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October 2013 www.power-eng.com

SPECIAL REPORT A DISCUSSION ABOUT THE FUTURE OF NUCLEAR POWER

IVANPAH THE WORLDS LARGEST SOLAR PROJECT

REPOWERING UNDERSTANDING THE RISKS AND REWARDS

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Power Engineering

CORPORATE HEADQUARTERSPennWell Corp.

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Telephone: (918) 835-3161 Fax: (918) 831-9834 E-mail: [email protected]

World Wide Web: http://www.power-eng.com

MANAGING EDITOR Russell Ray

(918) 832-9368 [email protected]

ASSOCIATE EDITOR Justin Martino


ASSOCIATE EDITOR Sharryn Dotson


ON-LINE EDITOR Jennifer Van Burkleo


CONTRIBUTING EDITORBrad Buecker

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POWER ENGINEERING, ISSN 0032-5961, USPS 440-980, is published

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Newsletter:Stay current on industry news, events, features and more.

Newscast:A concise, weekly update of all the top power generation news

Industry News:Global updates throughout the day

DEPARTMENTS

2 Opinion 4 Clearing the Air 6 Industry Watch 8 Nuclear Reactions 10 Energy Matters

FEATURES No. 10, October 2013

26 SPECIAL REPORT Nuclear Executive Roundtable

117VOLUME

38 Converting Once-Through Cooling to Closed-Loop

60 Executing the Complete Power Generation Project

68 Lessons Learned: Ivanpah Solar Facility

78 Developing a Low-Cost MATS Rule Compliance Strategy

100 Protecting Wind Turbines in Extreme Temperatures

108 How Regulations will Drive Innovations in Water Management Systems

116 Plant Performance Improvements by Enhanced Combustion Optimization

126 EPC Agreements for Re-Powering Projects

140 Synopsis and Impact of the Industrial Boiler MACT

152 Preparing the Grid for Renewable Resources

160 A Conversation on Alliance Contracts with Day & Zimmerman and TVA

168 Improving Performance with Biogas-to-Energy Project

174 Evaluating Bids for Air Quality Control Systems

184 Grand Coulee Dams Third Power Plant Undergoes Refurbishment

12 View on Renewables 16 Gas Generation 18 Demand Response 20 Power Plant Profile:

Stanton Energy Center

188 Generator Spotlight: NV Energy

196 What Works 211 Ad Index

1310pe_1 1 10/16/13 5:28 PM

www.power-eng.com2

OPINION

well below the average CO2 emission rate

for coal plants 1,700 pounds per MWh.

The standard for gas plants remained at

1,000 pounds per MWh.

The revised rule is a halfhearted at-

tempt at pragmatism. During her con-

firmation, EPA Administrator Gina

McCarthy was hailed as a great prag-

matist who could reach a good-faith

compromise with the power sector.

The revised rule is a clear sign this as-

sumption was wrong. The new rule sig-

nifies her commitment to a calculated

strategy to advance the Obama admin-

istrations anti-coal agenda.

THE BEST TECHNOLOGY?

Under the Clean Air Act, any CO2

standard for new plants must be based

on the best system of emission reduc-

tion that has been adequately dem-

onstrated. This is where the battle will

be fought.

EPA based the CO2 limit for coal plants

1,100 pounds per MWh on Carbon

Capture and Storage (CCS) technology.

Astonishingly, EPA found that CCS tech-

nology has been adequately demonstrat-

ed and is available. The logic is confound-

ing. The problem is the technology has

never been used or demonstrated on a

commercial-scale power plant in the U.S.

EPA pointed to a handful of CCS proj-

ects that are still under development,

including a 582-MW coal gasification

plant in Kemper County, Miss. The plant,

which is designed to capture 65 percent

If you dont think the War on Coal is

real, the revised greenhouse gas rule

for new power plants should leave

no doubt that U.S. regulators are fully

engaged in a campaign against the most

important segment of the power genera-

tion industry.

The industry was hoping for a bal-

anced, common-sense approach that

would lower CO2 emissions without tak-

ing coal out of the mix. Instead, the En-

vironmental Protection Agency issued an

impractical proposal based on conjecture

about a technology that is not used any-

where in the U.S.

It is yet another example of the EPA

drafting a rule without the data or evi-

dence to support it.

The industry was hoping for a pro-

posal that would keep coal in the mix

by allowing utilities to build innovative

coal plants such as the ultra-supercritical

coal-fired John W. Turk Plant, the most

efficient coal-fired power plant ever built,

and the Virginia City Hybrid Energy Cen-

ter, one of the cleanest coal-fired plants in

the country. These kinds of projects, how-

ever, could not be built under the revised

GHG rule because they would not be able

to meet the rules draconian limits for

CO2 emissions.

The revised New Source Performance

Standard for CO2 is essentially no differ-

ent than the original proposal, which es-

tablished one CO2 limit 1,000 pounds

per megawatt-hour for all new power

plants. The re-proposed rule corrected

this fundamental legal flaw in the origi-

nal proposal by establishing separate

standards for coal- and gas-fired plants.

But the re-proposed rule failed to provide

a meaningful difference in the standard

for new coal plants. The new standard

is 1,100 pounds per MWh, only slightly

higher than the first proposal and still

of its carbon output, should begin gener-

ating power next year.

The question is this: Can the EPA im-

pose a technology based on projects still

under development or in planning, or

should CCS be demonstrated on a work-

ing power plant? This question will no

doubt be answered by the courts.

Forces within the federal govern-

ment dont agree about the availabil-

ity of CCS technology. While the EPA

claims CCS technology is ready and

available, officials within the Depart-

ment of Energy will tell you, privately,

the technology is not yet feasible for

commercial applications.

EPA also concludes that strict emission

limits on CO2 would foster the develop-

ment of CCS research and technology.

The truth is no one will build another

coal-fired plant in the U.S. because the

standard for coal is unachievable with

current technology. With no incentive

to build, there will be no incentive to ad-

vance CCS technology.

By stopping the development of

new coal plants, the EPA is halting

the development of carbon capture

and storage technologies, said Robert

Duncan, CEO of the American Coali-

tion for Clean Coal Electricity.

The industry has not abandoned coal.

Without the Obama administrations

draconian rules for power generators, the

industry would be pursuing clean coal

projects to mitigate the risk associated

with the unruly price of natural gas.

It is a misguided rule that eliminates

coal as an option and endangers the re-

liability and affordability of Americas

power supplies.

