20110527Teply Di.pdf

RECEIVED
2011 HAY 27 AM 11= 03
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR )
APPROVAL OF CHANGES TO ITS )
ELECTRIC SERVICE SCHEDULES )
AND A PRICE INCREASE OF $32.7 )
MILLION, OR APPROXIMATELY )15.0 PERCENT )
CASE NO. PAC-E-l1-12
Direct Testimony of Chad A. Teply
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-l1-12
May 2011
1 Q.Please state your name, business address and position with PacifCorp dba
2 Rocky Mountain Power (the "Company").
3 A.My name is Chad A. Teply. My business address is 1407 West North Temple,
4 Suite 210, Salt Lake City, Utah. My position is vice president of resource
5 development and constrction for PacifiCorp Energy. I report to the president of
6 PacifiCorp Energy. Both Rocky Mountain Power and PacifiCorp Energy are
7 divisions ofPacifiCorp.
8 Qualifications
9 Q.Please describe your education and business experience.
10 A.I have a Bachelor of Science Degree in Mechanical Engineerig from South
11 Dakota State University. I joined MidAmerican Energy Company in November
12 1999 and held positions of increasing responsibility within the generation
13 organization, including the role of project manager for the 790-megawatt Walter
14 Scott Energy Center Unit 4 completed in June 2007. In April 2008, I moved to
15 Northern Natual Gas Company as senior director of engineering. In February
16 2009, I joined the PacifiCorp team as vice president of resource development and
17 constrction, at PacifiCorp Energy. In my curent role, I have responsibilty for
18 development and execution of major resource additions and major environmental
19 projects.
20 Q.What is the purpose of your testimony?
21 A.The purose of my testimony is to:
22 . provide the Commission wìth information supporting the prudence of
23 capital investments in pollution control equipment, generation plant, and
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Rocky Mountain Power
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hydro projects being placed in service durng the test period; and
. support the prudence of incremental generation operations and
3 maintenance costs associated with certain new resources, new pollution
4 control equipment, and other generation fleet operational changes
5 impacting this case.
6 Background
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Please provide a general description of the pollution control equipment and
additional capital investments being placed in service, and the benefits
gained from the investments.
The pollution control equipment investments included in this case primarily result
in the reduction of sulfu dioxide ("S02"), nitrogen oxides ("NOx"), mercur
("Hg"), and particulate matter ("PM") emissions from the retrofitted Naughton
Unit 2, Wyodak, Huntington Unit 1, Hunter Unit 2 and Jim Bridger Unit 3
facilities. These investments are required to comply with curent, proposed, and
probable environmental regulations as fuer discussed in the direct testimony of
Ms. Cathy S. Woollums. These investments constitute approximately 60 percent
of the Company's capital investments placed in service or projected to be placed
in service from January 2011 through December 2011.
Hydro generation plant investments, which constitute approximately 4
percent of the Company's capital investments placed in service or projected to be
placed in service from January 2011 though December 2011, are primarily new
license implementation measures required by the Federal Energy Regulatory
Commission to allow contiued operation of these low-cost generation assets.
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The generation plant tubine upgrade investment enhances the Company's
overall generation capability and cycle efficiency without increasing emissions
for the large thermal unìt that receives this equipment.
Other generation plant investments durng the test year support asset
safety, reliability, and cost effectiveness via reduced risk of equipment and
component failures, enhanced control systems, and improved securty provisions.
Please describe the primary environmental regulation requiring the pollution
control investments included in this case.
Through the 1977 amendments to the Clean Air Act, Congress set a national goal
for visibility to remedy impairment from manmade emissions in designated
national parks and wilderness areas; this goal resulted in development of the
Regional Haze Rules, adopted in 2005 by the U.S. Environmental Protection
Agency ("EPA"). The first phase of these rules trgger Best Available Retrofit
Technology ("BART") reviews for all coal-fired generation facilities built
between 1962 and 1977 that emit at least 250 tons of visibility-impairg pollution
per year. Visibilty-impairing pollutants include S02, NOx and PM. The direct
testimony of Ms. Woollums includes additional discussion regarding the Regional
Haze Rules and other environmental drvers behind the pollution control
investments included in this case.
