-mated at €592 billion (including energy effi-ciency and grid modernization) includes new offshore wind projects in the 500-MW class.

The UK and Germany face particularly in-teresting new years.

UK Tackles Capacity CrunchJust in time to avoid a looming capacity crunch, the UK government has sorted out a financial mechanism that should at last per-suade power companies to build new thermal generating plants. It’s no cheap fix, though, so energy politics are certain to continue making headlines through 2014.

Everyone agrees on the basics. Almost a

fifth of Britain’s generating capacity—old nuclear and coal—will close by 2020, yet power demand is projected to double by 2050. Government regulator Ofgem says spare generating capacity could fall to just 2% to 5% in 2015–16, and that by 2020 the country will need to spend £110 billion on generation and networks to stave off black-outs. Bound by law to cut GHG emissions by 80% by 2050, all three main political parties agree that most of the new capacity will have to be low-carbon—chiefly wind and nuclear, with gas as a backup.

UK wind power looks set to continue doing fairly well. Total installed capacity reached 10 GW by November 2013, and on a weekday afternoon in the same month wind production met a record 13.5% of total elec-tricity demand at the time.

Yet offshore wind plants are unlikely to be built fast enough to allow the country to meet either of two targets for 2020: 16 GW of installed offshore wind power and a long-standing plan to get 30% of electricity from renewables. The more likely figure of 8 GW to 10 GW risks losing the advantages of economy of scale in terms of both power prices and job creation, warns a recent report from RenewableUK.

At the end of November, RWE abandoned a plan to build the 1,200-MW Atlantic Ar-ray wind farm off the west coast of England, citing technical and economic challenges, though it is still working on offshore projects totaling up to 5.2 GW. Huub den Rooijen, head of offshore wind for the Crown Estate, which controls licensing, said that decisions of this kind would likely cut the UK offshore wind pipeline from a potential 40 GW down to 8 GW to 16 GW by 2020.

The power companies have also been re-luctant to invest in new thermal plants. Ob-stacles include recession, high gas prices, the commercial risks of nuclear power, and fear that gas plants will become unprofit-able when they are reduced to backing up wind turbines.



Desperate for new nuclear capacity, the government has therefore set minimum prices for all types of low-carbon power. The new Energy Bill, which is expected to be law by the end of 2014, sets out “con-tracts for difference” (CfDs), which guar-antee a nuclear operator a “strike price” of £92.50/MWh (Table 1). The difference between the strike price and the average wholesale price—currently around £47.50/MWh—will be paid by electricity consum-ers (or refunded to them if the market price should fall above the strike price). Because they are funded from bills, not taxes, CfDs are not technically subsidies.

The government wants to see eight new nuclear plants built, all at existing sites. A Chinese-backed consortium led by EDF En-ergy has agreed to go ahead with two new EPR reactors at EDF’s Hinkley Point site, and possibly two more at Sizewell.

With no equivalent security yet in place for fossil-fueled plants, however, the “big six” suppliers—Centrica/British Gas, EDF En-ergy, E.ON UK, npower, Scottish Power, and SSE—are finding the business climate tougher when it comes to gas-fired generation.

In February 2013, when UK regulators had already approved 15 GW of planned new gas capacity, Centrica CEO Sam Laidlaw said his firm would hold off building any gas-fired plants for four years. The following month, Ian Marchant, CEO of SSE, announced earli-er-than-expected plant closures and criticized the government for “lack of clarity” on the investment climate for gas plants.

What Laidlaw, Marchant, and others are hoping for are “capacity payments” to maintain the economics of combined cycle gas turbine (CCGT) plants against high fuel prices and increasing amounts of wind power taking priority on the grid. The earli-est date for Ofgem’s first capacity auction

is the fall of 2014; first delivery is planned for winter 2018–19, though this could be brought forward.

Meanwhile, energy users across the po-litical spectrum are fuming at record prof-its posted by the “big six” on the back of inflation-boosting price rises. Conservative voters also complain loudly about the cost of renewables, even though the Department for Energy and Climate Change claims the consequences of the Energy Bill will be no more expensive than continuing to burn gas. Ed Miliband, leader of the opposition Labour Party, has promised to freeze energy bills if he wins the 2015 election.

Under pressure to cut energy bills, Prime Minister David Cameron is alleged to have said that the solution is to “cut the green crap.” He has launched a review of the green levies that make up around 8% of the average do-mestic energy bill, though the best he can hope for seems to be to transfer some of this burden

to other green taxes. Energy-saving measures remain much talked about but ineffective.

Germany Battles Overcapacity and Renewables CostsWhile the UK tries to keep the lights on, German power producers are more typical of those elsewhere in Europe as they strug-gle with overcapacity and narrow or nega-tive margins for gas-fired plants. Wholesale power prices have fallen to half their 2009 values, and spark spreads are firmly negative (Figure 1).

By August 2013, German energy giant E.ON had idled about 6.5 GW of capac-ity and was considering mothballing about 11 GW more. Four months earlier, the com-pany even proposed shutting down its ad-vanced Irsching 4 and 5 CCGT units, which have efficiencies close to 60%. Low power prices, cheap coal, and low carbon permit costs had made the units uneconomic, the company said. Discussions with Germany’s Federal Network Agency (FNA) and grid operator TenneT TSO yielded enough com-pensation for E.ON to keep the Irsching plants running.

The FNA has said that plants operating for more than 10% of the time on demand from transmission operators should be paid for this capacity service. When it comes to renewables, Germany is still “too fixated on megawatts,” said Johannes Teyssen, CEO of E.ON.

Also in August, Europe’s third-largest power provider, RWE, said it would take of-fline 3.1 GW of natural gas and coal power plants in Germany and the Netherlands. The company blamed “political intervention,” subsidized renewables, and low wholesale power prices. These shutdowns will continue through 2014. “Many of our power stations

Strike price per MWh Technology

£305 Wave and tidal

£155 Offshore wind, falling to £135 by 2018

£145 Anaerobic digestion

£125 Large solar, falling to £110 between 2016 and 2019

£125 Geothermal

£120 Biomass

£100 Onshore wind, falling to £95 from 2017

£92.50a Nuclear, falling to £89.50 if EDF builds a second plant

£90 Energy by waste

£65 Landfill gas

Note: a. The nuclear contract is for 35 years, compared to 15 years for renewables. Whether nuclear is cheaper than renewables therefore also depends on the discount rate chosen.

Table 1. UK contracts for difference. Contracts for low-carbon generation may eventually be awarded by auction, making them independent of technology. Source: UK Depart-ment of Energy & Climate Change

15

10

5

0

-5

-10Trading Year 2011 Trading Year 2012 Trading Year 2013

CDS Cal 2012 – 14 Base load (€/MWh) (assumed thermal efficiency: 37%) Average CDS Cal 2012 – 14 CSS Cal 2012 – 14 Base load (€/MWh) (assumed thermal efficiency: 49%) Average CSS Cal 2012 – 14

1. Clean dark and spark spreads in Germany. Prices for 2013 are through Febru-ary 13. Source: RWE Supply & Trading



are now in the red,” said CFO Bernhard Günther. “This is the greatest crisis our in-dustry has faced for many decades.”

With this background, the sudden loss of 5 GW of nuclear capacity in 2011 is not the most significant issue for Germany’s Ener-giewende. Nor, in itself, is the plan to get 80% of the country’s electricity from renewables and to cut GHG emissions by 80% to 95% by 2050; after all, the rest of Europe should be doing the same. The question is how to get

the share of renewables in power production up from 20% now to 35% by 2020 without breaking the grid or upsetting the voters. A secondary challenge will be to avoid relying too much on coal—traditionally, an impor-tant fuel in Germany and the obvious fall-back when gas is too expensive.

In February 2013, Federal Environment Minister Peter Altmaier met with disbelief and head-shaking when he suggested that the energy transition could cost one trillion euros

by 2040. That’s still less than the estimated cost of German reunification in the 1990s—some might say another crazy scheme that, nevertheless, had to be carried through. Of course, Germany’s “big four” are all doing well out of green power. “Renewables are a mainstay of our earnings,” said E.ON’s Teys-sen recently.

Following the election of September 2013, Germany’s new coalition government has confirmed a target of 55% to 60% electric-ity from renewables by 2035 and said it will reform the Renewable Energy Act (Erneuer-bare-Energien-Gesetz, EEG) by Easter 2014. The EEG’s targets for renewables penetration remain largely unchanged, but the high costs of supporting renewables will be pushed down. Changing the subsidies “will be the central project of the grand Merkel coali-tion,” Altmaier said, with policy becoming “more predictable and lastingly affordable.”

Germany’s photovoltaic (PV) power in-dustry has crashed since 2011 as cheap Chinese solar panels have flooded onto the market, and tens of thousands of jobs have been lost. Yet PV growth continues to meet its ambitious targets, with 226 MW installed in October 2013 alone. By the end of that month, total PV capacity was 35 GW and the country was on course to meet its target of adding 2.5 GW to 3.5 GW each year. The new government says it will not change the support scheme for PV.

Support will be reduced for onshore wind power, whose installed capacity grew by 2.4 GW during 2012 to reach 31 GW by year end. Support will be unchanged for offshore wind, but capacity targets have been reduced to 6.5 GW by 2020 and 15 GW by 2030, down from 10 GW and 25 GW respectively, in recognition of the technical risks and shortage of capital. Offshore wind, although expected to form the mainstay of future growth, has not yet reached 400 MW installed capacity. Tur-bine manufacturer Siemens says it plans to cut the levelized cost of offshore wind power by up to 40% before the end of the decade, to less than €0.1/kWh.

Heavy grid investment will be needed for all this distributed generation, especially because wind power is concentrated in the north of the country while industry is biased towards the south. Fragmented grid manage-ment and considerable public opposition are making the job harder. To avoid the delays associated with getting overhead cables ap-proved, Germany’s four transmission system operators are cooperating on four high-volt-age direct current underground lines from north to south. ■—Charles Butcher is a UK-based POWER

contributing editor.

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2014 Industry forecast

Day & Zimmermann Focuses on FlexibilityMichael McMahon

Now more than ever, we see the U.S. power market sharply focused on maximizing return on investment. We

see power producers responding to economic uncertainty, high costs for new emission con-trols, and a decline in new nuclear construc-tion. Low natural gas prices seem to be the driving factor in every economic decision. Power producers, contractors, and vendors must be flexible and readily adapt to chang-ing market and economic decisions. For Day & Zimmermann (D&Z), this means we must deliver value that can be measured, including safety, project and labor management, and processes and tools that drive efficiency and reduce costs.

Safety remains the number one priority for the industry, and contractors are continually challenged to deliver a well-trained work-force that concludes each shift as it started—safe and injury-free. In 2013, D&Z launched its Behavior Observation Learning Tool (BOLT), a web-based worker observation process designed to identify safe and at-risk work behaviors. Using web-based mobile technology, supervisors and craft workers, both independently and paired with our cus-tomers, record real-time behavior observa-tions to correct at-risk conduct and reinforce safe work practices. We also are enhancing our Key Performance Indicator (KPI) data capture and trending tool that correlates lead-ing vs. lagging indicators.

The Value of Alliances and PartnershipsDay & Zimmermann’s strategic focus is on the U.S. power operations and maintenance (O&M) market and on the process and indus-trial markets. We have a significant industry footprint in both nuclear and fossil genera-tion. As such, our customers depend on us to deliver industry best practices and lessons we have learned from our experience. Alliances and partnerships are integral to this busi-ness philosophy and strategy. We find they are most effective in multi-site relationships, where we can leverage the use of consistent standards and systems across a fleet of fa-cilities. Our strategy has been successful as

we embark on fleetwide contracts with new and returning customers, including American Electric Power, We Energies, Public Service Electric and Gas Co., NRG, NextEra, Duke Energy, Southern Company, PPL, Public Ser-vice Co. of New Mexico, FirstEnergy Nucle-ar Operating Co., Westar, Portland General Electric Boardman, and others.

The alliance model provides the optimum environment for us to work with the custom-er. It provides safe, quality services at the lowest cost. When given a seat at the table, we regularly share ideas and develop the best solutions together. We establish KPIs or pay-for-performance measures. These measures help improve the process and the work product. We adjust them to continue to better meet business needs. Our experience with these types of contracts has enabled us to focus precisely on areas of improvement so that the plants we work on can operate more competitively.

Meeting Workforce ChallengesThe development of craft labor and project management has challenged the domestic power industry for some time, and we be-lieve this trend will continue. Labor avail-ability, skill, and management are essential to performing O&M work now and in the future. Many of our clients are seeking one or more delivery models: supplemental con-tingent workers, managed task, and project work. D&Z has been very successful offer-ing a scalable combination of all three. Our cost-effective and flexible model is one of the reasons that we have been successful in this market. D&Z’s focus on increased account-ability, customer satisfaction, and operational excellence makes us a valuable option for

customers who seek an alliance or partner-ship relationship.

One of the ways D&Z has addressed this is with its workforce training programs. We are actively involved with trade schools and community colleges securing government grants and developing worker training pro-grams. For example, D&Z’s implementation

of the Electric Power Research Institute’s (EPRI) Standardized Task Evaluation pro-gram complies with EPRI’s Administrative Protocol for Portable Practicals (AP3). Our program was found to be compliant through a comprehensive review and audit by EPRI evaluators and the unanimous vote by 11 in-dustry partners and utilities.

We also have strengthened our leadership team and invested in new talent with both owner and contractor experience in operating nuclear and fossil plants, in capital projects execution, and with OEMs. In field opera-tions, we determined it was important to dem-onstrate competence in project management and team leadership and selected the Project Management Institute’s registered Project Management Professional (PMP) credential. Many employees have earned the PMP des-ignation, and we plan to provide boot camp training for more this year.

The competition for talent at all levels of the organization is intense. It is not enough to invest in professional development and offer a competitive salary and benefits package. We are finding it’s the combination of our betterment culture and family ownership, and a strong commitment to core values of safety, diversity, integrity, and success that help us attract and retain exceptional talent. ■ — Michael McMahon is president of Day

& Zimmermann ECM.

Power producers, contractors, and ven-dors must be flexible and readily adapt to changing market and economic decisions.