If you have a question or a com-

ment, please contact me at russellr@

pennwell.com. Follow me on Twitter

@RussellRay1.

A Disappointing and Dangerous RulemakingBY RUSSELL RAY, MANAGING EDITOR

T

1310pe_2 2 10/16/13 5:28 PM

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CLEARING THE AIR

cesium, hafnium, and scandium.

These elements have RE factors of

>1 and are typically enriched in

bottom ash.

Category II includes elements that

volatilize during combustion, such

as arsenic, nickel and lead. These el-

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INDUSTRY WATCH

that FERC is considering taking short-

term steps to address what it views as

a pressing reliability concern.

Soon after issuing the data re-

quests, FERC issued an order direct-

ing ISO-NE to revise its tariff to afford

generators that are dispatched to ad-

dress reliability needs with additional

opportunities to recover their fuel

costs.

FERC directed these changes after a

generator was unable to recover a ma-

jority of the additional fuel costs that

it incurred when ISO-NE directed it

to run beyond its day-ahead schedule

after a snowfall resulted in the genera-

tor being the only resource capable of

providing needed reliability services.

Because the generator only learned

that it would be required to run be-

yond its day-ahead schedule after the

deadline for nominating natural gas

deliveries had passed and after it al-

ready had submitted an offer into the

day-ahead market, the generator was

required to purchase the fuel neces-

sary to comply with ISO-NEs in-

struction at high spot market prices,

but was unable to recover approxi-

mately $2 million of these costs. Even

though ISO-NE objected, suggest-

ing that FERC should allow existing

stakeholder discussions concerning

long-term solutions to address these

issues to run their course, FERC di-

rected ISO-NE to implement market

rule changes by winter 2013-2014

that would allow generators that are

dispatched beyond their day-ahead

schedules to make a FERC filing to

recover such costs.

The Federal Energy Regula-

tory Commission has set

its sights on the coordina-

tion between natural gas and electric

markets as a priority agenda topic in

recent years. In its most recent salvo,

FERC on June 4 posed data requests

to each of the countrys Independent

System Operators and Regional Trans-

mission Organizations to explore im-

provements to the coordination of the

natural gas and electric markets.

In recent years, the increasing reli-

ance of electric generators on natural

gas as their fuel of choice has high-

lighted the importance of the avail-

ability of natural gas in ensuring

electric reliability and meeting the

nations energy needs. FERC, in par-

ticular, became increasingly focused

on the issue after a cold snap in the

southwest in February 2011 resulted

in rolling blackouts at the same time

that a decline in natural gas produc-

tion resulted in curtailments of natu-

ral gas supplies. A joint FERC and

North American Electric Reliabil-

ity Corporation task force report con-

cluded that while the primary cause

of the blackouts and the decline in

production was the extreme weather

conditions, inadequate fuel supplies

did play a role in generator outages.

In light of these issues, in February

2012, FERC instituted a general pro-

ceeding in Docket No. AD12-12-000

to explore and seek comment on the

need for greater gas-electric coordina-

tion. At the urging of commenters,

FERC commenced a series of techni-

cal conferences to explore whether

greater harmonization of the gas

and electric industries is needed,

and, on May 16, held a special meet-

ing at which representatives from

the various ISOs and RTOs detailed

their experiences and described the

progress each region has made in

promoting coordination between

these industries. The data requests

asked each region by July 5 to pro-

vide a response detailing:

Steps that can be taken in the

short-term to enhance gas-elec-

tric coordination;

Whether the region is consid-

ering changes to align its day-

ahead scheduling practices with

the markets for natural gas simi-

lar to ISO-NEs recent decision

to change the deadlines for the

participation and commitment

of resources in its day-ahead

electric market to reflect trading

patterns in natural gas markets;

Whether the region has any spe-

cific concerns regarding the com-

ing winter;

Whether shifting the start of the

gas operating day ahead of the

increased demand for electricity

in the morning could improve

coordination in the region;

If gas system contingencies are

taken into account in system

planning; and

What steps the region is taking

to improve its awareness of local

conditions.

FERCs issuance of the data requests

is one of a number of recent signals

FERCs Latest Market Convergence Agenda: Gas and Electric CoordinationBY SANDRA E. RIZZO AND STEPHEN J. HUG, BRACEWELL & GIULIANI LLP

Authors

Sandra E. Rizzo is the

head of Bracewell &

Giuliani LLPs Energy

Regulatory Group. Ste-

phen J. Hug represents

clients in matters relat-

ed to federal regulatory

policies, regulations

and rules applicable to

the power generation

industry.

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NUCLEAR REACTIONS

electricity prices, nuclear plant own-

ers have relied on these studies to cut

costs by reducing staff. While efficiency

and worker productivity are appropri-

ate goals, time in the plant reveals daily

breakdowns in the model when critical

staff are sick, on vacation, or re-distribut-

ed to special teams.

Communications from INPO and

the NRC about future reductions in low

value-added programs and processes are

welcome signs. These efforts may sig-

nificantly improve the efficiency of the

plants operation. Or a significant para-

digm shift may be necessary.

Perhaps the industry desperately needs

truly new thinking that finally strips

away excess work so people can focus

on running the plant and supervising

people. Perhaps the industry needs an ap-

proach that builds on and leverages safety

culture but avoids babysitting processes

and overblown data collection. To do so,

you need a leadership team and a culture

to lead and guide the organization. Such

a leadership team would be truly cross-

functional, high performing and market

savvy. They would be intentional about

fine-tuning safety culture. The plants ap-

proach to cost management must then

reflect a new balance between unit gen-

eration and rationalizing the asset. Such

a business-minded nuclear organization

would also need a scorecard that reflects

real economic and market pressure and

success. In all, this approach would

achieve business results for the plant.

Such an approach may be too radi-

cal, not radical enough, or the timing

may be off. Or it just may be that nu-

clear power plants need this approach

to remain relevant.

Nuclear power in the U.S. is

facing unprecedented eco-

nomic challenges at the same

time regulatory burdens on the indus-

try continue to increase, as highlighted

by looming Fukushima modifications.

Early hopes that relief would eventually

come from rising gas prices have faded.

Environmental regulations (real and pro-

posed) have only managed to dampen

the coal power business with no percepti-

ble detriment to natural gas. Meanwhile,

natural gas reserves appear endless while

fracking and horizontal drilling continue

unabated. In short, prices for electricity

and natural gas have remained low.