Please describe the efforts taken to evaluate available control technologies.
As part of the BART review of each facility, the Company evaluated several
technologies on their abilty to economically achieve compliance and support an
integrated approach to control criteria pollutants (e.g. S02, NOx, and PM for the
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facility), if it were to continue to operate and to bum coaL. The BART analyses
reviewed available retrofit emission control technologies and their associated
performance and cost metrcs. Each of the technologies was reviewed against its
abilty to meet a presumptive BART emission limit based on technology and fuel
characteristics. The BART analyses outlined the available emission control
technologies, the cost for each and the projected improvement in visibility which
can be expected by the installation of the respective technology. For each unit or
source subject to BART, the state environmental regulatory agencies identify the
appropriate control technology to achieve what the air quality regulators
determine are cost-effective emission reductions. Once the appropriate BART
technology was identified, the Company moved forward with ìts competìtive
bidding process to evaluate and ultimately select the preferred provider for the
projects.
Does the Company focus solely on environmental compliance factors when
determining which capital investments to make?
No. As part of the Company's coal fueled units compliance planning efforts,
consideration is given to selection of appropriate pollution control technologies as
well as alternate compliance options such as market purchases of replacement
power, re-powering to natual gas, and the procurement of replacement
generation. Examples of these analyses are discussed fuher in my testimony.
What other factors does the Company consider?
Factors such as ongoing compliance with existing operatig requirements, fuel
supply flexibilty, equipment end of life considerations, and operational
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effciencies are also factors tyically included in the Company's investment
decisions.
How has ongoing compliance with existing operating requirements factored
into planning of pollution control investments?
The Huntington Unit 1 and Hunter Unit 2 baghouse projects and the waste
handling phases of the Huntington Unit 1 and Hunter Unit 2 scrubber projects
presented in this case are good examples of how ongoing compliance with current
regulations factors into the company's pollution control investment planing
process. The addition of the baghouse wil significantly reduce PM emissions and
improve compliance with existing opacity stadards. The scrubber waste handling
systems wil ensure that the final waste product wil not contain any free liquids
and can properly be disposed of in the onsite landfill.
How has fuel supply flexibilty factored into planning of pollution control
investments?
The Hunter Unit 2 scrubber project is a good example of how fuel supply
flexibilty has factored into the Company's pollution control investment planning
process. As the Company contemplated BART requirements for Hunter Units 1
and 2, pollution control equipment that would meet required emission limits and
would permit utilzation of coal with higher coal sulfu content was evaluated.
The ability to fuel the Hunter units on coal with higher sulfu content while
meeting new emission limits wil help to maintain competitive fuel and generation
costs at this facility.
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How have existing pollution control equipment end of life replacement
considerations factored into planning of new pollution control investments?
The replacement of various scrubber system elements at Hunter Unit 2 is an
example. These elements include scrubber vessel work scope, scrubber recycle
pump replacements, and scrubber reagent injection nozzle replacements, as well
as the scrubber reagent preparation system replacement. By planning the Hunter
Unit 2 scrubber project tie-in to coincide with a planned maintenance outage cycle
for the unit, the project was able to replace equipment and components that had
exhausted their useful life, and at the same time address system capacity and
compliance requirements.
How have operational considerations factored into planning of pollution
control investments?
Operational considerations are included in the technical specifications for each of
the Company's pollution control projects. The material handling phases of the
Huntington Unit 1 and Hunter Unit 2 scrubber projects are two key examples of
the Company's efforts to improve operational efficiencies. These projects result in
the installation of scrubber waste dewaterig equipment that eliminates the
manual management of fly ash blending processes. Thus, in addition to
addressing system capacity concerns and maintaining waste disposal compliance,
these projects improve operational effciencies allowing plant staff to focus on
other operational responsibilities.