Shale: The Rock That Rocked the WorldIn little more than a decade, the discovery of economic methods to extract natural gas from shale has exploded traditional assumptions about the world’s energy fu-ture and reversed trends across the power business. But the shift has only just be-gun, and more big changes are on the way. Thomas Overton

In the early 1980s, a man named George Mitchell, who owned an independent oil and gas company in Houston, began to

see a distressing trend in his company’s fu-ture. Mitchell Energy supplied natural gas to a pipeline flowing north to Chicago, but pro-duction had been declining and new sources of gas needed to be found. Mitchell had an idea.

It had long been known that shale under-lying conventional deposits was the source rock for oil and gas. The problem was the economics: Getting the gas out simply cost too much.

But Mitchell was certain a way could be found. Through the 1980s and 1990s, his handpicked team of geologists and engineers experimented with one method after another, while Mitchell fought his board of directors to keep the project alive.

In 1997, the team finally hit on a combina-tion of water, sand, and guar gum to fracture the shale and draw out the gas. Combined with

advances in 3-D seismic imaging, Mitchell’s crew had found the golden egg. When Devon acquired Mitchell Energy in 2002 and the team applied Devon’s expertise in horizontal drilling to the new technique, the shale boom took off (Figure 1).

In little more than a decade, the U.S. energy sector has been turned upside down. The enor-mous influx of shale gas has upended dispatch orders across the country, reversed decades-old flow patterns on interstate gas pipelines, and squelched the much-heralded renaissance of nuclear energy and “clean coal.”

But the shale story is far from over, and has resonated far beyond U.S. shores.

Production Still ClimbingThe Energy Information Administration (EIA) projects that U.S. gas production will increase from about 65 Bcf/d in 2013 to 73 Bcf/d in 2020, at which point the nation will be a net gas exporter. This is despite a 75%

decline in gas rig count since 2008, reflecting impressive growth in well productivity.

The continued production growth has sparked concerns about pipeline infrastruc-ture, primarily in the Northeast and North Dakota. The growth in North Dakota’s shale oil production has run ahead of its ability to handle the associated gas, leading to wide-spread flaring. Contrary to public perception, the reason is not low gas prices reducing in-centives to build new infrastructure. In fact, the high percentage of wet gas in the Bakken shale makes the region’s production quite valuable.

The reason is simply the ever-increasing volume: Total gas production in North Da-kota has nearly tripled since 2011. Despite a flurry of construction in gathering infra-structure—more than 2,000 miles of it in 2012 alone—the total amount of flared gas in North Dakota has continued to increase every year, and reached 160 MMcf/d this past fall.

Six new or expanded gas processing plants are expected to come online in North Dakota in the next few years, which should increase overall capacity by about 50%. Meanwhile, a proposal is in the works from pipeline company WBI Transmission to build a new transmission line that would move gas from the Bakken field to eastern North Dakota or Minnesota.

U.S. Regulatory HurdlesThe shale boom has attracted regulatory at-tention at federal, state, and local levels. Mu-nicipal bans on fracking, though currently few in number, are growing in popularity. While some are purely symbolic gestures in areas with no shale reserves, others have cropped up in the heart of shale country. A conflict is brewing in Colorado between the state gov-ernment, which favors regulated development, and cities that have enacted bans. Most recent-ly, Boulder, Lafayette, and Fort Collins voted to suspend or ban fracking within their city limits in early November. The city of Long-

1. Going deep. Hydraulic fracturing at a Devon Energy well site in Texas. Courtesy: Irekia-Eusko Jaurlaritza/www.ukberri.net



mont enacted a similar ban last year, and the state has filed suit to overturn it. A suit against the three newest bans seems likely, though the state may wait for the outcome from the Long-mont suit before acting.

At the state level, New York’s five-year moratorium seems unlikely to be lifted in the near future. Meanwhile, the state’s highest court, New York Court of Appeals, agreed in October to hear a case brought by a drilling company in opposition to a municipal ban. More than 150 New York municipalities have enacted bans or moratoriums on gas drilling, and all of these could be nullified should the case succeed (though such a decision would not affect the state-level moratorium). Mora-toriums are also in place in New Jersey and Vermont, though neither has meaningful shale gas deposits.

The biggest overall impact is likely to come at the federal level, where the Bureau of Land Management (BLM) is in the pro-cess of revising rules on fracking on public land, including Indian reservations. A draft rule in 2012 drew heavy criticism, but the BLM has argued that the inconsistencies in state schemes warrant federal regulation. However, to the extent a state or Indian tribe can show that its existing regulation scheme meets or exceeds federal requirements, the BLM will issue a variance allowing the local rules to control.

The revised rule was open for public com-ment through August, and a new revision should be issued in early 2014. Litigation over the proposed rule seems a certainty.

Power Sector Demand in U.S. May Grow, but Slowly Surging supplies and lower prices are not expected to increase power sector gas con-sumption in the near term, due to increases in efficiency. The EIA is projecting that con-sumption for power generation will remain between 22 Bcf/d and 23 Bcf/d through 2020, then begin rising to about 24 Bcf/d in 2030 and 26 Bcf/d in 2040.

Over the same period, the EIA projects that the gas share of power generation will climb to 27% in 2025 and 30% in 2040. Con-sumption growth will lag behind as older steam plants and less-efficient combustion turbines are replaced with highly efficient combined cycle plants.

Some observers, however, see these pro-jections as overly conservative.

Especially since deregulation of power markets began in the 1990s, gas prices and coal prices have been bound in a symbiotic relationship as generators sought to leverage the least-cost fuel. But that relationship may be coming to an end.

Estimates are that anywhere from 50

GW to 80 GW of coal generation will be retired between 2010 and 2020. Only a handful of new coal plants have come on-line in the past few years, and only a few more are in development.

A 2012 study by the National Energy Technology Laboratory (NETL) lays out how dramatic the pullback has been. In 2007, NETL reported just over 19 GW of coal projects were planned to begin operation by 2012. Less than 1 GW of that capacity was actually built.

Meanwhile, the EIA projects that nearly 40 GW of gas-fired capacity will be added between 2010 and 2020. The promise of long-term sustained supplies of gas at mod-erate prices has created enormous economic and regulatory pressure for this switch—even where other requirements for it are not yet in place.

Despite persistent supply constraints, the northeastern U.S. is continuing a strong trend toward gas-fired power, as several of the largest coal plants in the region, and at least one nuclear plant, are poised to shut down in 2014 and 2015. Gas now accounts for around 50% of power generation in the region, and that level is certain to increase.

As a result, the seasonal bottlenecks that caused large price spikes and gas shortages last winter are unlikely to ease until later this decade. Although several expansion projects built to increase takeaway capacity from the Marcellus region are coming online in 2014 and 2015, these are largely designed to trans-port gas to the New York/New Jersey region. No significant pipeline expansions into New England will come into service before 2016 at the earliest.

What these developments mean for the power industry is that gas may be exiting its price relationship with coal. Fuel switch-ing will become less and less of an option as more generators and regions abandon coal, and do so less from price concerns than from regulation. Gas prices later in this decade and after 2020 are likely to be dictated more by production costs and overall market demand than by coal supplies and prices.

Burgeoning production of shale gas is also creating a wholly unexpected gas export mar-ket. Gross U.S. pipeline exports to Mexico have doubled since 2008, and exports to Can-ada have increased about 50% over the same period. Both markets are expected to grow strongly, both in the near term and through 2040. Net exports to Mexico should top 2.7 Bcf/d by 2020, with substantial increases in cross-border pipeline capacity coming online in 2014 and beyond.

Perhaps the biggest shift in the gas mar-ket has been in liquefied natural gas (LNG). As little as five years ago, the Department of

Energy (DOE) was considering applications for at least a dozen import terminals. Now, only one LNG import terminal, Everett in Massachusetts, is still receiving LNG, while the DOE has approved four export terminals, with more approvals expected in 2014.

Collateral Damage for U.S. Renewables and NuclearThe boom in shale gas has handicapped re-newable generation, which fell 6% (from all sources) in 2012 as gas prices plummeted, even though installed renewable capacity rose by 10.5%. This caused alarm in some quarters that cheap shale gas would under-mine a shift to renewable generation.

These fears are not without basis, as con-tinued cheap gas-fired power represents com-petitive pressure on wind and solar, which are still more expensive, even with subsidies. Over the long term, however, observers have projected that a reliable source of inexpen-sive gas is likely to provide support for re-newables.

A 2013 report funded by the Mitchell Foundation—yes, the same George Mitch-ell—argued that natural gas and renewable generation are natural allies. Renewables, with their zero fuel cost, offer substantial hedging opportunities against future gas prices, while gas-fired plants are ideal for balancing intermittent renewable output. This symbiotic relationship is becoming clear in areas with significant renewable generation, such as California, Texas, and Colorado, where generators have rushed to build gas-fired plants, especially the newest fast-start models developed by the major suppliers for precisely this role.

Shale gas has also hit the nuclear industry. Like coal, a long list of new nuclear plants and uprates envisioned in the late 2000s were cancelled as gas prices collapsed. Twelve applications for new plants were filed with the Nuclear Regulatory Commission in 2008 alone; only a handful are under construction, all in regulated markets.

Existing plants were also hit hard: Do-minion shut down its Kewaunee nuclear plant in Wisconsin with 20 years left on its license, and Entergy opted to retire its Ver-mont Yankee plant in 2014, in both cases because the plants were unable to compete in a changed market. Competition from gas also played a part in the decisions last year of Duke and Southern California Edison not to repair the damaged Crystal River and San Onofre plants.

The EIA projects U.S. nuclear capacity to rise from the current 102 GW to 110 GW by 2020 (as the new units come on-line), but remain mostly flat from there through 2040.



Global ImpactThough exporting the shale boom might seem like a matter of technology transfer, global energy experts have been markedly pessimis-tic about shale gas outside the U.S. Observ-ers have pointed to a number of factors that created a “sweet spot” for U.S. shale gas, one unlikely to be fully duplicated elsewhere:

■ A huge oil and gas sector, with a deep pool of talent and oilfield services to draw on.

■ Strong private property rights, making min-eral exploitation relatively straightforward.

■ A favorable regulatory environment, espe-cially at the state level, and general public support for oil and gas development.

■ Unparalleled natural gas processing and transport infrastructure.

■ A highly liquid gas market, creating a deep pool of potential financing.

Canada and MexicoThe most immediate impact of the U.S. shale boom has been felt in Canada and Mexico. Ironically, though Canada has several viable shale plays, reduced demand for gas in the U.S. has depressed Canadian gas prices, re-ducing the economic incentive to drill. Still, Canada is the only other country producing

meaningful amounts of shale gas, in part be-cause it most closely mirrors the production environment in the U.S.

About 15% of Canadian gas production in 2012 was from shale, according to the EIA, as compared to 39% in the U.S. Total current production of shale gas in Canada is about 3 Bcf/d. Nearly all of it comes from two plays in British Columbia and Alberta: the Mont-ney Basin and the Muskwa-Otter Park forma-tion in the Horn River Basin. With demand from the U.S. declining, Canada is exploring its own LNG exports to Asia. Several export terminals are under development in British Columbia, three of which have received ex-port licenses.

The political environment for shale gas in Canada is less certain. Though the cur-rent Conservative government is strongly supportive of oil and gas development, its policies have deeply angered the nation’s environmental movement. Provincial gov-ernments in Quebec and Newfoundland have enacted bans on fracking, and pressure for similar bans is mounting elsewhere.

Though Mexican gas demand is projected to grow strongly, shale exploration in the country is still in its infancy. Mexico is be-lieved to hold substantial shale gas reserves,

some of it contiguous with shale plays in Texas. The International Energy Agency (IEA) estimates that Mexico has around 537 Tcf of technically recoverable shale gas. The development environment, however, is much less favorable than Canada’s.

Much of the problem is Mexico’s highly centralized and mostly nationalized oil and gas business, which is handicapped by cor-ruption and inefficiency. The federal gov-ernment is considering reform of the energy sector, but prospects are uncertain. Though PEMEX, the national oil company, has launched a $200 million exploration program in the Mexican portion of the Eagle Ford Shale, meaningful production is not expected before 2020.

South AmericaBy far the largest untapped shale gas poten-tial in the Americas is in Argentina. EIA and IEA estimates place the nation’s reserves third in the world behind China and the U.S. Early test drilling has shown that Argentina’s shale layers are productive and respond well to fracking. The IEA projects that, with the right policies in place, the country could be the fourth-largest producer of shale gas by 2035.

But the challenges are equally large.

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The nation’s oil and gas sector is mori-bund, handicapped by strict price controls that largely eliminate incentives to explore. The other problem is endemic labor unrest, which is certain to increase production costs. Though the national government has expressed interest in exploiting its resourc-es, it has so far shown little willingness to tackle the challenges head-on and risk a public backlash should relaxation of price controls lead to inflation—always a fear in a country that has seen several episodes of ruinous hyperinflation.

Still, there are signs of progress. In Sep-tember, state-run oil company YPF and the local subsidiary of Dow Chemical signed an agreement to explore for shale gas in the Neuquen Basin, thought to be the nation’s most promising play. The two companies plan to drill up to 16 wells as part of a pilot program.

Brazil’s shale gas reserves appear to be smaller than its southern neighbor’s, but it has moved more briskly to exploit them. Last year it held its first auction of shale gas ex-ploration rights. It has also begun requiring winning bidders for conventional deposits to drill exploratory wells into underlying shale, in hopes of getting a clearer idea of its poten-tial resources. Unlike Argentina, which has traditionally been a difficult partner for for-eign oil and gas firms, Brazil has welcomed foreign investment. Nevertheless, commer-cial shale gas production is years away and is unlikely to be meaningful before 2020.

EuropeThe gas market in the European Union (EU) bears little resemblance to that in North America. High prices as a result of long-term oil-linked contracts, declining production, and supply constraints have led to declining consumption and the shuttering of gas-fired power plants. Worse, reduced demand for coal in the U.S. has resulted in increased coal exports to Europe, pushing down the price of coal. A concurrent collapse in the EU emis-sions trading market has made coal highly competitive against gas for power genera-tion. Gas consumption fell 1.6% in 2012, and the IEA projects flat demand in the EU go-ing forward, largely as a result of regulatory support for renewable energy and continued competition from coal.