Despite an occasional nod from the

President and his administration on the

importance of nuclear power leadership

in the U.S. and internationally, relief

from the current conditions which

have led to the shuttering of four reactors

so far this year has not been forthcom-

ing. Merchant nuclear power plant own-

ers with the tightest margins have been

forced to plan for more shutdowns and

regulated utilities continue to squeeze

their operations.

This challenging environment has led

to calls for the industry to re-invent itself

and make innovative changes to become

more competitive and resilient. Some

people have pointed to the successes of

the post-deregulation period where the

industry as a whole made large gains in

reliability and safety. The Institute for

Nuclear Power Operations (INPO) and

the industry should be proud of such im-

provements, which were made through

relentless attention to operational fo-

cus and nuclear safety culture. Unlike

now, however, the turn of the century

operators had much more cash and much

less sustained pressure from electricity

prices. The need for a new approach is

even more urgent.

What industry leaders have begun to

recognize is that these unit reliability and

system performance gains have come

with a great deal of baggage, in terms

of a multitude of large and small pro-

grams and processes. INPO has openly

acknowledged that some of the addi-

tional burden that has accumulated over

the years may be low value-added, and

groups have been formed to see if there

are changes that can be made, starting

with corrective action, work control, and

human performance programs. The NRC

has stated that it is looking at the cumu-

lative impact of regulation to determine

if there is anything that can be done to

moderate such a trend.

From the perspective of plant workers

and supervisors, it is a struggle to feed

the information-hungry programs and

processes. For years, nuclear first-line

supervisors have complained of admin-

istrative burden preventing them from

spending more time in the field with

their people and the work. Although

these types of complaints have gotten

louder, the companys typical response

is that time spent on the computer and

dealing with documentation is part of the

job, because extensive corrective action

and work control processes are the way

the plants must be run. Supervisors just

need to be more efficient and demanding

of workers.

At the same time, staffing levels have

been steadily reduced based on bench-

marking studies of other departments

in other plants. With sustained low

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ENERGY MATTERS

C

simple-cycle should be considered since

combined-cycle often has a lower rate of

CO2 on a megawatt hour basis. However,

in the case of the Pio Pico Energy Center

in Otay Mesa, CA, the EAB ruled that

EPA does not need to consider lower-

emitting combined-cycle plants in deter-

mining the best available control tech-

nology for greenhouse gases. The EAB

held that because the BACT analysis is

a site-specifc determination that must

be appropriate for the particular facil-

ity, such technology can be scratched

from consideration. The EAB went on

to say that the Sierra Club and other pe-

titioners have not demonstrated that

the region clearly erred in eliminating

combined-cycle gas turbines in step

2 of its BACT analysis for greenhouse

gases, or that the issue otherwise war-

rants review or remand. In view of the

role the Pio Pico facility would serve,

combined-cycle gas turbines had been

eliminated as a potential candidate for

BACT by the EAB and deemed techni-

cally infeasible. The EAB noted that un-

like simple-cycle turbines, which can be

dispatched from cold iron to 300 MW

in less than 30 minutes, combined cy-

cles, even those with fast-start technol-

ogy, take signifcantly longer to start-up.

This precedent setting ruling should be

referenced in future simple-cycle permit

applications.

The reality is that absent Congres-

sional action, we have to live with the

Clean Air Act as written, warts and all.

It may be illogical to some, confusing

and outdated to others, but by keeping

apprised of new court interpretations,

we can make it work for us as much as

possible.

While reading about legal

cases is certainly not very

interesting to non-lawyers,

it is one of the few ways utilities are giv-

en insight as to what the Clean Air Act

(CAA) actually means (or at least how

the laws are being applied and interpret-

ed by the courts). To this end, it would

be useful to understand three recent

decisions that affect the mechanics and

economics of power generation.

First, does a utility need to worry

about CAA enforcement as well as nui-

sance lawsuits? In Bell v. Cheswick Gen-

erating Station, 1,500 property owners

fled a class action lawsuit against Ge-

nOn complaining that fy ash from a

570-MW coal-fred power plant settled

on and damaged their property. Briefy,

while such citizen suits are expressly

allowed under the Clean Air Act, state

tort law also might apply. The trial court

agreed with GenOn that state claims

were preempted by the CAA, but the

Appeals court disagreed and reversed

that decision, holding that if Congress

intended to preempt state tort claims,

it would have said so in the CAA. The

short of the matter is that not only do

utilities need to comply with their CAA

permits, they are subject to enforcement

by both CAA citizen suits and also nui-

sance claims under state law. The appel-

late court sent the case back for a trial,

which leaves the utility vulnerable to

uncertainty.

Second, one of the largest monetary

risks in operating a coal-fred utility is

retroactive New Source Review (NSR)

enforcement. Twenty years ago, when

you replaced some boiler tubes and an

economizer, should you have gotten a

construction permit? In the last 13 years,

EPAs coal-fred power plant enforcement

initiative has resulted in 27 settlements

covering 91 plants and 262 boilers, with

an average total settlement cost per boil-

er (including controls) of $72,800,000.

These settlements have some root in the

CAA legal maximum penalty of $32,500

per violation per day. A series of recent

court cases (in both the 8th and 11th Cir-

cuits) has established that not obtaining

a construction permit is not a continu-

ing violation. As held in a July 2013 Fed-

eral case, Todays emissions cannot be

called unlawful just because of acts that

occurred more than fve years before the

suit began. In other words, the fve-year

statute of limitations under the CAA

begins to run when the facility opera-

tor fails to obtain a construction permit

under the CAA, and each day the plant

operates without the permit does not

constitute a fresh violation of the Act.

As the Court stated, Once the statute

of limitations expired,[the plant owner]

was entitled to proceed as if it possessed

all required construction permits. This

should be good news for utilities trying

to manage risk and fnancial exposure.

Finally, and in another bit of good

news, EPAs Environmental Appeals

Board has issued a ruling relevant to any-

one trying to build a new simple-cycle

plant. The decision on whether to build

a simple-cycle or combined-cycle plant

is based on economics and dispatch pre-

dictions; it should not be held hostage to

only environmental concerns. The Sierra

Club argued that when evaluating Best

Available Control Technology (BACT)

for simple-cycle turbines, building a

combined-cycle confguration instead of

Recent Developments in Regulation Through LitigationBY ROBYNN ANDRACSEK, P.E., BURNS & MCDONNELL

1310pe_10 10 10/16/13 5:28 PM

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VIEW ON RENEWABLES

addition, the buildings, turbines, gen-

erators, feedwater and cooling systems

are being reused.