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What process is in place to explore ongoing investment in the Company's
coal units?
The existing integrated resource planning ("IRP") process conducted across the
six states served by the Company provides the process to analyze and address
ongoing investment in the Company's coal units versus alternatives including
retirement and replacement and repowerig. Futue IRPs wil increasingly focus
upon the complexity in balancing factors such as:
(1) pending environmental regulations and requirements to reduce emissions
in addition to addressing waste disposal and water quality concerns;
(2) avoidance of excessive reliance on anyone generation technology;
(3) costs and trade-offs of various resource options including energy
effciency, demand response programs, and renewable generation;
(4) state-specific energy policies, resource preferences, and economic
development efforts;
(5) the need for additional transmission investment to reduce power costs
and increase effciency and reliability of the integrated transmission system;
and
(6) managing the impact on customer rates.
Has the Company compared the cost of continued operation of the retrofitted
coal fueled generation units contemplated in this case to its other generation
sources, including natural gas fueled generation?
Yes. The Company has developed Confidential Exhibit No. 22 to compare the
cost of retrofitted coal fueled generation units to other generation resource classes.
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Rocky Mountain Power
1 Confidential Exhibit No. 22 presents the 2009 embedded generation bus bar cost
2 per megawatt-hour differences of the varous generation resources within the
3 Company's generation fleet, including re-powered and combined-cycle natual
4 gas fueled generation. Confidential Exhibit No. 23 provides the incremental
5 revenue requirement associated with the pollution control equipment retrofits in
6 this case on a dollars per megawatt-hour basis adjusted to 2009 dollars.
7 In general terms, the capital cost on a dollars per megawatt basis to retrofit
8 pollution controls on existing coal fueled generation is approximately the same or
9 less than the capital cost to build a new combined cycle natual gas generation
10 unit. However, fuel costs of a combined cycle natual gas unit wil overwhelm
11 capital cost competitiveness when compared to a retrofitted coal fueled facility.
12 Natural gas on a dollars per milion Btu basis is approximately trple the cost of
13 coal, and even when considerig the effciency differences, the cost of electrcity
14 generated by an emission controlled coal fueled facility wil be significantly less
15 than the cost of electrcity from a new combined cycle.
16 These exhibìts demonstrate that maintaining the ability to operate the
17 existing coal units by retrofitting the units with the pollution control equipment
18 represents the least-cost option for customers. This is even before considering
19 factors associated with retirement of the coal units prior to their ratemaking
20 depreciation lives, such as stranded depreciation expense, the economic impact on
21 Wyoming, the loss of fuel diversity in the generation portfolio, and the impact on
22 system reliabilty.
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Has the Company applied least cost principles to selection of its pollution
control investments?
Yes. Various project revenue requirement analyses have determined the lower
cost alternative to customers for achieving the taget level of emission reduction
or control. These take the form of comparing the present value revenue
requirement impact of one technology to another and determining the present
value revenue requirement differential ("PVRR( d)") benefit to customers. I wil
fuher explain these analyses in the following testimony.
Has the Company assessed the costs of continuing to invest in individual coal
fueled generation assets versus replacing the lost generation with market
purchases?
Yes. The Company has developed economic analyses that provide an overview of
the PVRR( d) benefits associated with its pollution control investments, with
consideration given to potential C02 costs and resulting market pricing
assumptions. Confidential Exhibit No. 24 and Confidential Exhibit No. 25
provide the results of said analyses at various points in time and with various C02
costs and market pricing assumptions. Confidential Exhibit No. 24 provides a
PVR( d) view of the projects presented in this case at the time of planing and
approval of the pollution control investments, utilizing then curent C02 cost and
market pricing assumptions. Confidential Exhibit No. 25 provides a PVRR( d)
view of the units that received the pollution control investments on a going-
forward basis, utilizing CO2 cost and market pricing assumptions and the System
Optimizer Coal Utilization Case Studies referenced below. These PVRR(d)
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analyses provide positive results for the various scenaros presented and fuher
demonstrate prudence of the pollution control investments. The PVRR( d)
analyses also offer insight into the potential impacts of various CO2 cost and
market pricing scenaros on investment recovery periods.