Despite high gas prices, prospects for shale gas in the EU are little better. While the IEA estimates of total shale gas reserves in Europe are close to those for the U.S., it is likely that far less of it will be recovered. The shale geology is thought to be more com-plicated, making the gas more expensive to extract. More significantly, public opposition to fracking in the EU is high in many areas,

with bans or moratoriums in place in France, Germany, and the Czech Republic.

The only near-term prospects for shale ex-ploration in the EU are in Poland and the UK About 50 wells have been drilled in Poland, though results have been less than hoped for. Another 200 wells are planned by 2016. The IEA projects about 0.8 Bcf/d of shale gas production from Poland by 2035. The U.K.’s shale reserves are fairly limited, but potentially severe gas shortages have forced the national government to push for explo-ration despite public opposition. Local firm Cuadrilla briefly attempted to drill for shale gas in Lancashire in 2011, but it suspended operations after several small earthquakes occurred in the region.

Ukraine is thought to have potential for shale gas development, but a challenging business and political environment has hand-icapped exploration. The IEA estimates pro-duction from Ukraine comparable to Poland by 2035, but commercial production should be quite limited before 2020.

RussiaFew countries outside of North America have been as affected by the shale boom as Rus-sia, even though it has no direct connections to the North American market. As recently as 2007, Russian national gas company Gaz-prom was preparing to spend $30 billion developing a gas field in the Barents Sea in hopes of supplying the U.S. market. That project was abandoned in 2010 when it be-came clear there was no need for the gas.

Once the dominant supplier to Europe, Gazprom has seen its position undercut from every direction. Cheap U.S. coal exports have reduced the demand for gas for power generation, while the collapse in U.S. gas im-ports has redirected LNG from Qatar to high-er-priced markets in Europe. Gazprom’s long insistence on oil-linked contracts is under siege, and most observers expect spot markets to dominate in the future. So threatened has Russia been by the shale boom that Gazprom has been accused of funding anti-fracking or-ganizations in Europe as a means of slowing its advance. Gazprom officials have loudly denounced shale gas as a bubble due to burst at any moment, and media coverage in the Russian press—some of which is owned by Gazprom—has been highly critical of shale development in the U.S. and elsewhere.

Yet, for all this, Russia is thought to pos-sess substantial shale reserves, though most-ly of oil. Gazprom has quietly begun its own fracking explorations, though it is unclear where this will go. It still has substantial con-ventional reserves, and with the European market in turmoil, it has been looking east for new markets. And it is to the east where shale

gas may see the greatest impact of all.

ChinaNo country has greater shale gas reserves, or a greater need for them, than China. Both the EIA and IEA estimate that China’s shale gas potential is as much as twice that of the U.S. The country is also poised for enormous growth in gas demand and is casting its nets wide. It currently has five LNG import termi-nals in operation and at least 10 more under development. It has secured or is in the pro-cess of securing pipeline imports from Cen-tral and Southeast Asia and Russia (though negotiations with Gazprom have stalled over prices). But to fully meet its needs, it must develop its domestic resources.

The impediments standing in the way of a Chinese shale gas boom, however, are for-midable, and in many ways present a mirror image of the advantages enjoyed in the U.S. Land ownership rules in China are murky, and endemic corruption makes securing clear mineral rights to shale deposits difficult—all the more so because oil and gas data are con-sidered state secrets. The regulatory environ-ment is heavily weighted toward state-owned enterprises and against the sort of independent risk-taking that spawned the shale boom in the U.S. China’s natural gas infrastructure is far short of what it needs, and the domestic gas market is both illiquid and constrained by price controls that have made gas develop-ment deeply unprofitable. The geologic char-acteristics of many of China’s shale basins are thought to be less productive than those in the U.S., and some of the more promising regions are hamstrung by severe shortages of water.

Even so, shale gas in China has made prog-ress in the past year as the central government has sought to cut through red tape and cre-ate incentives for development. Two licens-ing rounds have been completed, and several dozen producing wells have been drilled. The IEA estimates China’s shale gas production by 2035 at more than 11 Bcf/d, but many ob-servers remain skeptical that this level of pro-duction is achievable that quickly. (For more details, see “China’s Shale Gas Development Outlook and Challenges,” p. 41.)

AustraliaRegardless of the level of shale gas produc-tion China is able to achieve, projections are that the nation is poised to become the world’s largest gas importer because of sky-rocketing domestic demand, for both power generation and domestic heating. With China and the rest of East Asia becoming a huge market for LNG imports, Australia is moving briskly to meet the demand.

Australia is thought to have significant shale gas resources, though exploitation is



still in the very early stages. The nation is handicapped by limited gas infrastructure and serious water shortages in the interior regions. Significant production from shale is thought to be at least five to 10 years away.

Middle EastGiven the region’s enormous conventional gas reserves—which also enjoy the lowest production costs—the Middle East would seem to be a strange place for shale gas de-velopment. But large shale basins are known to underlie the Arabian Peninsula, and Saudi Arabia is beginning to look at exploiting them. This year, Saudi Aramco began assess-ing several areas in the country’s northwest, with a plan to use the gas to power a com-bined cycle plant in Jizan.

The Saudi government estimates that its shale gas reserves could total 600 Tcf, more than twice its conventional reserves. Oddly enough, the nation has had difficulty meeting domestic gas demand because of a focus on oil and price subsidies that make gas produc-tion uneconomic. Exploration is also under way in neighboring Oman and the United Arab Emirates, with production possibly be-ginning as soon as 2017.

AfricaThere are known to be several large shale ba-sins in Africa, notably in Libya and Algeria. The Algerian government has expressed in-terest in exploiting its shale reserves, but so far little has been done. The IEA estimates that Algeria could be producing significant amounts of shale gas by 2035, but little prog-ress is expected this decade.

The greatest near-term potential is thought to be in South Africa. By some estimates, that nation has the world’s fifth-largest shale gas reserves, despite having virtually no conven-tional reserves. A reliable domestic source of gas would do much to aid the nation’s desire to wean itself off coal while meeting burgeoning electricity demand. At the moment, however, the national government has enacted a mora-torium as it considers the appropriate regula-tory regime. Other impediments lie in the way: Most of the gas is in the southern Karoo Basin, which is arid and water-poor. The area is also geologically complex, with numerous igneous intrusions that may complicate seismic imaging and fracturing of the shale. As in other nations, political opposition to fracking is growing.

Where We Go from HereIf there has been one constant in the shale

business, it is that reality has repeatedly de-fied expectations. Production levels have leapt past previous estimates every year. Well productivity has climbed, and produc-tion costs have fallen. If there is one safe prediction that can be made, it’s that current predictions will be proven wrong in a vari-ety of ways.

How far can it go? If you listen to indus-try critics, shale is a bubble on the verge of bursting much the way the global financial markets collapsed in 2008. Viewed objec-tively, these claims have little in the way of support. The gas is clearly there, and the tech-nology for recovering it is becoming more ef-ficient and less expensive every year. While there has been turmoil in the market, this is in many ways an industry being the victim of its own success: So much gas came on the market so fast that collapsing prices wrecked the finances of several early entrants. As the sector matures, financial models will mature with it.

There is every reason to think shale gas is an industry with a long future ahead of it. George Mitchell, who passed away in July at 94, would surely be proud. ■—Thomas W. Overton, JD is POWER’s gas

technology editor.

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POWER IN CHINA

China’s Shale Gas Development Outlook and ChallengesDeveloping and using shale gas could alleviate fossil fuel shortfalls in China,

enhance that nation’s energy security, and contribute to economic and social development. Though the government has plans to utilize its buried shale resources, significant barriers to that plan remain.

Zeng Ming, Liu Ximei, and Li Yulong

Thanks to sustained and rapid develop-ment of China’s economy, demand for natural gas has been increasing. From

2000 to 2010, China’s demand for natural gas increased from 24.7 billion cubic meters (bcm) to 107.2 bcm; the average growth rate was about 16%. Furthermore, by 2009, natural gas demand exceeded supply in the Chinese market. China’s conventional natural gas pro-duction exceeded 100 bcm for the first time and reached 102 bcm in 2011, but the growth rate of yields was only 8.45%—lower than the average of 13.07% in the past decade.

Additionally, China’s dependence upon traditional energy imports is increasing yearly. Dependence upon foreign oil reached 53.8% in 2011, and net imports of coal were about 146 million tons in 2010, with year-on-year growth of more than 41%. Natural gas imports have been steadily increasing (Figure 1) as Chinese natural gas demand has been growing faster than that of coal and petroleum.

China’s high degree of dependence upon traditional energy imports is becoming a se-rious threat to the country’s energy security. Oil can be purchased from the international market; however, natural gas imports are

limited by the fact that regional distribution is mainly by pipelines, which are limited in adjacent countries.

It is predicted that China’s natural gas consumption will maintain an annual growth rate of 25% in the next five years and that demand will reach 170 bcm to 210 bcm in 2015. However, it is also estimated that natu-ral gas production will be only 140 bcm in 2015, with a growth rate of only 15%, which is far below that of consumption increases. The gap between supply and demand for nat-ural gas in China will continue to expand in 2015, reaching 50 bcm.

In light of current environmental pressure, the high degree of dependence on foreign oil and gas, prominent nuclear safety concerns, and renewable energy grid integration issues (see “A Plan for Optimizing Technologies to Support Variable Renewable Generation in China” in the December 2013 issue of POW-ER), it is of great significance for China’s en-ergy security to accelerate the development and utilization of shale gas.

China’s Shale Gas Resource Potential “Evaluating shale gas resource potential and defining favorable exploration targets in key areas,” as enacted by the Ministry of Land

and Resources, finds that the resource poten-tial of China’s land shale gas is 134.42 tril-lion cubic meters (tcm) and the recoverable resource potential is 25.08 tcm (excluding Qinghai-Tibet district). The area evaluated where shale gas has been found is about 88 square kilometers (km), with geologi-cal resources of 93.01 tcm and recoverable resources of 15.95 tcm. The U.S. Energy Information Administration (EIA) has re-leased a report saying that China’s shale gas resource is as high as 1.275 quadrillion cu-bic feet (36 tcm), ranking first in the world (Table 1). These numbers differ from others in Table 1, but all are estimates and all sug-gest abundant shale gas resources.

China has abundant, widely distributed organic shale. Offshore, marine rocks have been developed in South China, North Chi-na, and the Tarim Basin in Xinjiang. The resource potential of continental rocks with geological conditions of shale gas reservoirs is large. Continental shale gas is mainly found in North China, the Junggar Basin, the Turpan-Hami Basin, Ordos Basin, Bohai Bay Basin, and Songliao Basin. The three marine shale basins are southern Paleozoic marine shale, North China lower Paleozoic shale, and Tarim Basin Cambrian/Ordovician Pa-leozoic shale.

25%

20%

15%

10%

5%

0% 2006 2007 2008 2009 2010 2011

2%5% 5%

8%

14%

23%

1. Chinese natural gas imports are increasing. Source: General Adminis-tration of Customs of the People’s Republic of China

UnitEstimated resources

(trillion cubic meters) Evaluation year Remarks

Oil and Gas Center of Ministry of Land and Resources

25.08 2012Main basin and

region

Energy Information Administration (EIA) 36.1 2011 Main basin

Research Institute of Petroleum Exploration and Development

10–20 2009 Main basin

Langfang Branch of PetroChina Research Institute

11.4 2009 Emphatic basin

China University of Geosciences (Beijing) 26 2008Emphatic basin

and region

Table 1. Estimates of China’s shale gas resource.


Power in China

The best areas for shale geological condi-tions are Sichuan Basin, Paleozoic systems in Ordos Basin, the Middle and Lower Yangzi Platform regions, and North China Basin; better areas are Junggar, Songliao and Tur-pan-Kumul Basin; poor areas are Qaidam and Liaohe Basin. South China, North Chi-na, Northwest China, and the Qinghai-Tibet Plateau account for 46.80%, 8.90%, 43.00%, and 1.30% respectively of total recoverable shale gas resources (Figure 2), while Paleo-zoic, Mesozoic, and Cenozoic formations account for 66.70%, 26.70%, and 6.60% of total shale gas.

Status of Shale Gas ExplorationShale gas resources show great potential in China, but exploration and develop-ment of the unconventional gas is still at its exploratory stage. As research con-tinues, China’s shale gas exploration is making considerable progress, based on the successful commercial experiences of America’s shale gas development. (See Figure 3 in the web version of this story at powermag.com for details of development stages from 2000 to present.)

China has carried out shale gas drilling and hydraulic fracturing tests in Sichuan, Ordos, Bohai Bay, Qinshui Biyang Basin, Zhaotong in Yunnan Province, and Gui-zhou Province as well as South and Ton-gren regions. The total drilled wells include 35 shale gas wells (including 5 horizontal wells), 14 hydraulic fracturing wells (in-cluding 2 horizontal wells), 11 industrial gas (oil) flow wells (including 1 horizontal well), of which 7 wells have a daily output greater than 10,000 cubic meters.

Policy StatusThe Chinese government has announced a se-

ries of policies to speed up shale gas develop-ment, covering a range of issues, including:

■ Conducting the first round of shale gas ex-ploration competitive bidding.

■ Designating shale as “independent minerals.”

■ Releasing shale gas geological resource reserves numbers.

■ Enacting the “Shale Gas 12th Five-Year Plan.”

■ Publishing the “Guidance Catalogue for Foreign Investment Industrial (2011 revi-sion),” which defined the regulations for foreign cooperation and joint ventures for shale gas exploration and development.

Shale as an Independent Mineral. The Chinese government has strongly backed shale gas exploitation and exploration, mak-ing shale gas part of the country’s new energy strategy, and has approved shale gas as “inde-pendent mineral” to avoid monopoly control of the original oil and gas resources.

The National Energy Board “Shale Gas Development Plan (2011-2015)” aims to prove shale gas geological reserves are 1 tcm and recoverable reserves are 200 bcm. Chi-na’s annual output of shale gas is expected to total 6.5 bcm in 2015, up from zero today, and to be 100 bcm in 2020, according to the country’s shale gas development plan for 2011–2015. In the 12th Five Year Plan peri-od, in order to support shale gas exploration, the Chinese National Energy Administration will promote the setting up of special shale gas funds and will study price mechanisms and related financial policy.