In the communities where the sta-

tions are located, the switch to bio-

mass will help preserve or restore jobs

and ensure a continued stream of lo-

cal property tax revenue. An ancillary

benefit will be the many jobs created

to supply the waste wood from lo-

cal timbering operations that will be

needed to fuel the stations.

Dominion had experience with bio-

mass when it made the decision to

convert the three stations. The compa-

nys 83-MW Pittsylvania Power Station

in Pittsylvania County, Va., just across

the Roanoke River from the Altavista

station, is one of the largest wood-

waste stations in the nation. Also, our

new Virginia City Hybrid Energy Cen-

ter in Wise County, Va. is designed to

co-fire with coal and biomass.

Dominion Virginia Power needs the

electricity that the converted power

stations will produce. Based on the

projections from PJM, our regional

transmission operator, the need for

electric generation in Virginia is ex-

pected to grow by thousands of mega-

watts during the next decade. PJM has

identified a gap of 4,000 MW by 2023

that our company is working to close.

The converted stations will provide

much needed baseload electricity.

So when it comes to biomass, natu-

ral gas or any other form of power gen-

eration, we believe that our approach

is the right one balanced fuel diver-

sity that leads to reasonable rates and

economic development.

Dominion Virginia Power has

long recognized the virtues

of fuel diversity in power

generation and, in recent years, has

turned to biomass as well as other re-

newables to achieve a desired balance

of generation sources. Fuel diversity

not placing all bets on any single gen-

eration source leads to reasonable

rates that best serve the needs and in-

terests of customers and shareholders.

In mid-summer, we completed the

conversion of our Altavista Power Sta-

tion in Altavista, Va. from coal to bio-

mass and placed the station into com-

mercial operation. Altavista is the first

of three former coal-fired stations of

similar size and design that will begin

operating on biomass before the end of

2013. The other two are the Hopewell

Power Station in Hopewell, Va. and the

Southampton Power Station in South-

ampton County, Va.

These coal-to-biomass conversions

will benefit our customers, the envi-

ronment and the Commonwealth of

Virginia. They will provide low-cost

baseload energy, promote Virginias re-

newable goals, provide economic ben-

efits and, of course, improve our fuel

diversity.

When the decision was made to

convert the stations two years ago, the

reasons for moving forward with the

conversions were many:

Existing generation facilities that

were little used could be modi-

fied to enhance their value to our

customers, creating significant

customer savings over their antici-

pated 25-year lifetimes.

Although the net output of each of

the three stations would fall from

63 MW on coal to 51 MW on bio-

mass, the three are expected to run

92 percent of the time as baseload

units after conversion, compared to

an estimated 18 percent if they were

to continue on coal. The three units

had been peakers, supplying elec-

tricity mostly during times of peak

demand such as hot and cold days.

Benefits to the environment would

include reductions in nitrogen ox-

ides, sulfur dioxide, particulate mat-

ter and mercury.

Customers would gain the benefit

of production tax credits available

to renewable projects as well as

the benefit of renewable energy

certificates flowing from biomass

generation.

The three stations had become less

economical to operate on coal over

the last decade, running at a combined

capacity factor of only 26 percent in

2009-2010. Altavista was not running

at all after 2010 as it was placed in cold

reserve that year.

The cost of converting the three

coal stations $166 million is a

fraction of the cost of building a new

150-MW biomass station from scratch.

Although major modifications are be-

ing made to fuel handling equipment,

boilers and bag houses, much of the

equipment in the coal stations is be-

ing reused. For example, the coal units

already had the majority of the emis-

sions controls necessary to manage

NOx, SO2 and particulate matter. In

Dominion Turns To Biomass To Grow Fuel DiversityBY PAUL RUPPERT, SENIOR VICE PRESIDENT, BUSINESS DEVELOPMENT AND GENERATION CONSTRUCTION, DOMINION

1310pe_12 12 10/16/13 5:28 PM

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www.power-eng.com14

VIEW ON RENEWABLES

under the radar. Georgia Power has an-

nounced a 525 MW program, up from

almost nothing two years ago, though its

structure is still under discussion. Third-

party ownership in this regulated state

remains a hot-button issue. Florida has a

large solar resource but opportunities for

solar energy remain limited, with many

market barriers to third-party owned so-

lar and a lack of supportive policies.

Texas, a longtime leader in wind en-

ergy, is starting to awaken to its solar

energy potential, given its vast land and

solar resources and high electricity load

and rates. What its lacking now is policy

support as was put toward wind energy.

In the West, California remains a lead-

er in solar energy, and just passed several

pieces of legislation addressing rate de-

sign, net metering, and RPS targets. After

seeing significant growth during the past

couple of years, Arizona is a big question

mark with uncertainty around net meter-

ing and its RPS. Clarification and resolu-

tion is hoped for in coming months, giv-

ing this market more certainty going into

2014. Nevada recently passed legislation

that could create more opportunities for

large-scale and distributed generation so-

lar. NV Energy has committed to replace

553 MW worth of coal plants with a mix

of renewable energy and natural gas, and

its pending acquisition by MidAmerican

offers further optimism for more renew-

able energy development..

The aforementioned top-12 states,

and the issues theyre wrestling with,

will help shape the future of solar

energy in the U.S. Learning from

their successes, and their challenges,

will ensure the industrys continued

growth along the path toward a future

of sustainable domestic energy.

A recent report from the Environ-

ment America Research & Policy

Center identified the top U.S.

states for solar energy, ranked by criteria

ranging from new and cumulative in-

stalled capacity to electrical generation to

solar-friendly policies.

The top states in order of ranking are:

Arizona, Nevada, Hawaii, New Jersey,

New Mexico, California, Delaware, Col-

orado, Vermont, Massachusetts, North

Carolina, and Maryland. They share

some important characteristics, includ-

ing renewable electricity standards with

carve-outs for solar, strong statewide in-

terconnection and net metering policies,

and accommodations for creative financ-

ing options such as third-party owner-

ship and property assessed clean energy

(PACE) financing.

Many of these states also share some

challenges, which are described in the So-

lar Energy Industries Associations (SEIA)

second-quarter report:

- Net metering. Utilities and grid

operators continue to struggle to under-

stand and embrace increasing amounts

of behind the meter power generation,

fairly valuing distributed generation and

ensuring grid reliability. Earlier this year,

a report found that solar net metering in

Vermont is a net-positive for the state, fol-

lowing similar conclusions in California,

New York, and Texas. Californias just-

passed AB 327 includes some amend-

ments to address concerns about net me-

tering caps. Net metering also is a central

issue in Arizona, causing uncertainty in a

state thats seen soaring solar growth the

past few years. In Colorado, a proposal

filed this summer by Xcel evaluating dis-

tributed generation has raised some eye-

brows, notes Carrie Hitt, SEIAs senior

VP for state affairs. Other states, includ-

ing Louisiana and Texas, are exploring

the issue, and will likely take some cues

from the aforementioned states.