Has the Company assessed the costs of continuing to invest in individual coal
fueled generation assets versus the cost of convertig the units to natural gas
as fuel source?
Yes. The Company has developed. economic analyses intended to provide an
overview of the PVRR( d) benefits associated with its pollution control
investments, with consideration given to potential CO2 costs and resulting market
pricing assumptions, versus natual gas repowerig scenarios. Confidential
Exhibit No. 26 provides the PVR(d) results of said natual gas repowering
analyses. The results of these PVRR( d) analyses provide positive results for the
various scenarios presented and fuher demonstrate prudence of the pollution
control investments presented in this case, and also offer insight into the potential
impacts of varous CO2 cost and market pricing scenaros on investment recovery
periods.
Does the Company believe that it has appropriately assessed the cost
effectiveness of the pollution control investments?
Yes. In assessing when and whether to proceed with pollution control
investments, the Company has' considered cost effectiveness of reasonable
options.
Measures of capital cost on a dollars per kilowatt basis have been
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reviewed durng studies of alternatives, as well as the cost to remove a ton of a
pollutant, which is applied specifically as par of the BART determination
process. Recently, BART determinations issued by the EPA and other state
agencies for S02 and NOx emission control projects have demonstrated that
removal costs of up to $7,500 per ton are not considered cost prohibitive. PM
emission reductions cannot tyically be compared to this same cost per ton
removal standard since the incremental emissions improvement wil be much
smaller due to the relatively high removal effciency level of existing PM removal
equipment. It should also be noted that when ongoing compliance and/or
equipment end-of-life issues must be addressed, the dollar per incremental ton
removed evaluation is not applicable. A listing of representative costs per ton
removed for the pollution control projects presented in this case is included in
Confidential Exhibit No. 27.
Has the Company accounted for pollution control investments in its forward-
planning cycles?
Yes. The Company makes every effort to identify, quantify and include forward-
looking environmental compliance projects in its planing processes.
Is the Company obligated to install pollution controls required by state
permits, regardless of whether final EPA review and approval of the
respective regional haze state implementation plans remains pending?
Yes. The BART permits and constrction permìts issued by the respective state
agencies for the pollution control investments contemplated in this case include
stand-alone requirements enforceable by the laws of the respective states. These
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requirements are enforceable independent of whether EPA has approved the
respective state implementation plans.
Are the pollution control investments in this case required to comply with
existing regulations?
Yes. The pollution control investments in this case are required to comply with
existing regulations including Regional Haze Rules, National Ambient Air
Quality Standards, the Regional S02 Milestone and Backstop Trading Program
developed in alignent with existing federal regulations and administered in Utah
and Wyoming, state issued constrction and operatig permits, and state
implementation plans. Exhibit No. 28 provides an overview of existing
regulations with which the projects wil be in compliance.
Do the pollution control investments also support compliance with
anticipated likely regulations?
Yes. In many cases the investments are also expected to support compliance with
anticipated likely regulations as curently proposed. Exhibìt No. 28 provides an
overview of anticipated likely regulations with which the projects presented in
this case are anticipated to support compliance.
Are the pollution control investments in this case based on anticipated
regulations that do not exist, may never be implemented, and if implemented,
may require technologies other than those installed by the Company?
The pollution control investments in this case are required to comply with existing
regulations being administered by the respective state departents of
environmental quality.
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Does the Company anticipate that final EPA approval of the respective state
implementation plans will require alternate pollution control equipment to
be installed, making the equipment contemplated in this case obsolete?