Opening Investment to Private Cap-ital. In late June 2011, China conducted the first round of shale gas exploration competitive bidding and invited six state-owned enterprises to participate in bidding for four blocks of mineral exploration rights (in Chongqing municipality and Guizhou and Hunan provinces). Foreign companies and private domestic compa-nies were excluded from the first auction. Sinopec and Henan Coal-Bed Methane Co. were the successful bidders.

In order to develop shale gas resources, China held its second shale gas auction in December 2011. Although state-owned companies were still major bidders, private domestic companies and foreign companies were also allowed to participate. This is an important attempt to reform management of mining rights of oil and gas resources, which will help to encourage private enterprises to invest in shale gas exploitation.

Price Policy. China’s “Shale Gas De-velopment Plan (2011–2015)” has pointed out that shale gas is different from any con-

ventional natural gas that executes market pricing. China’s current natural gas pricing mechanism can be summarized as a cost-plus pricing method under state regulation. The price of natural gas is divided into four links: the ex-factory price, pipeline fees, the urban gate station price, and the end-user price.

Pricing is determined mainly by govern-ment departments according to the produc-tion and supply cost plus a reasonable profit. Guangdong and Guangxi Province took the lead in piloting the natural gas price-forming mechanism on Dec. 26, 2011. The pricing of shale gas, coal bed methane (CBM), coal gasification, and unconventional natural gas will follow a market regulation mechanism, which also reflects the government’s attitude of encouraging the exploitation of unconven-tional natural gas.

Shale Gas Subsidy Policy. In a notice jointly issued by the Ministry of Finance and the National Energy Administration that took effect Nov. 1, 2012, the central government promises to provide subsidies for shale gas mining enterprises. The stan-dard of subsidy is set at 0.4 yuan per cubic meter for 2012–2015 and is to be adjusted based on the development of the shale gas industry. Two categories of shale gas can enjoy subsidies: shale gas resources that have been exploited and utilized and enter-prises that have installed metering equip-ment that can provide accurate data on the amount of shale gas exploited and utilized. That means companies bidding for shale gas exploitation rights that have not yet started shale gas development or utilization are excluded.

Technical StatusChina has a foundation of technical equipment for shale gas exploration and development because horizontal wells and fracturing tech-niques have application in the traditional oil and gas industry. China has comparatively ma-ture technology in manufacturing of drill, frac-turing truck group, downhole tools, and so on. But the key technologies of horizontal drilling and hydraulic fracturing are immature.

First, China is lacking a whole set of technologies for horizontal drilling, includ-ing rotary steerable technology, logging while drilling technology, simulation soft-ware, analysis software, monitoring tools, and more. Second, it is inexperienced with these newer approaches. Take drilling for example: China has been drilling vertical wells for a long time, but only in recent years has it gradually shifted to the use of horizontal well technology to develop natural gas. Until October 2011 the total number of CBM drilling wells was more than 7,230, of which only about 170 were

43.0

8.9

46.8

1.3 South Northwest North Tibet Plateau

2. Regional distribution of China’s shale gas. Source: Research Institute of Ex-ploration and Development of China Petroleum


Power in China

horizontal wells, with most of those drilled after 2009 (Figure 4).

Major Challenges for Shale Gas Development in ChinaChina’s efforts to develop its shale gas in-dustry may face various obstacles, several of which are outlined below.

Resource Exploration Problems. Inves-tigation and exploration of China’s shale gas resources is still in its infancy. Exploration is very difficult in China because the shale plate is complex and the available area for explora-tion is relatively fragmented. The main prob-lems are that:

■ Investment in shale gas geological explo-ration is inadequate. Total investment in survey evaluation and exploration of shale gas is less than 7 billion yuan, compared with about 660 billion yuan for conven-tional oil and gas exploration.

■ China granted special access regulation of business exploration for oil and gas, which is basically controlled by the major oil and gas companies, which makes it difficult for private capital to get involved.

■ Geological data regarding shale gas could not be shared within the industry.

Policy Problems. Shale gas, involving faster development and higher investment risk, is an unconventional low-grade natural gas resource that needs positive and effec-tive policies to ensure scientific and robust development. Nevertheless, China lacks a law and policy system to encourage de-velopment of unconventional oil and gas resources, including shale gas. Although shale gas has been classified as independent minerals, specific operational policies for the industry have yet to be resolved, such as the management of mining rights, market access threshold, and standards.

Technical Problems. Technical problems are the major factors hindering develop-ment of China’s shale gas. The shale gas is difficult to develop because of its ultra-low permeability and depth (Cambrian shale bur-ied depth of 2,000 to 3,500 meters), which requires more advanced technology.

After several years of research and technical preparation, China has achieved some initial technology development, but not enough to meet the needs of shale gas exploration and development. Key tech-nologies that are lacking include shale gas resource evaluation, shale-containing gas analysis test, horizontal well drilling completion technology, and long-distance stage-fracturing, which severely restricts exploration and development.

China also lags in technology for long-range multi-branch horizontal wells and super-tight reservoir stage fracturing re-form. Additionally, the fracture fluid sys-tem is not built to effectively protect the shale reservoir and ensure minimal damage because the filtrate of different fracturing fluid systems can harm the shale reservoir to different degrees.

Additionally, some of the technical stan-dards for existing natural gas exploration and development are not suited to shale gas. Shale gas does not contain hydrogen sulfide and other toxic components, and only via fracturing does it produce gas; in this sense, shale gas is artificial gas reservoirs. Nevertheless, the regulations regarding Habitat Safe Distance and Drill-ing Fluid Density were included in “Drill-ing Well Control Technical Specification” (SY/T6426-2005) and are too large for shale gas wells, which is not conducive to lower operating costs.

Furthermore, because it involves an un-conventional natural gas, exploration and development of shale gas is much different than the description in the standard of “Oil and natural gas resource/reserve classifica-tion” (GB/T19492-2004), and its reserves could not be calculated in accordance with the existing “Oil and gas reserves calculation specifications” (DZ/T0217-2005).

Insufficient Pipeline Infrastructure. Shale gas must be transported mainly by pipeline, and China’s domestic natural gas pipeline network has been constantly im-proved. (See Table 2 in the web version of this article for existing and planned pipe-lines.) However, pipelines have become more important for importing foreign gas (at pres-ent there are three main import pipelines: the Central Asian natural gas pipeline, Myanmar gas pipeline, and the Russian natural gas pipeline), and additional pipeline infrastruc-ture will be needed for domestic shale gas.

Potential shale gas regions are in mostly sparsely populated and remote areas; that creates a problem for transferring the mined gas to consumers. Infrastructure inadequacy has become a major obstacle to further shale gas developments. Despite recent develop-ments, China’s pipeline network is unable to effectively reduce market risk faced by upstream enterprises. Currently, China has about 40,000 km of natural gas pipeline. The planned target is 100,000 km in 2015, but that is far from the U.S. pipeline total of 460,000 km.

Another problem is that the administra-tors of oil and gas pipelines have little in-centive to transport third-party shale gas. China’s natural gas pipeline infrastructure was mainly controlled by Petro China and Sinopec, which led to highly concen-trated control for mining, transportation, and sales. Petro China pipeline mileage accounts for more than 75% of the gas mainline, and Sinopec and CNOOC con-trol less than 20%, which results in a se-rious monopoly of gas resources and gas pipelines. In case of tight gas transmission lines, if the Chinese government does not create complementary measures or encour-age pipeline construction or force open the pipeline, shale gas development will face a huge cost to rebuild the infrastructure. Under the existing system, the party con-trolling the pipeline has no incentive to transport shale gas.

A Way ForwardWe suggest several strategies for accelerating shale gas development in China.

Strengthen the Strategic Exploration of Shale Gas Resources. More data about potential shale gas resources, where they are distributed, and their geological condi-tions are needed to enable discovering de-velopment areas with organic-rich shale and predicting the potential distribution of shale gas resource.

Shale gas resources pilot test areas of strategic investigation, exploration, and de-velopment should be established. Govern-ment should establish a shale gas geological survey data integration system and form survey research for this series. It should also build talent teams for shale gas survey, exploration, and exploitation and develop a geological data-sharing system and a social service system. The government should also launch shale gas geological theory research and international communication and coop-eration programs.

Create Policies Encouraging the De-velopment of Shale Gas. As an unconven-tional natural gas resource, shale gas needs government policy support because of high

8,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000

0Vertical wells

7,060

Horizontal wells170

4. China’s shale gas reservoir drill-ing (as of October 2011). Source: Nat-ural Gas Industry, Societé Generale Securities Institute


POWER IN CHINA

exploration and development costs, a long investment recovery pe-riod, and difficulty in realizing short-term economic benefits.

Policies are needed to encourage strategic survey and exploration and development of shale gas resources, as has been the case in the U.S. and other countries. The national financial sector should increase investment in a strategic survey of shale gas resources and encourage private investment in shale gas.

In addition, various favorable tax and fee policies should be formu-lated similar to the domestic development of CBM to promote shale gas development. At the same time, government should increase sub-sidies for exploitation of shale gas and launch preferential policies for key technology research, development, and promotions.

Improve Key Technical Abilities. Investment in science and technology should be increased to promote technological inno-vation. We suggest organizing advanced technological forces to carry out key technology research on shale gas exploration and development and to encourage enterprises to develop, promote, and use new technologies and processes that can improve the ef-ficiency of shale gas development. Additionally, the techniques of reservoir evaluation, perforating optimization, horizontal wells, and fracturing should be introduced and improved. Formulation of technical standards and specifications of shale gas should also be accelerated.

Accelerate Pipeline Network Construction. We recom-mend that the government develop comprehensive plans for and build a nationwide and regional natural gas pipeline network. Both more miles of natural gas pipelines are needed and an ap-propriate proportion of trunk pipelines and distribution pipe-lines. The Chinese government also should strengthen regulation

of its pipeline network. For example, a nondiscriminatory access policy should be rolled out if it wants to decrease transportation costs for shale gas.

In order to meet the needs of the developing shale gas sector, con-struction of pipelines should speed up.

Another need is equitable entrance mechanisms for the natural gas pipeline network and timely mandatory introduction of third-party access provisions.

Construction of small liquefied natural gas and compressed natural gas facilities will also be needed, especially for development areas farther from the natural gas pipeline network, to minimize transporta-tion costs.

As shale gas development advances, construction of export pipe-lines may be needed.

Shale Gas Is Nationally ImportantChina needs to speed up legislation concerning the management of shale gas resources, establish technological standards for shale gas development, introduce competitive mechanisms, improve foreign cooperation, strengthen supervision, and maintain an orderly and healthy level of shale gas exploration and development.

The Shale Gas Development Plan (2011–2015) issued by the Na-tional Energy Board identified shale gas development goals:

■ Basically complete the investigation and evaluation of shale gas re-source potential, understand the distribution of shale gas resources, and optimize 30 to 50 prospective shale gas areas and 50 to 80 favorable target areas.

■ Mostly complete the national shale gas resource potential survey and evaluation in 2015, exploring shale gas geological reserves of 1 trillion cubic meters, recoverable reserves of 200 bcm, and achieving an annual output of 6.5 bcm.

■ Establish geological survey techniques and resource assessment technical approaches for shale gas that are suitable for geologi-cal conditions in China as well as key technologies for shale gas exploration and development and ancillary equipment.

Commercial development and utilization of shale gas in China can be divided into three stages:

■ First stage—before 2015: pilot testing and developing key technologies.

■ Second stage—2015 to 2020: focusing on the development of ma-rine shale gas at scale in southern China and recognizing a break-through in the industrial development of continental shale gas and realizing its scale development and utilization. Shale gas produc-tion is expected to reach 20 bcm in 2020.

■ Third stage—after 2020: forming supporting technologies and ef-fective management systems and mechanisms for shale gas explo-ration and development suitable for the characteristics of China’s unconventional gas. The goal is to make shale gas a new force to support rapid development of China’s natural gas industry within 10 to 20 years.

Although large-scale development of shale gas will take time, ac-tively looking now for shale gas resources is imperative for national energy security reasons. As we look forward to the future, the devel-opment of China’s shale gas has broad prospects.

The authors would like to sincerely thank Wang Liang for guidance with the English writing. ■ —Zeng Ming, Liu Ximei, and Li Yulong, School of Economics and

Management, North China Electric Power University, Beijing, China.

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Redefining priorities for Québec’s Hydro Power ClusterOptimizing at home, building new capacity abroad

Gabrielle Morin, Razvan Isac and Sulaiman Hakemy

This report was researched and written by Global Business Reports

Chaudière hydroelectric facility, in Quebec.

Photo courtesy of Innergex

2 Global Business Reports // POWER QUÉBEC January 2014

A land of lakes and rivers, Québec benefits today from an abun-dance of clean and green energy, vastly generated by means of hy-dro power, which is increasingly complemented by the province’s eastern wind energy farms. Government owned Hydro-Québec rules over power generation, transmission and distribution in the province, and, over the years, the utility has decisively contrib-uted to the establishment of a world-renowned cluster of hydro actors across the supply chain. The hydro industry’s tradition con-trasts with the wind sector’s youthfulness, whose expansion was prompted by the recent liberal governments and their 4,000 MW wind power RFPs. With its energy surplus estimated to last until 2027, Québec and its players are now looking inwards to optimize the province’s aging hydro infrastructure, while properly integrat-ing Gaspésie’s wind sector contribution. More importantly, they are looking at foreign markets, where their expertise could shape many developing countries’ energy infrastructures.

Québec’s Dominant Hydro Power Boasting more than a million lakes and 4,500 rivers that represent over 40% of Canada’s water resources, Québec’s choice for en-ergy generation was destined to be hydroelectricity. At the end of 2012, the province had an installed capacity of 35,829 MW, but that figure should reach 40,000 MW by 2015, as outlined in the government’s Energy Strategy. With 60 generating stations, 26 large reservoirs, 664 dams and 97 control structures, hydro power currently accounts for roughly 96% of Québec’s power supply; moreover, it represents over 50% of Canada’s total hydro energy. All this impressive portfolio falls under the management of Hydro-Québec, the government owned utility, whose history dates back to 1944. After the development of the gargantuan 15,000 MW James Bay complex in the 1970s and 1980s, Hydro-Québec was not involved in any major projects for several years. However, that changed over the last decade: between 2005 and 2013, Hydro-Québec commissioned a series of large hydro power generating units: Eastmain 1 (480 MW), Eastmain 1-A (768 MW), Sarcelle (150 MW), Toulnustouc (526 MW), Peribonka (385 MW), and Chute-Al-lards and Rapides-des-Couers (138 MW). Furthermore, by 2020, Hydro’s new chef-d’oeuvre, La Romaine (1,550 MW), comprising four units, will also come online. La Romaine 2 is scheduled for commissioning in 2014, while La Romaine 1 will follow suit in 2016.