- Market growth for non-residential

solar. While residential solar PV and

third-party ownership have taken off,

growth in commercial solar has lagged,

shrinking 11 percent in the first half of

this year compared with the same period

a year ago, according to SEIA. The group

suggests New York and California will

need to take the lead on growth in this

sector in the coming months.

Meanwhile, utility-scale solar, large-

ly centered in California and Arizona,

has seen a slowdown in utility pro-

curements, SEIA said. Current PPAs

were driven largely by state RPS re-

quirements, which are already in sight,

Future PPAs need to emphasize cost-

competitiveness, and well see to what

extent utilities will step up to embrace

centralized utility-scale solar.

Looking ahead, what does the state-

wide landscape look like for solar energy?

SEIAs Hitt offers some highlights:

In the East, Massachusetts has hiked

its solar goals (1600 MW by 2020) and

currently is figuring out the framework

structure to support that growth. New

York had exhausted most of the funds for

its current program, though longer-term

the state shows promise.

In the Midwest, Ohio is still a market

of opportunity for solar energy, despite

recent efforts to revisit the states RPS.

Michigan remains well under the radar

for solar energy, in part because of Detroit

Energys plans to reduce solar incentives.

Smaller markets such as Minnesota and

Missouri show growth promise.

The Southeast U.S. region still is largely

Whats Driving States to Adopt Solar Energy?BY JAMES MONTGOMERY, ASSOCIATE EDITOR, RENEWABLEENERGYWORLD.COM

1310pe_14 14 10/16/13 5:28 PM


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www.power-eng.com16

GAS GENERATION

in capital spares or keep the existing in-

surance policies in place and repair or

replace equipment when the events hap-

pened. In order to do that, we needed to

calculate reliability rates to fulfll our in-

formation requirements.

The Electric Power Research Institute

(EPRI) is working with its members to

use experience and best practices from

coal and nuclear power plants to devel-

op a comprehensive maintenance basis

for critical systems and components in

combined-cycle plants. A comprehen-

sive maintenance basis provides a ratio-

nale to determine critical components

and identify the most effective tasks to

address reliability and operational chal-

lenges. It also helps ensure overhauls are

scheduled and that unanticipated break-

downs do not occur, making generation

assets more reliable and cost-effective.

The EPRI project is identifying the

components important to long-term

generation reliability; determining what

types of failure modes exist; and detail-

ing the most effective tasks with a focus

on condition-based maintenance (CBM).

The results can be used to assemble a

plant maintenance basis that refects the

actual operational mission for the station

instead of a more generic maintenance

strategy that could lead to excessive over-

hauls of equipment with limited wear.

When we started asking ourselves

what we can do to start putting the right

preventive maintenance frequencies in

place we recognized that theres al-

ready been a signifcant amount of work

done by EPRI for both the nuclear and

fossil assets, Morrison said. To a large

extent, our combined-cycle feet is very

similar to a nuclear or a fossil plant, with

Current gas prices and expand-

ing emissions regulations on

coal-fred plants are resulting in

increased capacity factors at combustion

turbine combined-cycle (CTCC) plants

in some cases, from as little as 10 percent

to more than 60 percent. The increasing

reliance on these assets to provide basel-

oad generation drives the need for com-

prehensive new operations and mainte-

nance strategies.

We realized that our gas plants were

starting to run considerably more than

our annual projections due to lower gas

prices and other factors throughout our

service territory, said Bill Morrison, Vice

President of Generation Engineering for

the Tennessee Valley Authority (TVA).

And we recognized that the plants were

not designed to run the way that they

were being run. Most of our plants were

built to be peaking, and we were starting

to run them more and more as a baseload

facility, and we knew the maintenance

and predictive maintenance programs

were not in place that would give us the

abilities to support that level of sustained

operational reliability.

Paulo Jorge Domingues dos San-

tos, Subdirector Servicios Tecnicos for

Endesa Generacion, S.A. had similar

maintenance program needs, but for a

different reason. We didnt have much

reliability information organized in the

way that EPRIs Preventive Maintenance

(PM) Basis is organized to support our

reliability-centered maintenance and

reliability-centered spares programs,

Domingues dos Santos noted. My team

was performing an analysis for our insur-

ance policies. We needed to calculate if it

would be worth it to invest more money

the exception of the prime moverits a

jet engine instead of a boiler or a reactor.

To us, it only made sense to use EPRI as

a starting point for going after the addi-

tional gaps that existed within its Pre-

ventive Maintenance (PM) Basis that had

already been developed in other areas.

Our approach is to utilize the existing

maintenance bases to put the right PM

programs in place.

We expect to have a comprehensive

maintenance basis we can use in our

work controls process to prioritize ac-

tions, so we can start making sure we

have the right PM tasks set up to ensure

that we maintain our high level of reli-

ability as we continue to run facilities

harder and harder, Morrison said. For-

tunately, the assets are running well now,

but thats because theyre new, and typi-

cally around the 8- to 10-year time frame

is when you start to see signifcant reduc-

tions in the level of performance. The

time is right to do this now; otherwise

youll be digging out of a hole for years

to come.

We have information about steam

turbines, generators, transformers,

pumps, etc. from EPRIs PM Basis,

Domingues dos Santos said. But the

majority of our gas turbines are rela-

tively new. The oldest ones are only 10

to 11 years old, so we didnt have a large

operational history to use in building a

reliability table for the majority of our

combustion turbines. I can tell you that,

because of implementing the proper set

of maintenance processes on our coal

side of the house, weve seen in the $10

to $20 millions worth of value annually,

and I would expect our gas feet will see

the same type of benefts.

Maintaining natural-gas fred baseload plantsBY JEFF BREHM, COMMUNICATIONS MANAGER, ELECTRIC POWER RESEARCH INSTITUTE

1310pe_16 16 10/16/13 5:28 PM

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www.power-eng.com18

DEMAND RESPONSE

in response to power requirements po-

tentially eliminating or stalling the need

for additional generating requirements

and providing more predictable energy

market purchases.