No. While it is possible that the EPA will require more strngent emission limits,
any such requirement will be in addition to - not in place of - the pollution
control technology selections completed to date, which apply best available
retrofit technology, comply with existing state and federal regulations, and
support Regional Haze Rule objectives. The Company also incorporates into its
pollution control equipment contract specifications design considerations intended
to provide appropriate levels of operating margin, equipment redundancy, and
system maintainability and reliability provisions to support an expected range of
process inputs, operating conditions, and system performance. Although the
Company cannot predict future pollution control regulations and associated
emissions limits, the Company does take steps to procure a prudent level of
design flexibility to accommodate potential changes in system performance
requirements, where practicaL.
Has the Company communicated to the Commission its knowledge and
understanding of additional costs required to maintain compliance with
current and anticipated environmental regulations?
Yes. As the Company becomes aware of known or anticipated environmental
regulations, the Company begins assessment of requirements and incorporation of
appropriate project completion timelines and cost estimates into ìts business
planing processes. The Company's IRP and IRP updates fied with this
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Commission also include extensive discussion regarding the business planning
considerations given to curent and anticipated environmental reguations.
Has the Company developed other information regarding the Company's
overall emission reduction plans through 2023?
Yes. The Company has provided additional information including an overview of
the Company's long-term emission reduction commitment, project installation
schedules and compliance deadlines, emission reduction priorities, anticipated
customer impacts, and brief descriptions of other environmental initiatives that
are also expected to impact futue operating costs of the Company in its recent
filings in other states. A copy of this additional information is provided for
reference in Exhibit No. 29.
Does the Company continue to improve its analysis of market risk associated
with emerging environmental regulations, particularly risks associated with
greenhouse gases?
Yes. In support of the Company's 2011 IRP development process, the Company
incorporated System Optimizer Coal Utilization Case Studies 20-24. These case
studies were designed to investigate the impacts of CO2 cost and gas price
scenarios on the Company's existing coal fleet after accounting for coal plant
incremental costs. This study used new modeling fuctionality that enables
representation of existing plant repowering and retrofitting as futue resource
options. Additionally, the Company acquired and used customized enhancements
to the model for estimating carbon dioxide emissions and regulatory costs
associated with spot market balancing sales and purchases. These case studies
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include capital expenditues for planed and/or ongoing pollution control
equipment investments included in the Company's business plan, including
mercur HAPs MACT compliance costs. Due to the timing of these case studies
in 2010, the Company's preliminary capital cost estimates for compliance with
the EPA's proposed coal combustion residuals ("CCR") rules and Clean Water
Act Section 316(b) cooling water intake rules . were not incorporated. CCR
compliance costs have since been incorporated into the Company's business plan,
and preliminar estimates for futue Clean Water Act Section 316(b) cooling
water intake compliance projects are being developed and wil be incorporated
into the Company's next business plan cycle. These data sets wil be incorporated
into futue updates of the coal utilzation case studies. Exhibit No. 29, Table 1
lists the Company's planned air emissions related pollution control projects
included in the case studies, with the exception of activated carbon injection
projects for mercur emissions control.
Do the results of the Company's coal utiization case studies included in the
2011 IRP process result in the Company requesting accelerated depreciation
treatment of pollution control investments contemplated in this case?
No. The results of the Company's coal utilzation case studies do, however,
identify certain CO2 cost and gas price scenarios that would lead the Company to
re-evaluate strategic asset planning for certain units. Re-evaluation of strategic
asset planing would be vetted via the Company's depreciable life studies that are
completed every five years, with the next due in 2013.
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Wil the Company continue to include System Optimizer Coal Utiliation
Case Studies in its IRP process?
Yes. The Company wil continue to include and refine System Optimizer Coal
Utilization Case Studies in its futue IRP processes.
Has the Company installed the pollution control investments in an effcient
manner?
Yes. As fuer discussed in Exhibit No. 29, emission reduction projects of the
number and size described above take many years to engineer, plan, and build.