The nature of hydro power has also allowed for a healthy di-versification of Québec’s energy landscape over the last 10 years, with the government deciding to create a wind power sector in the province. “Québec has the best energy mix people can hope for, with wind and hydro power. We can use wind power in winter, when the output is good, and store precipitation in the dams. Then, during summer, when wind is low, we can use that winter precipitation to smoothen output: it is the ideal scenario,” added Daniel Laplante, president of AIEQ, Québec’s Electric Industry Association.

Hydro-Québec’s activity over the years has led to the formation of a tremendous hydro knowledge base in the province. Com-panies across the hydro supply chain have flourished in Québec and their expertise has become sought-after worldwide. Exp is a diversified engineering firm with presences across the US and Canada. In Québec, the company employs over 1,000 people. In recent years, Exp has been involved in the La Romaine, La Sar-celle, and the Chute Allard and Rapide-des-Coeurs projects, as-

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Global Business ReportsPOWER QUÉBEC

Where hydro power is kingLa Belle Province’s Energy Mix: a task made easy by nature

Boralex’s Ocean Falls hydroelectric dam. Photo courtesy of Boralex

3Global Business Reports // POWER QUÉBECJanuary 2014 3

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Global Business Reports POWER QUÉBEC

suring mechanical and electric works for their auxiliary units. However, the benefits of working in Québec extend abroad. Jean Lavigne, Exp’s vice-president for energy, explained: “In Québec, we have developed expertise in hydro-electricity alongside Hydro-Québec. We leverage and apply this to other markets as well, in places such as Western Canada, Africa and India. The experience we have gained working with Hydro-Québec has enabled us to export our expertise and develop a similar relation-ships with other clients as well.”

Essential actors of the hydro cluster in-clude turbine manufacturing powerhouses such as Alstom Hydro, Andritz Hydro, and Voith Hydro who all have a strong presence in Québec. French giant Alstom has had a powerful impact on Canada’s hydro market, as discussed by Pierre Gauthier, president of Alstom Canada: “Alstom has serviced over half of the Canadian hydro power ca-pacity through its manufacturing plant at Sorel-Tracy. Furthermore, we were recently awarded the La Romaine 2 and 3.”

Beyond new projects, however, Alstom is targeting the rehabilitation market. Since 2012, the town of Sorel-Tracy hosts Alstom’s global center for technology for innovation in hydro retrofitting. “We se-cured the rehabilitation contract for La Grande 2, Hydro-Québec’s biggest power plant. Through our technology we can provide dramatically increased efficiency. Alstom can increase power outputs by 30% just by replacing the plant’s equip-ment, which accounts for only 10% of the project’s cost. Multiply this through the next 50 years and you see that the returns are impressive,” added Gauthier.

Alstom is not the only global turbine manufacturer to have one of its technol-ogy centers in Québec. In 2008, Austrian

Hydro-Québec’s Chenier Static VAR Compensator Substation, 735 kv. Photo courtesy of Exp.

Daniel Laplante, president of AIEQ

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4 Global Business Reports // POWER QUÉBEC January 2014

Please give us an overview of Hydro-Québec’s evolution within the prov-ince, from your founding to your position today as one of the world’s largest producers of hydropower? Hydro-Québec was founded in 1944. We gained scale in the 1960s with the acquisi-tion of a number of local and regional pow-er companies, and in the 1970s and 1980s we developed the 15,000-MW James Bay Hydroelectric Complex. This development really gave us a global standing in terms of generation and transmission. The 1990s saw little development taking place be-cause of lower demand growth. Over the last five to 10 years, however, we have been able to launch a significant new phase of large hydro development, adding 4,000 MW to the system. Our most recent devel-opment is at Romaine, which is a $6.5-bil-lion project. We are currently investing $1.8 billion into high voltage transmission to bring this resource to market.

One key aspect for Hydro-Québec is the quality of communication and relation-ships we have established with First Na-tions aboriginal groups throughout our op-erations. We involve them in our projects from the beginning. They have established businesses in procurement, air transpor-tation, construction, and even catering. In the $5-billion Eastmain Rupert project, we have awarded close to $500 million in contracts to First Nations businesses. At the same time as we are developing these relationships, we are very proud of our environmental record and the way that we are able to install these major hydro de-velopments so as to allow the ecosystems to remain vibrant and productive after the projects are completed.

In April 2013, the New York Public Ser-vice Commission approved a plan to build a 1,000 MW transmission line be-tween Québec and New York City. What impact will this project have on export potential for Hydro-Québec?

of 4,000 MW overall. Hydro-Québec has run large RFPs to meet these mandates. We are purchasing the wind power on behalf of ratepayers in Québec, and we also handle the integration on the grid. To ensure that the wind power would not be a drag on the transmission grid, we pushed our equipment suppliers to put the best that they had into these generators in terms of technical aspects, like low voltage ride through and the ability to supply reactive power. The grid is as robust today as it was before these wind farms were attached to the system. Also, for the first time, Hydro-Québec it-self is going to be developing wind in the coming years.

What expectations do you have for Hydro-Québec’s growth over the next three years?Because our business cycle is long, the generation projects we are looking at right now will be commissioned in the next dec-ade. In the coming year or two we are hop-ing to have one, if not two significant new transmission interconnections under con-struction to New York and New England. This will give us the ability to bring more on-peak power to market, during those periods of higher consumption, and put our storage capacity to better use in the greater Northeast, which will lend greater efficiency to the market.

We anticipate a low commodity price environment for at least the next three to five years because of shale gas, which is a tremendous resource. The absolute level of prices is not going to be at 2008 levels in the foreseeable future, but we have the ability to create strong shareholder value through on-peak sales and the unique storage component of our assets, which is quite large.

Currently, we have 6,000 MW of export capacity to move power to mar-kets in New England, New York, Ontario and New Brunswick. Hydro-Québec’s sys-tem of large-scale hydro reservoirs is the equivalent of a very large wholesale bat-tery for the greater Northeast region. In addition to the renewable hydropower we produce, we store power that we have purchased off-peak with the intention of re-selling it on-peak when power demand is greatest. We can store more power in our reservoirs than a state like New York can consume in a full year. Now we are work-ing on transmission projects to bring more of that power to our export markets. This new project will be a $2 billion-plus, 1,000-MW mainly-underwater direct cur-rent line down the Hudson River through New York state into Queens, New York. Our US partner, TDI, with the backing of the Blackstone Group, has acquired the necessary permits from New York and we are expecting the Presidential permit later this year. We will also need a permit from the US Army Corps of Engineers because we will be laying wire.

Our other key transmission project will also be a high capacity direct current line starting from the Eastern Townships area of Québec, near Sherbrooke, and serving New Hampshire, Connecticut, and Massachusetts. The end point will be Franklin, New Hampshire. This 1,200-MW project is not as advanced as the New York project in terms of the actual permitting process, but it is a key focus for us, working with our US partner, Northeast Utilities.

What role is Hydro-Québec playing to help meet the government’s goal of integrating more wind energy into the province’s power supply?The integration of wind energy on our grid is really a function of how much policy support there is from the government. The Québec government has established wind power supply mandates to the level

Interview with Thierry VandalPRESIDENT AND CEO, HYDRO-QUÉBEC

giant Andritz Hydro acquired several of GE Hydro’s global assets: now, the province hosts Andritz Hydro’s global center of com-petence for Francis turbines. “GE Hydro’s complementary technology and global foot-print made the company very attractive for Andritz Hydro. We acquired low-head envi-ronment technology and at the same time, we were able to benefit from Montreal’s core of engineering expertise: virtually eve-ryone that worked for GE was transferred to Andritz,” said Daniel Carrier, vice-pres-ident of operations at Andritz Hydro. Five years after the GE acquisition, Andritz Hy-dro has consolidated its Canadian business with large projects in British Columbia (BC Hydro’s Mica plant) and Labrador (Nalcor Energy’s Muskrat Falls project). Looking forward, the company is targeting the reha-bilitation market in Québec, as well as ex-panding into new product areas: “We still have a lot to offer to this province’s hydro power industry: our strong local presence and tradition in this environment recom-mend us for future projects. Québec will turn more and more to the refurbishment of existing facilities and since a large part of the existing base was installed by us, that means we have the detailed knowl-edge needed to properly optimize it. We are also interested in seeing the evolution of some of our newer products, such as our hydraulic gates,” noted Keith Pomeroy, vice-president of sales and marketing at Andritz Hydro.

Indeed, with an aging hydro infra-structure, rehabilitation is high on Hydro-Québec’s agenda, and the utility is currently undergoing works at nine of its large hydro structures, among which Beauharnois, La Tuque and Manic 1 and 2.

While the construction and rehabilita-tion of large hydro projects is underway, Québec’s small hydro sector has not been receiving much attention in recent times. IPPs active in this market segment were affected in February 2013, when the government cancelled six such projects, citing economic reasons and the province’s existing energy surplus as its main reasons for it doing so.

Hydro power will undoubtedly remain the backbone of Québec’s energy supply for decades to come. However, with the advent of wind energy and the probable halt of new construction projects after La Romaine, the next step will require the optimization of this increasingly complex

system. Frédéric Schenk, director of in-dustrial services at Swiss certification and testing giant SGS, discussed the sector’s perspectives: “Given the US’s shale gas boom and Québec’s existing energy sur-plus, return maximization will be essential moving forward. Hard-asset knowledge is already very well established in Québec, largely due to Hydro-Québec – the chal-lenge will be to go beyond that; to transi-

tion from the industry’s build phase, to the maintenance and improvement stage of the cycle. This will require building complex predictive models that will optimize the management of dams and basin flow rates, based on such factors as global warming and weather variability. Furthermore, green energy sources will also have to be proper-ly managed and integrated within the sys-tem. Lastly, by incorporating a good market

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5Global Business Reports // POWER QUÉBECJanuary 2014 5

ent Power Producers), Hydro-Québec was to achieve a wind power generation target of 4,000 MW by 2015, an equivalent of 10% of the province’s energy supply. Be-yond the goal of diversifying the province’s power portfolio with another green alterna-tive, the decision also had strong social and political considerations.

With a population of roughly 94,000, the Gaspésie–Îles-de-la-Madeleine is an administrative region located in Québec’s extreme east: traditionally reliant on indus-tries such as fishing, pulp and paper, and mining, the region entered a state of eco-nomic depression in the early 2000s when several key businesses shut down. None-theless, when everything was down, wind picked up. The government’s call for wind power was destined to revive the Gaspé-sie, by exploiting its eolic potential. Seven years later, in September 2013, 1,866 MW of wind-power were already operational, with another 1,596 MW under construc-tion. “Québec now has 5,000 wind-indus-try related employees and nearly 1,200 of them work in the Gaspésie. There is a wealth of consulting expertise and there are also a number of research institutes, including the TechnoCentre éolien, a unique organization specializing in north-ern wind conditions and icing,” said Alex Couture, director of project development at EDF EN Canada, an EDF Energies Nouvelles subsidiary with a vast wind energy portfolio in Québec.

The first major development occurred in 2003, when Hydro-Québec Distribution is-sued the first 1,000 MW RFP, which was shortly followed by a second 2,000 MW RFP in 2005. In 2009, a third, 500 MW RFP, was put forth: 250 MW were destined for municipalities, while the other 250 MW were aimed at Aboriginal communities. By the late 2000s, the minimum 30% Gaspé-sie local content requirements had led to the establishment of a healthy supply chain in the peninsula, with companies such as Fabrication Delta (wind-towers), Compos-ites VCI (nacelles), Marmen (wind-towers) and LM WindPower (wind-blades) setting up dedicated shops across the region. Fi-nally, in May 2013, Québec’s current pre-mier, Pauline Marois, completed her pre-decessor’s 4,000 MW promise and even went the extra mile with 100 MW by an-nouncing a final 800 MW RFP, that would bring investments of C$2 billion. This latest batch would be assigned in four blocks: 150

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6 Global Business Reports // POWER QUÉBEC

Gaspésie’s Wind Sector

The Outset – Diversifying Québec’s energy portfolio while reviving an economically depressed region

In 2006, Jean Charest, Québec’s liberal party premier at the time, unveiled his 2006-2015 Energy Strategy, one which would dramatically change the province’s power landscape: through IPPs (Independ-

Hydraulic turbine test lab- Lachine QC. Photo courtesy of Andritz Hydro

understanding within this complex picture, strong decision support systems can be created – these will allow for highly accu-rate recommendations to be offered to the decision makers in charge of managing the hydro-electricity assets, integrating some-times conflicting goals such as maximizing income, flood protection and environmen-tal protection. SGS will continue to grow its expertise with the province’s strong hy-dro cluster and we will leverage Québec’s value and knowledge base for the benefit of our global organization.”

January 2014

MW for the Assembly of Mi’gmaq commu-nities of Québec, 300 MW for competi-tive bidding in the Gaspésie, 150 MW for other parts of Québec and, for the first time, 200 MW of projects to be developed by Hydro-Québec itself.

Founded in 1991 in Ontario, First Cana-dian Title, part of FAF International, pro-vides title insurances and other real-estate related services to a wide market, and the company has taken advantage of the wind sector developments in Québec to extend its reach. “We can insure any type of real estate in the energy sector, including those of high value. We have recently been focus-ing on windmill farm projects; historically, we have insured hydroelectricity projects in the province. Contiguity of land is essen-tial for an energy/power project; a leading facet we insure. Québec has an excellent land registry system with little risk and ti-tle insurance is affordable to the investors; nonetheless, title problems may still occur. Insurance should be a fundamental part of a transaction,” stated Laurent Nadeau, CEO for Québec at First Canadian Title.