The widespread implementation of

demand response systems could signifi-

cantly reduce usage by educating users on

their current consumption patterns.

In 2011, the U.S. Green Building

Council granted LEED (Leadership in

Energy and Environmental Design) rat-

ing credits to companies that implement

DR programs into their buildings. LEED

certified buildings have official verifica-

tion of energy efficiency and therefore

often provide healthier environments for

residents or tenants. As concerns about

environmental sustainability continue to

take root among Americans, so does the

appeal and ultimately, necessity for LEED

accreditation.

DR programs can sense imminent

demand load problems and reduce

electricity usage in high-consumption

places, removing the chance of over-

load and resulting power failures.

According to the U.S. Green Build-

ing Council, commercial and indus-

trial buildings with a peak demand load

greater than 200 kW (kilowatt) have a

significant impact on energy demand

and electricity grid stability in general, es-

pecially in urban and business areas with

many commercial buildings or industrial

operations.

As the worlds population continues to

grow, so does the need for energy. With

Energy Awareness Month upon us, there

is no time like the present for utilities and

consumers to take control of their elec-

tricity usage.

Energy Awareness Month in Octo-

ber is a national effort to promote

smart energy choices that literal-

ly puts power in the hands of consumers.

Yes, simple actions such as turning off

the lights or adjusting the thermostat can

significantly lower energy bills and en-

vironmental strain, but what if consum-

ers had more information about their

energy usage would they make more

intelligent decisions?

There are many vehicles used by utili-

ties to promote energy awareness and

conservation to their customers. Fly-

ers stuffed into mailed monthly bills,

energy audit opportunities and top ten

conservation tips on utility websites are

common.

As technology has evolved, so have

the approaches that utilities can use to

encourage, or in some cases, enable con-

servation through Demand Response

(DR) systems.

Demand Response systems for electric

grids promote sustainable energy usage

among both utility companies and their

customers, while also allowing utilities

to control energy demand. DR technolo-

gies also help utility personnel commu-

nicate directly to customers. Through DR

systems for electric grids, customers can

use smart thermostats, consumer portals

on their home computer or mobile ap-

plication, and in-home display devices

to monitor and better understand their

electricity usage. All of this has been

made possible through the deployment

of AMI that provides real-time usage data

at a finer granularity than ever possible.

Demand Response systems send us-

age information to both utilities and

their customers via Home Area Network

(HAN) devices such as smart thermo-

stats and in-home display devices com-

municating directly to the electric meters

via ZigBee or through the internet over

home computer and mobile applica-

tions fed from the head end of the AMI

system. This allows consumers to person-

ally monitor their energy usage via online

portals and better understand how much

electricity they are regularly consuming.

Consider how much energy an individ-

ual uses on a daily basis. Everyday tasks

such as keeping a home at a cool tempera-

ture and lighting several rooms at a time

may seem harmless in the moment, but

over time, the costs add up. By opting to

remain unaware of energy usage habits

and exact consumption data, consumers

are wasting money and resources. With

DR technology, utility customers can

make more intelligent energy decisions,

as well as receive greater control over their

electricity purchases.

Once consumers start reducing the

amount of electricity they use, power

companies will be able to reallocate

the electricity they produce, and be

able to factor the effectiveness of their

DR programs into their decision mak-

ing process for developing new genera-

tion, using renewable, or offering even

more DR programs.

DR programs are also a powerful tool

when blackouts occur during times of

peak demand, particularly during ex-

treme weather conditions. Without DR

systems in place, utility companies are of-

ten faced with operating power plants at

full capacity when demand for electricity

spikes, and paying more for peak energy

on the spot market. DR technology allows

electricity users to reduce consumption

Raising Energy Awareness through Demand Response TechnologyBY GREG MYERS, VICE PRESIDENT, SENSUS

1310pe_18 18 10/16/13 5:29 PM



1310pe_19 19 10/16/13 5:29 PM

www.power-eng.com20

POWER PLANT PROFILE

Duke Energy partnered with Regenesis

in the construction. After construction,

Duke purchased the project, which is

currently operated under a two-year op-

eration and maintenance contract with

Regenesis that expires in December.

Building the solar project came with

some challenges, according to Michael

Butler, Duke Energy Renewables Solar

Manager East. Florida does not provide

incentives for solar power plants, so mak-

ing the economics work is diffcult. In ad-

dition, the site was a wetlands area identi-

fed as a water retention area, meaning it

needs to hold water than letting it run off.

Florida weather and the potential of

hurricanes also played a factor into the

design of the solar facility. The system

has a weather-stow feature that puts the

panels into stow position if it detects sus-

tained winds of 40 mph or greater for 10

seconds.

Despite the diffculties, though, Butler

said the project has multiple advantages.

There is a reuse of land that was once

landfll area, so really land that could

not be developed into anything else,

he said. Using it for a solar ft was a re-

ally good ft.

While many utilities talk

about maintaining feet

diversity, not many power

plants are as diverse as the Orlando Utili-

ties Commissions Stanton Energy Cen-

ter. The facility uses a range of fuel sourc-

es and includes a 5.91-MW solar farm.

The Stanton Energy Center has two

460-MW coal-fred units, a 300 MW nat-

ural gas-fred combined cycle unit, a 633-

MW combined-cycle unit and a 5.91-MW

solar array. In addition, the coal-fred

units can burn natural gas and landfll

gas. The units are also equpped to burn

two different types of coal.

It really makes your operators have to

be on their A game all the time to make

sure the combustion processes are opti-

mized, OUC Director of Power Produc-

tion Wade Gillingham said. If theyre

not, you can have some serious boiler op-

eration and maintenance problems, and

so far weve been successful.

The two coal-fred burners are oper-

ated by OUC, which also owns 70 per-

cent of the units. The units burn a blend

of Illinois Basin and Central Appalachian

(CAPP) coal and have secondary aug-

mentation igniters that use natural gas.

Thats usually to start the coal fame,

but we also use it to supplement coal if its

more economical, Gillingham said. If

we have pricing signals that gas is cheaper

than coal, we burn as much of the gas as

we can.

The units also burn landfll gas from

a facility owned by OUC. The utility has

been burning landfll gas since 1998.

Although the initial landfll gas process-

ing facility and the wells it used have ex-

hausted itself, Gillingham said OUC has

owndership of another process faiclity in

the same landfll.

OUC also owns 100 percent of the

300-MW combined cycle unit on site

and 28 percent of the 633-MW combined

cycle unit. Southern Power operates the

larger unit and is majority owner with 65

percent ownership.

