pwer engineering october 2013
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power engineering magazineTRANSCRIPT
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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
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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
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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
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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-
ements show RE factors of
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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.
1310pe_6 6 10/16/13 5:28 PM
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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
U.S. Nuclear Power SurvivalBY MARY JO ROGERS, PH.D., PARTNER, STRATEGIC TALENT SOLUTIONS
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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
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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
-
For info. http://powereng.hotims.com RS# 15
See Us at POWER-GEN Intl, Booth # 3001
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
-
FOR FURTHER INFORMATION CONTACT US: CALL +44 1509 611 511 OR EMAIL [email protected]
ENERGY SOLUTIONS FOR THE GLOBAL POWER INDUSTRY
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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
-
For info. http://powereng.hotims.com RS# 13
See Us at POWER-GEN Intl, Booth # 2411
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
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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