From Development to Operation – Québec’s Wind Power IPPs and their 300 feet tall machines

Cartier Wind Energy, a 2004-founded joint-venture between TransCanada Pipe-line and Innergex, is one of Gaspésie’s major developers. Cartier won 600 MW during the first RFP and now oper-ates five wind parks: Baie-des-Sables (109.5 MW), Anse-à-Valleau (100.5 MW), Carleton (109.5 MW), Gros-Morne (211.5 MW) and Montagne Sèche (58.5 MW). “Cartier was the first company to accelerate the wind sector value chain in Québec. We have been a pioneer in many ways, especially in management and social acceptability. The ministry has used our documentation and experience as a framework for wind energy for the next 2000 MW bids, making Cartier a model for other developers. Our focus will now be on the operational side of wind parks, coping with the extreme elements of the north like ice-rain, heavy snow, and low temperature. We have over 300 kilo-meters of road, 310 kilometers of power transmission lines, and five power substa-tions within our wind parks to keep them operational,” explained Robert Guillemette, CEO of Cartier Wind Energy.

Northland Power, a Canadian IPP estab-lished in 1987, was the other big winner of the first RFP, with its Jardin D’Éole (127.5 MW) and Mont Louis (100.5 MW) wind pro-jects, which were brought online in 2009 and 2011 respectively. Now, the company, which has a portfolio of 1,300 MW of op-erational assets, is turning its attention to community and municipality projects: “In Québec we are working with a par-ticular entity (Regie), which is an organiza-

tion formed by multiple RCMs (Regional County Municipalities), in our case, five, to solve the financing issues that often occur with municipality projects, which are usu-ally smaller in scope,” said Robert Demers, business development director for Québec at Northland Power.

EDF EN Canada is one of the ma-jor winners of the second and third RFPs; since 2009, the company man-aged to secure over 1,000 MW of

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7Global Business Reports // POWER QUÉBEC 7

Alex Couture, Project Deveopment Director,

EDF EN Canada Robert Guillemette, CEO,

Cartier Wind Energy

January 2014

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wind power projects in Québec, which will all be completed by 2015. Massif du Sud (150 MW), Lac Alfred I (150 MW), Lac Al-fred II (150 MW), and Saint-Robert-Bellarmin (80 MW) are EDF EN’s main operating assets at the moment. “RFPs in Québec are far better structured and more straightforward than other provinces. However, it is important to understand the dominance of French in the Québec energy sector; every contract with Hydro Québec is in French,” noted Couture.

“The standards in Québec are very high. It is probably the tough-est grid to connect to from a regulations standpoint, but it is worth it because it is a strong, reliable grid. In 2011, EDF EN Canada had nothing built in Québec. Two years later, we have a tremendous amount of knowledge on how to build wind farms in Québec and how to see things. One of the innovative strategies we employed was to erect turbines very early on – this showed great foresight, as it allowed getting the teething process out of the way early,” added David Gallagher, program manager at EDF EN.

The exclusive turbine provider for EDF EN’s Québec wind farms is REpower Systems Inc. Canada, a subsidiary of the global Ger-man-based group. Over the last years, the group Canadian’s pres-ence grew impressively, from three employees in 2010, to over 100 today. “Québec was our point of entry into the Canadian mar-ket. 2012 was a record year for us, in which we installed 200 ma-chines, for a total of more than 400 MW and in 2013 we reached the 550 MW mark. REpower’s Canadian subsidiary comprises 10-15% of REpower’s global turnover, a high figure considering

that we have subsidiaries in ten countries. Today, because of the confidence earned from our Montreal office’s track record of suc-cess, all of REpower’s North American operations are managed out of Montreal. Our approach has been to use even more local resources than were required. We utilize blades manufactured in Gaspé by LM Wind Power, which also happens to be our global supplier, and towers produced in Matane by Marmen. We already use Marmen for projects in the United States, which demonstrates that Québec’s plan to create local champions in the wind sector is really working. Overall, between 46% and 49% of the value of REpower’s turbines is created in Québec,” said Helmut Herold,

Northland Power’s Mont Louis Wind Farm, photographed by Joan Sullivan.

January 2014

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CEO of REpower Systems Inc. Canada.One of Cartier’s parent companies, In-

nergex Renewable Energies, is a Canadian IPP with a diversified renewables portfolio that contains hydro, wind and solar pro-jects, for a total capacity of 617 MW. In May 2013, Innergex was awarded the 150 MW wind project for the assembly of Mi’gmaq communities of Québec. “Innergex has been very proactive with respect to First Nation partnerships; we are very proud of this achievement and over the years, we have built a corporate culture of openness in understanding how First Nations operate in the market in Canada,” explained Michel Letellier, President and CEO of Innergex. “Nonetheless, we would like to see a standardization of regulations across the energetic markets when it comes to envi-ronmental supervision. Renewable energy IPPs have many environmental criteria that they need to uphold and we are perfectly happy to do that but, at the same time, we are in direct competition with other energy sector players that are not subjected to the same rules,” added Letellier.

Pauline Marois’ new 800 MW RFP gave the sector some reasons to celebrate, al-beit not enough for a market with so many active players, hungry for business. Vestas traditionally occupied the first position in the global market shares for wind turbines, but recent years have seen it struggle to maintain that title, with GE and China’s Sinovel challenging its authority. Present at the very beginning of Québec’s wind energy development, the Danish compa-ny did not get involved in any of the first major RFPs. “In Canada, we are still have the largest market share (around 35% of the total capacity), with an installed base of over 2,500 MW. Now, Vestas is back in Québec and we are going to be compet-

ing hard; sales is like hockey – sometimes you get checked but then you need to get back up, to show people that you can take a hit and keep ticking. So look out for Vestas to reestablish its dominance in Canada,” said Chris Brown, president of Vestas, US and Canada.

Coping with Remote LocationChallenges

The remote placement of wind farms has also triggered the development of comple-mentary infrastructure across Québec’s extreme east. Consequently, assuring lo-gistical and power support in these regions during construction and operations has been a key issue to tackle for developers. But where some sees challenges, others see opportunities.

A traditional player in providing temporary power and temperature control solutions to remote locations is Aggreko, which in 2013 celebrated 50 years of existence. The com-pany has been steadily increasing its pres-ence in Canada in recent times – notably,

in Western Canada. “Now, we are shifting our attention to Eastern Canada, where we see tremendous potential for our solutions, given the natural resource investments presently going on,” said Peter Brouwer, vice president Eastern Canada Aggreko. “Aggreko has technicians throughout East-ern Canada and our preventative mainte-nance programs are very strong. Real-time monitoring by a dedicated team from our Remote Operations Center quickly trouble-shoots issues to maximize uptime, a criti-cal element for remote communities. We are expanding and opening service centers across Québec and we benefit from one of the newest fleets in the province. Aggreko provides off-grid commissioning for IPPs that develop wind farms: in Québec we collaborated with Northland Power on one such project. We managed to deliver the project on time and on budget, and most importantly, in a safe manner. We see good future potential for this in Québec, given the government’s openness to renewable energy sources,” added Brouwer.

SDV Canada, part of the Bolloré Group,

Michel Letellier, President and CEO, Innergex

January 2014

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10 Global Business Reports // POWER QUÉBEC October 2013

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ments of the wind energy sector in Québec can act as an opportunity for us because of the often remote locations of wind farms; furthermore, these projects also lead to the construction of adjacent roads, a process which we can also support,” noted Erik Thorsrud, president of Atlas Copco Con-struction Equipment Canada.

Future Success – Different Pathsfor Different Players

Looking forward, it is difficult to foresee how Québec alone will be able to sustain all of Gaspésie’s dynamic wind players. With a new Energy Strategy expected for 2014, optimists hope to see an increase of the 10% share wind energy has in the province’s power mix. However, Québec’s energy surplus and the US’ shale gas fren-zy do not currently prompt the need for more MW generation. While the province’s wind repowering cycle starts in 2024, cur-rent works will keep players busy only until 2017. “According to one of our studies, Gas-pésie’s players need a minimum market of 300 to 350 MW per year to survive; even so, they would be working only at a 40% capacity rate,” said Frédéric Côté, general manager of TehnoCentre éolien, which played an essential role in developing Gas-pésie’s wind cluster.

Until 2024, new business for IPPs such as Boralex, a big second RFP winner, with projects such as the 272 MW Seigneurie de Beaupré wind farm, will depend exclusively on calls for tenders. On the oth-er hand, local maintenance service provid-ers such as Techéol, East Coast Wind and Suspendem Rope Access will be finding plenty of work in Québec, as wind farms are gradually coming out of their warran-ties. However, the most challenging and exciting path ahead will be the one for Gaspésie’s home-grown manufacturers, such as Composites VCI and Fabrication Delta, which will survive by competing on the global markets. Already, Compos-ites VCI has shifted its manufacturing fa-cilities to Brazil, where it is accompanying its traditional Gaspésie partner, GE. Meanwhile, Fabrication Delta will be look-ing to leverage its strategically-placed New Richmond plant to engage the north-eastern American markets.

Having outgrown Québec, these compa-nies will take the fight abroad, where sur-vival of the fittest will determine success.

is a Québecois logistics company whose history dates back to 1967 and which has seen its energy business become more important in recent years, notably through wind sector developments. Roger Ger-vais, president of SDV Canada, discussed the company’s focus: “We have a spe-cialty in power plant and windmill projects, but at the same time, one of our main and longstanding clients is Alstom Hydro. Although our interest in the wind sector is recent, we have already done three big projects. We delivered them success-fully, and in this small industry clients talk amongst themselves. During 2013, SDV was already preparing for the work it was awarded for 2014 for the big-gest wind farm in Canada, the Parc des Laurentides. Foresight is especially impor-tant in the wind sector, where we have to deliver one complete tower every day – if ever we fail, construction has to be postponed and there will be 400 inactive workers, at great expense.”

Meanwhile, Atlas Copco, which celebrated 140 years of existence in 2013, has made a name for itself in Canada and the world through its comprehensive mining sector services. Now, a new divi-sion, dedicated to construction projects across the country, is trying to leverage the company’s cross-sectorial ties to make an impact in Québec: “Canada’s East Coast development will be driven by projects in which Québec will have a big role to play, such as the Energy East Pipeline. This potential prompts us to look at ways of expanding our footprint here. In Québec, we are targeting power projects, which, during the phase of their construction, will require portable energy sources – this is where we can shine with our pokers and diesel-fueled generator sets. The develop-

Erik Thorsrud, general manager, Atlas Copco Construction

January 2014

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Québec’s Solar Energy –In the shadow of hydroand wind With its recent pro-wind policies and its abundance of lakes and rivers, Québec has not left much room to grow for its solar power segment. Even so, some support initiatives have surfaced in recent years: in March 2012, Québec’s Ministry of Natu-ral Resources announced the creation of the PAIESO program, a C$7 million fund aimed at supporting the installation of solar thermal and photovoltaic systems. Overall however, the implementation of large-scale solar projects is still far from becoming real-ity in the province, as Jean-Francois Sam-ray, president of AQPER, Québec’s Renew-able Energy Association, explained: “It will be tough for solar to connect to the grid, as Québec is already active in other renew-able technologies. A paper by the Edison Research Centre demonstrated that given

its relatively cheap cost, the more popular solar power becomes, the more it will jeop-ardize the way electricity is charged to the consumer. More individual solar electricity production means less grid-kWh consump-tion; still, the network’s maintenance costs will be there, which would lead to more expensive kWh rates. Subsequently, even more people would move to solar – but the grid has to exist. On the other hand, Québec still has many remote areas where people can use solar technologies, so there will always be a market for it.”

Momentarily however, Québec’s solar opportunities lie mainly in off-grid and mini-grid installations. Founded in 2009, Rackam is a Québecois company that benefited from Québec’s IRAP (Industrial Research Assistance Program) financial support dur-ing its incipient development phases – now, the company specializes in providing solar thermal power to industrial players. Having spent two years developing its concentrat-ed solar power technology and showcasing its potential, the company is now launching its two first large projects. Moreover, look-

ing beyond Québec, Rackam is targeting international expansion. Mathieu Chagnon, president of Rackam, discussed his com-pany’s future markets of interest: “We are a Québec-based company because a lot of good engineering is here, and there are good opportunities for research and to find investors. A large part of our supply chain is also Québecois, but our market is mostly international. We pursue two paths of re-search in partnership with the University of Sherbrooke and during our early research we were able to receive federal govern-ment subsidies. In two years, we will cer-tainly have business activities in the US and Europe. Rackam is evaluating many foreign projects, and will continue to look at many more in the future.”

Looking in the long-term, the key for scal-ing up solar power in Québec will be to at-tract political support, as Brian Wilkinson, president of Matrix Energy, a Québecois solar photovoltaic company with 28 years of experience in the field, concluded: “Very few solar programs in the world have made economic sense thus far, but every utility

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in the world exists because of government subsidies. The idea that solar technology is incompatible with the grid is false. Today, you can put in a photovoltaic system for not much more than C$1.50/watt and it will last more than 25 years. Québec can flood more territory, use wind, or engage in frack-ing – all these options have their issues. On the other hand, we have a reserve sitting there in the sky that in one hour produces the world’s energy needs for a year.”

Québec’s Ample Power Transmission and Distribution

Hydro-Québec’s transmission and distribu-tion arms, Hydro-Québec TransÉnergie and Hydro-Québec Distribution, operate the most extensive network in North America, covering 33,639 km of lines and 516 sub-stations. To capitalize on the province’s en-ergy surplus, strong ties have been made with other Canadian provinces, as well as with the US: 17 interconnections exist between Québec and systems in Ontario, New Brunswick and the NE of the US, with a total export capacity of 7,994 MW.

The network’s sheer size, alongside Québec’s need to efficiently integrate its new wind energy supply, has brought smart grid technologies to the forefront of discussions in recent times: a big role in the development of the necessary pro-cesses is played by Hydro-Québec’s IREQ research center, an organization renowned worldwide for its technological prowess. With over 35 years of experience in re-mote management and network automa-tion, Vizimax is a Québecois company that resulted from the merger of SNEMO, an electrical product manufacturer and STR, a utilities engineering consulting firm. Jean-Guy Lacombe, CEO of Vizimax, discussed the company’s collaboration with Hydro-Québec and the integration of renewables to the grid: “Our objective in the power in-dustry is to move from master/slave archi-tecture to client/server architecture where smart-grid power will be distributed in the field. Smart Grid automation is a special-ized market – there is no room for experi-mentation. When Hydro-Québec requires new technology or assistance, they look to Vizimax to work with IREQ to find a solu-tion. One of our recent projects helps five

small wind parks connect to the grid with-out causing noise disturbance, electricity tipping, or consequent power outages on the network. Québec will however see a lull in building new hydro generation pro-jects. This is why Hydro-Québec is seeking to sell its expertise globally and secure new project streams. Vizimax will follow that trend and look outward as well.”