Gillingham said the site was originally

designed to have four coal-fred units.

After building two, the utility decided

to diversify its portfolio with combined

cycle technology and entered a partner-

ship with Southern Company for the

larger combined cycle unit. After that was

built, OUC began working with South-

ern Company on a coal gasifcation unit,

but the project was upscaled and moved

to the Kemper County energy facility.

OUC then built the 300-MW combined

cycle unit.

If we didnt build (the coal gasifcation

unit), we still needed generation, so we

landed a combined cycle unit, Gilling-

ham said. That decision has paid divi-

dends by taking advantage of the natural

gas market and not having to run a coal

unit in the shoulder months when its not

as economical and demand is down.

The solar power project was added in

2010 after OUC issued a request for pro-

posals. Regenesis won the proposal, and

Diversity, Zero Liquid Discharge and DedicationBY JUSTIN MARTINO, ASSOCIATE EDITOR

The Stanton Energy Center has two coal-fred

cofring units, two natural gas-fred combined

cycle units and a 5.91-MW solar array at the

same site. Photo courtesy of Orlando Utilities

Commission.

1310pe_20 20 10/16/13 5:29 PM

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1310pe_21 21 10/16/13 5:29 PM

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catalytic reduction technology that was

the frst SCR on a pulverized coal-fred

unit of more than 200 MW in the U.S.

and has 70 percent plus removal.

We run it as hard we need to meet

our emissions allowances, Gillingham

said.

The site is also a zero liquid discharge

site, which means any water used on

site or that comes in contact with the

process areas of the site has be routed

back to holding ponds and reused.

Orange Countys Eastern Wastewater

Treatment Facility provides reclaimed

water to the site for cooling, and all rain

runoff on the site is diverted to holding

ponds for reuse.

A zero liquid discharge facility is

good for the environment but it comes

with many challenges.

The primary mechanism for man-

aging the pond level is evaporation

through the scrubber process. When

In addition, building a utility-scale

solar project on the grounds of an

existing plant made it much easier to

connect it to the power grid, although

Butler said that was a fairly unique

opportunity and does not expect an

increase of solar projects at existing

power plants.

The majority of the power produced

at the Stanton Energy Center is still fos-

sil fuel-based, and OUC has multiple

processes to deal with with emissions.

Both coal-fred units have scrubbers

with 90-percent-plus removal and

electrostatic precipitators with 99.995

percent removal. Unit 2 has selective

Workers at the Stanton Energy Center face many

challenges, including using a mix of fuels and

operating a zero liquid discharge facility in a climate

with heavy rainfall. Photo courtesy of Orlando

Utilities Commission.

1310pe_22 22 10/16/13 5:29 PM

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When coal was the most economical

source of electricty, you may have your

problems during hurricanes and highly

inclement weather, but the 85 to 90 per-

cent capacity factor (in the coal-fred

units) made it easier to manage ponds,

Gillingham said. It wasnt easy, but it

was easier.

Quite honestly, sometimes our wa-

ter challenges are quite a bit more chal-

lenging than our air quality challenges.

A lot of the air quality challenges in the

past can typically be solved through

capital investments, operating tech-

niques and/or production effciencies.

Despite the challenges of running

a plant with high fuel diversity and a

zero liquid discharge system in a cli-

mate known for 52 to 54 of annual

rainfall, the plant has a low rate of

forced outages. Gillingham said the

fve-year average for forced outage rate

is 0.6 percent on Unit 2 and 1.3 percent

on Unit 1, both well below the nation-

al average.

So while the Stanton Energy Center

may stand out because of its unique

blend of power generation sources on

one site as well as its high levels of

emission control, both in air and wa-

ter quality, for Gillingham what stands

out the most is the quality of people

who run the facility.

Im very proud of the facility and

the people who work here, he said.

We have a forced outage rate that

would rival most anybody. We take a

very reliable approach to plant opera-

tions while trying to balance the eco-

nomics and budget.

the plant is burning less coal and us-

ing the scrubbers less, the plant is able

to evaporate less water. The combined

cycle units do not have evaporative

equipment, but their cooling towers

contribute to the ponds, making them

a producer of wastewater and a poten-

tial challenge to ZLD design. If one of

the coal-fred units is inactive four to

six months a year, the plant loses half

its evaporative ability, Gilling-

ham said.

Floridas rainfall also contrib-

utes to the issue. six to seven

inches of rain equates to around

an additional two feet of water

level in the recycle pond.

The coal-fred units at Stanton Energy Center

burn a blend of Illinois Basin and Central

Appalachian pulverized coal. Photo courtesy

of Orland Utilities Commission.

1310pe_24 24 10/16/13 5:29 PM



1310pe_25 25 10/16/13 5:29 PM

www.power-eng.com26

theres obvious technical challenges

with renewables. Theyre becoming

more cost-effective, but still very ex-

pensive and they have the limitations

of intermittency, which creates prob-

lems for the quality of service, at least

in the United States, that everybodys

accustomed to. When you turn the

switch on, the power is there whenever

you need it. For us, its not just simply

an economic consideration, its also a

diversity and long-term consideration

as Marv was alluding to.

Mike Rencheck: Theres some oth-

er aspects when you look at the opera-

tion of a grid where nuclear isnt fully

compensated for its entire support of

the grid. In other words, a lot of volt-

age control and frequency control

comes from these very large machines

that you simply cant get from a natural

gas plant or a renewables offering right

now, and if you would, you would have

to add other components into the sys-

tem, making it much more expensive.

When you couple that with the ability

of uranium as a fuel being only 5 to

15 percent of the cost of operating a

unit, you can see that over time, theres

relatively very little volatility due to

swings in fuel pricing.

Bill Johnson: I think I am the cus-

tomer representative in the group, or

at least the person who is in charge of

Low natural gas prices,

an increase in the use of

renewable energy and

the high upfront costs of

nuclear have dominated

the headlines, but many in the nuclear

industry believe these are just tempo-

rary setbacks. Power Engineering sat

down with several nuclear industry

executives about the current state of

nuclear and its future. The participants

were: Bill Johnson, CEO of the Tennes-

see Valley Authority; Mike Rencheck,

CEO of AREVA Inc. North America;

Marvin Fertel, CEO of the Nuclear En-

ergy Institute; Neil Wilmshurst, Vice

President of Nuclear, Electric Power

Research Institute; and Joe Zwetolitz,

President of Nuclear Energy, Babcock

& Wilcox. What follows is a transcript ,

edited for style and length, of that dis-

cussion.