When considering a fleet the size of the Company's, there is a practical limitation
on available constrction resources and labor. There is also a limit on the number
of units that may be taken out of service at any given tie, as well as the level of
constrction activities that can be supported by the local infrastrctues at and
around these facilities. Additional cost and constrction timing limitations include
the loss of large generatig resources durng some parts of constrction and the
associated impact on the reliability of the Company's electrcal system durg
these extended outages. In other words, it is not practical, and it is unduly
expensive, to expect to build these emission reduction projects all at once or even
in a compressed time period.
Does the Company believe that the pollution control investments
contemplated in this case meet the "used and useful" standard?
Yes. Each of these investments achieves its original intent, provides benefit to
customers, and allows the Company to maintain compliance with state issued
permits, state implementation plans, and regional S02 milestones and backstop
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1 trading progrms.
2 Customer Considerations
3 Q.What are the benefits to customers of installng the pollution control
4 equipment and why should Idaho customers pay the costs related to this
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Customers directly benefit from the continued availabilty of low-cost generation
produced at the facilties while also achieving environmental improvements from
these resources, resulting in cleaner air. In addition, the tie-in of these necessary
controls is being accomplished durg planed maintenance outages, as opposed
to scheduling separate outages for this work, which reduces replacement power
costs. The Company has 10 BART-eligible units in Wyoming and four in Utah.
The BART controls for each of these units must be installed as expeditiously as
possible, but no later than five years from the date the respective SIPs are
approved and prior to the compliance dates specified in the permts
Postponing installation of the pollution control equipment included in this
case to later planned maintenance outages would make it virtally impossible for
the Company to effectively ensure that all of its affected units meet compliance
deadlines and would place the Company at risk of not having access to necessary
capital, materials, and labor while attempting to perform these major equipment
installations in a compressed timeframe. As the deadlines for environmental
requirements across the countr draw closer, the demand for equipment and
skiled labor is likely to increase, making timely compliance more diffcult
wìthout incurg significant additional cost.
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I Description of Pollution Control Investment Projects
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Please describe the Naughton Unit 2 scrubber addition project and
associated equipment.
The scrubber addition project at the Naughton Unit 2 power plant includes the
installation of S02controls. The capital investment for the project being placed in
service during the test period is approximately $152 millon. Constrction began
in 2010, and the project is expected to be placed in service by November 2011.
The new pollution control equipment wil be tied into the existing unit durng a
scheduled plant maintenance outage. The project wil install a flue gas
desulfuzation ("FGD") system. The FGD system injects reagent slurr
containing sodium carbonate and sodium bicarbonate in the top of an absorber
vessel ("scrubber") with a network of spray nozzles. The distrbution of spray
nozzles and trays causes the sodium carbonate slur to intermix with the flue gas
passing through the absorber vesseL. The S02 in the flue gas reacts with the
sodium carbonate in the slur to form waste slur of sodium sulfite and sodium
sulfate. The liquid waste slur is then captued and transported to a scrubber
waste pond for disposaL. The scrubber waste wil ultimately be dewatered and
retained in a closed and capped scrubber waste cell on the Naughton plant site.
Other equipment to be installed as part of the project includes induced
draft fans, boiler reinforcement, new ductwork and a new chimney, sodium
carbonate slur reagent preparation systems, waste material handling systems,
electrcal infrastrcture, controls, and other miscellaneous appurenances and
support systems.
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Is the Company also installig scrubber facilties at the Naughton Unit 1
power plant?
Yes. The Naughton Unit 1 scrubber project is being constrcted concurently with
the Naughton Unit 2 scrubber project, but on a different schedule. The description
of the Naughton Unit 1 scrubber project is for the most par identical to that
provided above.
Wil the Naughton Unit 1 scrubber addition project also be placed in servce
during the test period used in this case?