Québec – A naturally fit data-center hostingenvironmentIn June 2013, Swedish networking pow-erhouse Ericsson AB announced plans to build a new information technology cent-er in Montreal, a project that will attract more than C$1 billion in investments into Québec. Ericsson’s data center is just one of the many facilities of its kind scheduled for commissioning in the province: with an excess of cheap, clean energy, Québec is quickly stepping up to become a jurisdic-tion of preference for this energy-intensive industry, which is projected to spend $126 billion annually by 2015. Jeff Edward, vice president operation at Cogeco Data Ser-vices, explained the market’s demand dy-namics: “In this tough economic environ-ment, companies started to analyze their overheads more closely and realized that the construction and maintenance of IT in-frastructure is one of their major cost driv-ers; however, since this is only an auxiliary component of their activity, they are now increasingly outsourcing it to companies like ours so they can take a step back and focus on their core business.” Cogeco Data Services gained an important footprint in Québec through the acquisition of MTO

Jean-Guy Lacombe, CEO, Vizimax,

January 2014

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Telecom in 2011 and now, the company is working on developing its new flagship pro-ject in Montreal.

“Québec is an ideal place for the place-ment of data centers. Firstly, cold climates offset the tremendous heating loads that the computers themselves have. Secondly, since data transfer is a key issue, Québec’s excellent IT infrastructure places it ahead of other jurisdictions. Finally, since data centers deal with highly sensitive informa-tion, they must be located in geo-politically suitable environments, and Québec is just that,” said Benoît Parent, general manager for power generation, Cummins Eastern Canada. The company provides generator-sets for standby, prime power, and continu-ous applications, and has identified the data center business as being one of its prime targets in Québec. “Cummins Eastern Canada has been involved with data center systems for some time and we benefit from having dedicated sales and service teams in Québec and an emergency rapid response team in Mississauga. We sup-ply the generator sets, the switchgear and the various schemes that allow Tier III and Tier IV reliability standards for data centers. Since generators are often placed together in enclosed spaces, Cummins Eastern Can-ada offers fire proof modularization for its products. Consequently, we offset the risk of the entire system going offline due to an accident occurring with just one of the components,” described Parent.

Data centers are more energy-intensive today than ever and thus, power availability and costs are essential for their economic feasibility. “Data centers are notorious for consuming large amounts of energy so any low-cost environment automatically be-comes very attractive for the industry. With its extremely competitive power prices and

its energy surplus, Québec is the perfect market. We now see tremendous opportu-nities in this province, which is going to be our key target over the next years,” noted Vello Ehvert, president of Ehvert Mission Critical, a company that specializes in the engineering, procurement, construction, integration and support of data centers.

The sector has also benefited from a recent shift in the provincial government’s

policy towards it. As opposed to Scandi-navian and US authorities, Québec’s pre-vious liberal government did not offer the tax breaks and the preferential electric-ity prices needed to attract the industry’s heavyweights. The sector was deemed not sufficiently attractive from a job-creation perspective, a sensitive issue in Québec, which saw its employment rate grow only 0.8% in 2012. Now, Pauline Marois’s ad-

January 2014

Benoît Parent, general manager for power generation,

Cummins Eastern Canada

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as NYC and Toronto’s costs were more than double that figure, at 11.55 c/kWh and 10.60 c/kWh, respectively. Stimulating effi-ciencies in this context was always going to be an uphill battle for Québec’s energy efficiency players, even with a helping hand from their government.

“The 1990s was a tough period for the energy efficiency market as power was relatively cheap. However, in 2000, the price of gas escalated, creating a new market for energy efficiency. During this period, Québec’s Liberal government intro-

duced new legislation that institutions should reduce their energy consumption by 15% and attached to this legislation were grants and rebates,” explained André Rochette, founder of Ecosystem, a company specialized in HVAC (heating, ventilation and air-conditioning/cooling) management. Since its creation in 1993, Ecosystem expanded its reach abroad (Toronto/NYC), while also securing local landmark projects, such as Montréal Biodôme’s energy optimization.

Heat recovery systems are also Sofame Technologies’ speciali-zation. Set up in 1984, the business has since developed innova-tive proprietary technologies, such as the Percotherm®, Percof-rac™, or Percomax® industrial-scale water heaters; to date, the company has over 330 projects in its portfolio. John Gocek, CEO of Sofame Technologies, discussed the market’s receptiveness: “Québec has been a productive market for us; it is a high heating zone because of its cold temperatures. It is not difficult to explain to our customers the cost saving and environmental benefits of recovering waste heat. Since 2008, customers’ budgets have been tight however – that is a high hurdle, but we are still finding lots of opportunities at large power plants and multinational corpora-tions with environmental objectives. The big trend today is district integrated cogeneration plants, emitting waste heat at various high temperatures; Sofame’s direct contact technology recovers almost 100% of waste heat, regardless of scale. A high-profile project for Sofame and recipient of an ASHRAE award is Montréal’s Trudeau Airport; we are achieving 97% boiler-room efficiency, and the air-port is being heated at 140F by waste heat from the boilers. The project has become the model for future heating in the industry.”

Initially founded as a systems’ integration firm, Distech Controls is a Québec-grown energy management company which saw its international business take off in the early 2000s in markets such as Asia and Europe. Having been one of the first Canadian com-panies to adopt open systems and standards for energy control technology, Distech is now targeting the full spectrum of com-mercial and institutional buildings: “Distech Controls pushed the implementation of open standards further, by standardizing our technology solution on recognized open protocols not only for the products themselves, but also by embracing “open” business prac-tices. As an example, we made our programming software freely available, to all end user clients. Combining open technologies with an open business model, clients could optimize and improve their processes, select best of breed products, only limited by their needs, and this changed the way business was done at the time. Building owners want comfort, energy efficiency and to make their buildings greener – they seek freedom when it comes to technol-

6.4 MW of uninteruptable power. Photo courtesy of Kelvin Emtech

ministration has promised Hydro Québec’s preferential L pricing rate for large power users and a 10 year corporate tax holiday for companies investing more than C$300 million in data centers. Nonetheless, these measures were not the decisive factors for the private sector players’ interest in Québec “The current incentive scheme’s barrier-to-entry is too high, even for a pro-ject of our scale, of 100,000 square feet. However, there is a tremendous amount of IT infrastructure expertise in Québec, which also has a lot of pent-up demand for data center space: overall, we are very excited about this market’s perspectives,” concluded Edward.

Energy efficiency’s fight in a low-costelectricity environment Québec’s abundant power generation has made the province a continental leader in low-cost electricity. Recent Hydro-Québec studies show that the average electricity prices in Montreal for residential customers were 6.76 c/kWh, compared to 22.57 c/kWh in NYC, or 13.89 c/kWh in Calgary. Furthermore, for large power customers, Montreal prices were at the 4.76 c/kWh mark, where-

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ogy and do not want to be tied in with one supplier or another,” said Etienne Veilleux, president and CEO, Distech Controls.

Looking ahead, construction-market regulations will strongly influence re-gional business; nonetheless, competing in Québec’s tough environment has ena-bled these companies to have the edge abroad. “The Québec-gained expertise made it easier for Ecosystem to enter ju-risdictions with higher electricity prices and our strongest growth potential at the moment is in New York and Toronto. Québec’s current low prices of electricity and gas, as well as the government’s lack of direction on energy policies, dilute the desire to activate energy-efficient projects. We are hoping that the expertise built in Québec in this field will not be lost due to a lack of vision,” noted Rochette. “The biggest fac-tors of growth for the future of our segment are construction and government regulations; the future looks good for our line of business,” added Veilleux.

Biogas/Biofuel Opportunities and Conclusion“In spite of Hydro-Québec’s dominance, Québec is still a strong, open market,” said Peter Morel, president of Pöyry Montreal, one of the two offices responsible for the northeastern North-American market for the Finnish multinational engineering com-pany. Traditionally strong in Québec’s forestry industry, Pöyry has recently shifted its attention to opportunities in bio-fuels and biomass. “While Québec is home to some interesting biomass-powered cogeneration projects, the low costs and high efficien-cy of hydroelectric power leave little room for diversification into large-scale biomass energy production,” noted Morel. “We will however stay focused in second generation biofuels like etha-nol – there is good interest there, because it produces energy while reducing carbon footprints,” added Zennie Lamarre, vice president of projects at Pöyry Montreal.

Indeed, biofuel and biogas opportunities are out there for the taking in Québec. Traditionally proficient in organic waste dewatering and drying, Groupe Berlie-Falco has recently focused on also providing biogas energetic output to its munici-pal and industrial clients, through the process of anaerobic diges-tion. Having already obtained visibility in foreign markets such as the Middle East, Groupe Berlie-Falco is now targeting its domestic market: “Canada offers good support for the industry, given the C$650 million subsidy program for composting and biogas plants. Québec’s goal of eliminating organic waste go-ing to landfills by 2020 is very ambitious and the fact that the province is part of the Western Climate Initiative are both signs of its commitment to reducing greenhouse gas emissions. However, the province needs to also provide the financial in-centives necessary to attract the private sector on board – this would make business self-sustainable for the future. Nonethe-less, we believe 2014 will be a very active year in our segment,”

noted Bertrand Blanchette, co-president of Groupe Berlie-Falco.

Considering its innovation-prone biofuel/biogas players, such as Enerkem, Québec might want to reconsider its future en-ergy mix plans: “The trend towards even more environmentally-friendly and innova-tive ways of producing power has brought with it a lot of debate on diversification into other energy sources in Québec. The gov-ernment is certainly aware of these con-cerns, but it may be a while before we see significant shifts in the market structure,” concluded Morel.

In the meantime, the year 2014 will bring forth Québec’s new Ener-gy Strategy: one of the most daring ideas on its agenda will be the im-plementation of electric transportation in Québec, an initiative which would decrease fossil fuel dependence, lower emissions, and make good use of the province’s extra megawatts. While inno-vative initiatives, such as the Electric Circuit and the lithium iron phosphate batteries have been developed by Hydro-Québec in recent years to facilitate electric transport, the complete implementation of this ambitious plan is still on the horizon. More immediately, rather than looking inwards, Québec’s energy industry players will have to direct their efforts to more attrac-tive foreign jurisdictions, while leveraging their province’s strong engineering and technological base.

Enerkem produces biofuels and chemicals from non recyclable household garbage. Photo courtesy of Enerkem

January 2014


PRBCUG AwARds

TransAlta’s Centralia Plant Earns PRBCUG AwardCompleting the difficult transition to 100% Powder River Basin coal earned TransAl-

ta’s Centralia plant in southwest Washington some well-deserved recognition. Dr. Robert Peltier, PE

The Powder River Basin Coal Users’ Group (PRBCUG) recognized Tran-sAlta’s two-unit, 1,340-MW Cen-

tralia Complex with its 2013 Plant of the Year (Large Plant category) award at its 2013 Annual Meeting, collocated with the ELECTRIC POWER Conference & Exhi-bition last May (Figure 1). The plant was recognized for its excellent safety and dust control program, its completion of exten-sive boiler upgrades and modifications, and its expansion in rail operations to han-dle PRB coal.

TransAlta owns a fleet of 75 plants con-centrated in Canada with 22% of its net ca-pacity located in the Northwest. TransAlta’s U.S. headquarters is in Olympia, Wash. The largest of TransAlta’s U.S. assets is its Cen-tralia Complex, in southwest Washington. Unit 1 entered commercial operation in Sep-tember 1971 and Unit 2 followed 12 months later (Figure 2).

Plant staff have described the fuel conver-sion project as a “journey,” much like others

who have successfully converted their facili-ties to burn PRB coal. The PRB Coal Users’ Group exists to encourage and provide tech-nical support for those making the same jour-ney (www.prbcoals.com).

Centralia completed early PRB test burns from 1989 to 1991 and began burning 30% PRB coal in 1992. The conversion to 100% PRB coal was completed in late 2008 with the closure of the local coal mine that had supplied the plant with fuel since the units were commissioned.

The plant safety modifications completed at Centralia that were necessary to burn PRB coal included installation of a pulverizer inerting system, conveyor transfer fogging systems, silo dust collection system, and CO detection and other fire detection and sup-pression systems. Installation of the pulveriz-er inerting systems eliminated the pulverizer duct explosions or “puffs” that began with burning PRB coal.

Boiler upgrades to burn 100% PRB coal were also required. The high-calcium coal

caused significant unit derates from exces-sive back end temperatures, bottom ash slag-ging, and convection pass fouling. In 2007, Fuel Tech’s TIFI system was installed in both units, and in 2008 Unit 2’s reheater and econ-omizer were modified and 22 new sootblow-ers were added, among many other boiler modifications completed on both units.

Coal delivery and unloading facilities were also upgraded with the construction of two new rail sidings capable of handling three-unit trains simultaneously and a new unloading rail loop to facilitate the increased use of PRB coal. Unfortunately, the fly ash now produced is not as marketable as that produced when burning a local coal, so the amount of waste ash produced increased as PRB coal use increased. The lower amounts of synthetic gypsum produced from re-duced-sulfur PRB coal also reduced the sales to wallboard manufacturers.

Our congratulations to Centralia’s plant staff for a successful conclusion to their PRB coal conversion journey and its well-deserved selection as the PRBCUG’s Plant of the Year (Large Plant). ■

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

1. Award-winning plant. Representatives of TransAlta’s Centralia Plant received the PRBCUG Plant of the Year (Large Plant) trophy in recognition of the plant’s successful comple-tion of its conversion to burn PRB coal. Source: POWER

2. Winning combination. TransAlta’s 1,340-MW Centralia Complex was the PRB-CUG’s 2013 Plant of the Year (Large Plant). Courtesy: TransAlta


PRBCUG AWARDS

OPPD’s North Omaha Station Takes PRBCUG HonorsThe Omaha Public Power District (OPPD), one of the largest publicly owned utilities

in the U.S., generates approximately one-half of its electricity by burning coal. OPPD’s North Omaha Station began using low-sulfur coal from Wyoming’s Powder River Basin in 1985. Plant upgrades that increased plant safety and the reliability of plant operations were recently recognized by the PRBCUG with its 2013 Plant of the Year award.