PE: With the price of gas so low

and the price of solar panels

dropping, and the cost of a new

nuclear power plant running in the

billions, like we see at Vogtle and

Summer, what is the financial ar-

gument for nuclear?

Marvin Fertel: You mention Vogtle

and Summer. Vogtle and Summer are

obligated to, on a continuous basis

almost, to inform their public utility

BY SHARRYN DOTSON, ASSOCIATE EDITOR

commission of the economic value of

Vogtle and Summer to their ratepayers

and customers in Georgia and South

Carolina. Up through the last review

that they did, they continue to find

that, over the life of the plant, its go-

ing to save their customers at Vogtle at

least $4 billion over the next best al-

ternative, which is natural gas. I think

part of the reason for that is youre

looking at a 60-year asset and youre

projecting out not only gas prices, but

youre projecting out the performance

of the nuclear plant. I think part of the

challenge is the upfront capital costs,

but if you look at customers over the

long term, nuclear probably fares pret-

ty well, we just dont think long-term

enough.

Joe Zwetolitz: Marvin, youre the

right person to respond to this from

an overall industry perspective and I

agree completely. For us, its about not

putting all your eggs in one basket. Gas

is cheap today, but weve seen the price

go up and down in the past. Bill can

probably talk about this, hes probably

seen it. As the price is low, its very at-

tractive to build gas but you have to

maintain your options in the future,

and if everybody were to go to gas

today, theyd probably suffer some of

the same problems as in the past. Not

just with gas, if you look at renewables,

Nuclear ExecutRoundtable

1310pe_26 26 10/16/13 5:29 PM

www.power-eng.com 27

residential customers, it had gone up

into the 46 or 47 cents per kilowatt-

hour range and that was unaccept-

able. They were basically telling her to,

I think, junk the experiment and get

back to making sure they had a reliable

grid at lower prices.

PE: In light of the recent court

decision ordering the NRC to finish

looking into Yucca Mountain as a

nuclear waste storage site, where

do we stand with respect to waste

storage? How big of an impact

does the waste storage issue have

on the nuclear industrys ability to

be competitive?

Fertel: First of all, on the court deci-

sion, we think that the NRC will even-

tually tell everybody if they are going

to go forward. We think that theyll

be able to finish the safety evaluation

report, which we expect will demon-

strate that Yucca Mountain, at least

competitive around the world. I have

also read stories recently about the ex-

periment in Germany where they de-

cided to get out of nuclear and replace

almost entirely with renewables, and

theres a lot of cracks starting to be seen

in that strategy. The business commu-

nity in Germany is really starting to

complain about the electricity rates go-

ing up. I think itll be interesting to see

how Germany does with their experi-

ment. I think if anybody can do it and

make it work, they probably can, but

theyre going to have some struggles

and its going to be a challenge to be

able to get there.

Fertel: To Joes point, The Journal

had an article this weekend where the

business community apparently sent a

letter to (German Chancellor Angela)

Merkel just before the election empha-

sizing the fact that costs in the busi-

ness community had doubled from

about 12 or 13 cents to 25 cents. For

running a power system, and I would

agree with all those comments. A

couple of things we think about with

nuclear, obviously, is the fuel diversity.

You dont want to put all your eggs in

one basket. The environmental ben-

efits over a 60-year period of the clean-

est technology we have. Mike Ren-

check makes an excellent point in the

importance of large rotating masses in

the frequency control - which is a fine

point of physics - turns out to be really

important in making sure the trans-

mission system is stable. So for us, this

comes down to power density trans-

mission support, low price when you

spread it over 60-80 years of the assets.

General concept of balance of the port-

folio. I think theres still a strong case

to be made for nuclear going forward.

Zwetolitz: I do want to make one

other point. Just looking at gas around

the world, were obviously the lowest,

and so nuclear becomes a lot more

BILL JO

HN

SON

MARVIN FERTEL

MIKE RENC

HEC

K

NEIL W

ILMSH

UR

ST

JOE ZW

ETOLITZ

utive

1310pe_27 27 10/16/13 5:29 PM

www.power-eng.com28

like Vietnam and Turkey, were saying

Were being advised by IEA to con-

sider the whole fuel cycle, and actually

consider disposal before we build a

program. What is the U.S. doing about

it? People are looking at us as an ex-

ample, like Well, you guys havent fig-

ured it out yet, why should we figure it

out before we start?

PE: What is the status of the

mPower small modular reactors

and the SMR project at the Clinch

River plant site?

Zwetolitz: Weve been in the design phase for the SMR for a number of

years. We are looking

for a goal of next year

to have our design

certification applica-

tion being submitted

to the NRC some-

time in the late part

of 2014. And then in

2015, working with

TVA, we hope to have

a construction per-

mit application sub-

mitted at that time. It

will take a number of

years going through the NRC process

to support that, so design is going on

to support the DCA, we have detailed

design going to continue after that. All

that converging around 2018 or 2019

to have design certification document

in hand and all of that in support of

a goal of having two SMR mPower

units running at Clinch River in the

2021 timeframe. We have the agree-

ment with the Department of Energy

in terms of the funding opportunity,

which we were awarded, so thats al-

ready underway. We had a recent in-

crease in the amount that has been

provided under that agreement. We

look at this as an excellent opportuni-

ty to work with the federal government

to develop U.S. technology thats going

to be a game changer in the nuclear

from the staff standpoint, is safe. Were

not sure theyll get money to do very

much more because of Senator (Har-

ry) Reid, so Im not sure how much

movement well see on that. From the

waste standpoint, part of the blessing

and the curse for us is we manage the

waste so safely and securely at our sites

that quote, unquote, theres no cri-

ses, and thats why the government

can steal $30 billion and not fulfill

its obligation. And there wont be any

crisis because we will continue to do

that. To your question of how does it

hurt us competitively, it hurts us a lit-

tle bit because were paying for it, but

thats only part of the issue. The issue

is everybody else should be paying for

what they should be paying for. So, we

would like to see all costs fairly inter-

nalized for everybody, and we would

like to see our waste program go for-

ward. But, fundamentally, were in it

for the long haul.

Rencheck: Just to comment on

the waste statement. Really, 96 per-

cent of a fuel assembly is reusable. So,

the amount of waste produced is very

small, in essence, because you can

recycle the fuel assemblies. Its done

with techs today and if we spend more

R&D efforts on it, then Im sure we

can continue to improve on those pro-

cesses, either through n

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