No. The Naughton Unit 1 scrubber project is expected to be placed in service
durng the next planed major maintenance outage for that unit, expected to be
complete by May 2012. The planned major maintenance outages for the
Company's generation assets are scheduled on a control area basis, considering
optimal frequency between overhauls and to minimize the number of major units
off line at anyone time. The Company completed its most recent overhaul to
Naughton Unit 1 in 2008 and is scheduled for its next overhaul in the spring of
2012. The Company's intent in establishing the tie-in schedules for the Naughton
Unit 1 and Naughton Unit 2 pollution control equipment was to balance the
aggregated constrction costs and schedules for the pollution control equipment
projects against the established planned maintenance overhaul schedules, work
plans, and budgets for the respective units.
Are common facilties costs associated with the Naughton Unit 1 and
Naughton Unit 2 scrubber addition projects included in this case?
Yes. The cost of all common facilities that are required to be placed in service to
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allow prudent operation of either unit's new emission control equipment are
incorporated into the Naughton Unit 2 capital investment being placed in service
by November 2011. Common facilities include reagent preparation, waste
disposal, electrcal supply, and ancilar utility systems, as well as site preparation
and the chimney.
Please describe the Wyodak power plant stand-alone bag house project and
associated equipment.
A stand-alone bag house was installed at the Wyodak power plant for control of
PM, S02, and Hg emissions consistent with requirements. In order to increase the
S02 removal effciency of the unit above 90 percent as required to comply with
environmental requirements, a bag house must be utilized in conjunction wìth the
existing dr spray drer absorbers ("SDAs"). Without a bag house, the best S02
removal efficiency a SDA on the unit can achieve with Wyodak coal is between
70 and 80 percent. Adding the bag house is necessary to achieve the permitted
S02 removal requirements.
The Company's share of the capital investment for the Wyodak bag house
project being placed in service durng the test period is approximately $104
milion. Construction began in 2010, and the project was placed in service at the
end of April 2011. The new pollution control equipment was tied into the existing
unit durng a scheduled plant maintenance outage.
The bag house captues PM from the flue gas stream as it passes though
the bag house and wil improve the unit's efficiency in removing S02 and Hg
from the flue gas. The dr parculate waste stream containing both fly ash and
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scrubber waste wil then be transported to an ash collection pond on adjacent coal
mine propert for disposaL.
Other equipment to be installed as par of the project includes induced
draft fans, boiler reinforcement, new ductwork, waste material handling systems,
electrcal infrastrctue, controls, and other miscellaneous appurenances and
support systems.
Please describe the Huntington Unit 1 power plant scrubber project, and
associated equipment.
The scrubber project at the Huntigton Unit 1 power plant provides required S02
controls for the unit, as well as a new scrubber waste material handling system
and conversion of the chimney to wet operation. The new waste handling
equipment wil be designed to manage the increase in waste product from the
higher removal efficiency and increased throughput of the scrubber.
The capital investment for the scrubber waste material handling project
being placed in service durng the test period is approximately $29 milion.
Constrction began in 2010, and the scrubber waste handling project was placed
in service in March 2011. Installation of the waste handling portion of the project
wil be completed with the plant in service. The portion of the Hunter 2 scrubber
project that resulted in increased flue gas desulfurization ("FGD") system slur
delivery system capacity, by replacing recycle pumps and reagent supply piping
and appurenances, was placed in service prior to the test period for this docket.
The wet stack conversion was also completed prior to the test period.
The scrubber waste material handling project includes forced oxidation
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compressors to allow the full conversion of calcium sulfite to calcium sulfate,
larger absorber agìtators, hydroclones as a replacement for the existing thickener,
vacuum dr filters with associated transfer tans and pumps, electrcal
infrastrctue, controls, and other miscellaneous appurenances and support
systems. Installation of this equipment wil allow the scrubber slur waste stream
to be more effectively dewatered to maintain compliance with scrubber waste
landfill disposal requirements. Installation of this new equipment also addresses
equipment end-of-life issues for existing equipment including the absorber
agitators and the thickener. These particular equipment items were nearig their
end-of-life stage and would have required capital replacement in the near futue.