By Dr. Robert Peltier, PE

The Powder River Basin Coal Users’ Group (PRBCUG) each year since 2000 honors one or two plants that burn PRB

coal for “innovation and implementation of best practices and continual improvements in areas including safety, environmental perfor-mance, coal handling, boiler combustion, and risk management.” In addition to Plant of the Year honors, the selected plant is also inducted into the PRBCUG Power Plant Hall of Fame.

For 2013, the Plant of the Year (Small Plant Category) honors were garnered by Omaha Public Power District’s (OPPD) North Omaha Station (NOS). The trophy pre-sentation and recognition for the outstanding work by the plant staff took place during the May 2013 ELECTRIC POWER Conference & Exhibition, the venue for the annual meet-

ing of the PRBCUG (Figure 1). The Plant of the Year (Large Plant Category) award was presented to TransAlta’s Centralia Genera-tion Plant (see p. 62). Additional information about the PRBCUG, its 2014 annual meet-ing, and the group’s awards program is avail-able at www.prbcoals.com.

The North Omaha Station consists of five units with a combined capacity of 625 MW and is part of the 3,200-MW OPPD system. The last unit entered commercial operation in 1968, 14 years after the first unit was con-structed. NOS was originally designed to com-bust Midwestern high-sulfur coal. In 1985, the attractive environmental advantages and cost-effectiveness of PRB coal resulted in the deci-sion to transition the station to the low-sulfur coal. The lower heat content and higher ash content of the subbituminous coal meant that the coal burn rate would have to increase in order to deliver the same fuel energy content compared to bituminous coal, although the plant was not derated as has occurred at other plants. In addition, the entire fuel system—from unloading on the coal pile through the burner tip—required upgrades in equipment,

plant operating processes, and additional training of the plant staff. Safe combustion of PRB coal is an intentional process. The 105-person staff of NOS joined in the common goal to become a leader in safe handling and combustion of PRB coal (Figure 2).

A few years ago, NOS decided it was time to upgrade the antiquated material-handling system to improve safety and plant reliability. NOS partnered with Martin Engineering to perform a safety and equipment audit that rec-ommended cost-effective equipment upgrades to simultaneously improve plant operational reliability and reduce coal fugitive emissions, a key safety challenge when burning PRB coal.

After a series of discussions, OPPD de-veloped a four-phase material-handling im-provement program. The first equipment upgrade phase began in October 2009, and all four phases were completed in 2012. Specifi-cally, the material handling upgrade program included equipment changes and upgrades in the Shaker House, where the coal is unloaded from rail cars; the Crusher House, which re-ceives and processes the coal received from the Shaker House; the Transfer House; the Tripper Room, which feeds the coal to the in-dividual boiler fuel silos; and all the convey-ors that interconnect the plant (Figure 3).

The coal dust management program en-tailed rebuilding all the plant’s coal-handling transfer points including all vulcanized splic-es in the conveyor system, impact beds, and belt supports. In addition, improved equip-ment was added or replaced existing, such as taller chute walls, new apron seals, and dual dust curtains. All the original roller bearings on the conveying systems were replaced with sealed roller bearings. Winged tail pulleys were replaced with smooth tail pulleys, and return plows and belt trainers were added. Also, problematic contacting flow switches used on the conveying systems were replaced with noncontacting sensors.

1. The first team. Representatives of OP-PD’s North Omaha Station plant staff received the coveted PRBCUG Plant of the Year Award (Small Plant Category) at the past annual PRB-CUG conference, held jointly with the ELEC-TRIC POWER Conference & Exhibition. From left to right, David Wetrosky, Plant Manager, OPPD; David Wilson, Yard Equipment Opera-tor, OPPD; Randy Rahm, Executive Director, PRBCUG; Pat Baker, Crew Leader, OPPD; John Bridson, Chairman, PRBCUG; Kirk Es-tee, Operations Superintendent, OPPD; Wil-liam Konefes, Vice Chairman, PRBCUG; Brian Langel, Manager-Production Engineering, OPPD and Greg Krieser, Division Manager, OPPD Source: POWER

2. Making the switch. OPPD’s North Omaha Station is composed of five units pro-ducing a total of 625 MW. The fifth unit was installed in 1968, the first unit 14 years ear-lier. The plant made the switch to PRB coal in 1985 and finished a complete upgrade of the plant’s fuel-handling systems in 2012. Cour-tesy: OPPD


PRBCUG AWARDS

The Crusher House and the Shaker House were originally designed with last-genera-tion dust collection systems, each of which included a collector, blower, disposal sys-tem, and long lengths of ducting and many high-maintenance isolation valves. Both dust collection systems were removed from ser-vice as part of the project, thus eliminating a potential explosion hazard. In their place, Martin Engineering installed insertable dust filter systems in 12 high-dust zones. Instead of conveying dust-laden air to a central dust collector, the insertable system filters the air at the transfer point so the dust can be imme-diately returned to the conveying system. The dust is captured on a pleated fiber filter that is periodically cleaned using compressed air injected against the reverse side of the filter. Each filter system has two filter elements so that one filter remains in service during the staggered cleaning cycles. Unlike standard filter elements, the filter material is impreg-nated with carbon fibers so that a buildup of static electricity is not possible (Figure 4).

The plant’s coal chutes had also taken a beating over the years, with several areas where severe erosion had resulted in open-ings that allowed coal leaks. The chutes were relined as part of the upgrade project.

A “belt and suspenders” approach was taken when designing the new dust collection system. In addition to the new filter systems, Martin also installed its Dust Fighter foam system to further improve fugitive dust col-lection. The foam system automatically mixes and applies a thin film of dust collection foam to the conveyed coal without increasing the coal’s moisture content. Each automated foam system consists of a single mixing station that prepares foam for up to eight nozzles installed on the coal conveying chutes.

There were many other upgrades and im-provements to the NOS coal-handling system

completed as part of the project. For example:

■ A water wash-down system was installed in the Tripper Room and Tripper Room tun-nel. A water deluge system was installed in the Transfer House, and the Shaker House basement. Both systems were installed in the Crusher House, Transfer House, and at the transfer and mag belts.

■ To decrease housekeeping and improve

safety, all combustible construction ma-terials were removed from the Tripper Room walls, Transfer House walls, and the Shaker House curbs. Walls were painted for easy maintenance in all the material-handling zones.

■ Five carbon monoxide monitors were installed in the coal bunkers, and an ad-ditional four monitors were added to the Shaker House. Data collected from these monitors is logged by the Pi data-logger located in the control room so that trends in CO concentrations can be closely watched and alarmed. When the concen-tration of CO reaches a predetermined level, an alarm sounds in the control room and an email is sent directly to operations supervisors.

■ Firefighting equipment was also procured and staged outside the Tripper Room, in-cluding a piercing rod kit and an F-500 cart with eductor and hoses.

■ Fugitive emissions from the coal pile were reduced by properly grooming the coal pile into a dome shape and by reducing steep pile slopes.

■ A belt slippage protection system was incorporated to the conveying systems to prevent large spills of coal and to prevent catastrophic belt failures.

The plant survey also carefully reviewed the electrical area classifications and all the changes and upgrades required to fully comply with Class II, Division 1, Group F classification were completed as part of the project.

The work of the Coal Handling group at the plant played an important role in receiving this award. The group stepped up and took on new responsibilities with respect to housekeep-ing. In the process they created a culture of excellence, both in operations and safety. The group’s safety record over the past years has been impressive, having recently completed 20 years without a lost-time injury.

Upgrading the skills and capabilities of the plant staff was also an important part of the program. For example, new evacuation plans were formulated in conjunction with the com-munity fire department and bunker firefighting training was completed. Onsite fire fighting drills with piercing rods in bunker fires and open area fires were conducted with commu-nity first responders to improve skills, com-munications, and teamwork. A plant safety video and a PRB combustible dust video were also produced to further hone the skills of the plant staff and contractors on the peculiarities of safely handling PRB coal as part of an on-going safety training program. ■

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

3. Comprehensive upgrades. North Omaha Station completed a multi-year upgrade of its coal-handling system in 2012, from the point fuel arrives at the plant through the coal bunkers on each boiler. Courtesy: OPPD

4. Efficient dust collection. The prob-lematic centralized dust collection systems were retired and replaced by individual insertable dust filter systems at the point of collection. The self-cleaning system returns the collected dust directly back into the enclosed conveying sys-tems. The top photo shows the original dust col-lection tap placed just above the conveyor. The new insertable dust collection system is shown on the bottom. Courtesy: OPPD

Tripper Room

Transfer House

Crusher House

Shaker House

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Inclusion in New Products does not imply endorsement by POWER magazine.

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Sequence of Events Recorder Cyber Sciences, supplier of specialty products for the monitoring and control of electrical distribution systems, offers the new CyTime Sequence of Events Recorder. Model SER-2408 is designed to help simplify testing of emergency power supply systems in power stations. With 24 high-speed digital inputs, eight control relay outputs, and data-log groups with simultaneous recording of inputs/outputs, the SER-2408 enables specialized reporting to support mandatory test compliance with standards for critical-power facilities. The SER-2408 is available with up to 32GB of memory for distributed storage of user drawings and documentation. (www.cyber-sciences.com)

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Commentary

Is Distributed Generation Really the Future?

If you read the environmental press, clean tech media, or even the New York Times, you might conclude that America is on the cusp of a distributed generation (DG) revolution. “So-

lar power and other distributed renewable energy technologies could lay waste to U.S. power utilities and burn the utility busi-ness model to the ground,” wrote leading environmental news site Grist last April. “Renewable-energy technologies like solar and wind power,” the Times wrote, are now “challenging the tra-ditional distribution system.”

The utility industry too is taking the threat seriously. The Edi-son Electric Institute (EEI) recently issued a report titled “Dis-ruptive Challenges,” assessing the threat renewables pose to the industry. Utilities and rooftop solar companies are facing off in Arizona and other states over rate subsidies for solar. Former Federal Energy Regulatory Commission Chairman Jon Wellinghoff recently told reporters that, “Solar is growing so fast it is going to overtake everything.”

Not So FastBut the reported death of the centralized electrical grid and the utilities that run it is greatly exaggerated. Solar panel prices have come down, but rooftop solar is still much more costly than centralized fossil generation, nuclear, or even utility scale wind and solar. Whether in Germany or California, solar deployment remains entirely dependent upon a raft of direct public subsidies and indirect rate subsidies.

Despite those subsidies, solar has yet to generate significant electricity anywhere. Germany, the world solar leader, after over a decade and $100 billion in direct public subsidies, gets only 5% of its electricity from solar. U.S. leader California generated less than 1% of its electricity from solar in 2012.

DG advocates have made much of the recent EEI report, but the report actually concludes that there will be no DG revolution. “In fact, electric utility valuations and access to capital today are as valuable as we have seen them in decades,” the authors say, “reflecting the relative safety of utilities in this uncertain economic environment.”

Disruptive PoliciesIf you want to know what utilities actually object to about DG, it is policies that functionally require them to purchase power from solar homeowners at $0.30/kWh when they don’t need it instead of buying it on the wholesale market for $0.04/kWh when they do. The result is not just less-profitable utilities but also higher rates for the vast majority of ratepayers. A recent California Public Utili-ties Commission study concluded that by 2020 the state’s net me-tering programs would increase rates by a billion dollars annually.

That’s not to say that the growth of renewable energy is not disruptive—just not in the way its advocates claim. Look at just about any place that has achieved significant deployment of re-

newable electricity, and what you find is that the vast majority comes from large, utility scale installations, not rooftop solar or any other behind-the-meter generation source. Even Germany gets over three-quarters of its renewable generation from large-scale wind, hydro, and biomass.

Given the current state of renewable technology and the scale of generation necessary to run a modern economy, these basic dynamics appear unlikely to change anytime soon. Take a peak at any of the dozens of scenarios produced by renewables advocates that claim we can run the U.S., Europe, or the world largely on renewables, and what you find is that most generation comes from massive industrial scale wind and solar developments from North Dakota to the North Sea—not DG.

In fact, a renewables-powered future will probably require more centralized generation, not less. Achieving significantly higher penetrations of renewable energy will require transmitting electricity over hundreds or thousands of miles from where large amounts can be generated to places where it will be consumed. Renewables champions may talk small-scale DG, but what they intend to build is every bit as centralized as the centralized power sources we have today.

Ultimately, what is disrupting the existing utility model is not the distributed nature of renewables, it is their intermittent nature, and the policies necessary to make them viable. Heavy public subsidization of the capital costs of wind and solar, com-bined with preferential purchase requirements for the power they generate, ensure that the marginal cost of wind and solar will always be lower than just about anything else when the wind is blowing and the sun is shining. Hence, Germany simultane-ously boasts the highest retail electricity prices in Europe and the lowest wholesale prices—not because the power costs less to generate but because most of the cost has been shifted else-where. In Germany, expensive, highly subsidized, intermittent renewables generation has driven wholesale prices so low that the utilities that must manage the grid and operate conventional power plants can no longer operate profitably. This, not cheap distributed solar, is what is disrupting the utility industry here and abroad.

Just because an electrical system that relies heavily on to-day’s wind and solar is likely to be costly and unreliable doesn’t mean we won’t build one. Our energy systems are a reflection of our culture, ideology, and politics, not just rational economic and engineering decisions. Germans, for instance, so fear nuclear energy that they prefer to pair expensive renewables with cheap coal. Perhaps the U.S. will do the same with wind, solar, and gas. If so, it will certainly be disruptive of our current electrical system. But one thing it probably won’t be is distributed. ■

—Ted Nordhaus is chairman, Michael Shellenberger is presi-dent, and Alex Trembath is policy analyst, Energy and Climate

Program at the Breakthrough Institute.

Ted Nordhaus Michael Shellenberger

Alex Trembath

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Putting Nature to WorkA utility client was looking for ways to reduce selenium

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Documents

Power Magazine, International January 2014