Please describe the Hunter Unit 2 power plant bag house conversion project,
scrubber project, and associated equipment.
The bag house conversion project at the Hunter Unit 2 power plant wil convert an
existing electrostatic precipitator to a bag house to meet PM and Hg emissions
control requirements. The bag house wil captue PM and help remove Hg from
the flue gas stream as it passes through the bag house. The dr pariculate waste
stream is then transported to an on-site landfill for disposaL. Other equipment to
be installed as par of the project includes upgrading the scrubber booster fans,
boiler reinforcement, new ductwork, modifications to the existing chimney to
accommodate wet operation, relocation of the stack opacity monitors, waste
material handling systems, electrcal infrastrctue, controls, and other
miscellaneous appurenances and support systems. The Company's share of the
capital investment for the bag house conversion project being placed in service
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1 durng the test period is approximately $54 milion. Constrction began in 2010,
2 and the project was placed in service at the end of April 2011. The bag house
3 conversion was completed durng a scheduled plant maintenance outage.
4 The scrubber project at the Hunter Unit 2 power plant wil result in
5 improved S02 controls for the unit and wil install a new scrubber reagent
6 preparation system and an improved scrubber waste material handling system to
7 meet environmental requirements. The scrubber project wil increase unit's
8 existing FGD slur delivery system capacity by replacing recycle pumps and
9 reagent supply piping and appurenances, effectively increasing the liquid
10 ("slur") to flue gas ratio within the absorber vessels ("scrubbers"); installng a
11 new higher capacity scrubber reagent preparation system, and expandig waste
12 material handling system capacity with a new system. The FGD system injects
13 lime slur in the top of a scrubber with a network of spray nozzles and trays. The
14 distribution of spray nozzles and trays causes the lime slur to intermix with the
15 flue gas passing through the absorber vesseL. The S02 in the flue gas reacts with
16 the calcium in the slur to form a slur waste of calcium sulfite and calcium
17 sulfate. The waste material handling portion of the project wil add oxidation air
18 blowers to the system to ensure conversion of the calcium sulfite to calcium
19 sulfate. Calcium sulfate is easier to dewater and the change wil allow the slur
20 waste stream to be more effectively dewatered, and transported to a scrubber
21 waste landfill for disposaL.
22 The Company's share of the capital investment for the scrubber FGD
23 system and scrubber waste material handling portions of the project being placed
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in service durng the test period is approximately $23 millon. Constrction began
in 2010, and the scrubber FGD system project activities were completed and
placed in service at the end of April 2011. The scrubber waste material handling
portion of the project is expected to be completed by July 2011. The scrubber
reagent preparation system portion of the project is expected to be placed in
service by March 2012. Costs for the scrubber reagent preparation system portion
of the project are not included in this case. The scrubber FGD system scope of
work was completed durg a scheduled plant maintenance outage. Installation of
the reagent preparation system upgrade and the waste handling portion of the
project wil be completed later, and wil not require an extended plant
maintenance outage for tie-in.
Equipment to be installed as part of the various portions of the scrubber
project includes lime slur reagent preparation equipment; waste material
handling system equipment including hydroclones, as a replacement for the
existing thickener, and vacuum drm filters; electrcal infrastrctue; controls; and
other miscellaneous appurenances and support systems.
Is the Company also completing a scrubber project at the Hunter Unit 1
power plant?
Yes. The Hunter Unit 1 scrubber project is being constrcted concurently with
the Hunter Unit 2 scrubber project, but on a different schedule. The project is
being constrcted concurently with the Hunter Unit 2 project to benefit from
installation and operational costs synergies achieved through the use of common
facilities between the two units.
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Please describe the Hunter Unit 1 power plant scrubber project and
associated equipment.
The scrubber project at the Hunter Unit 1 power plant wil result in improved S02
controls for the unit and wil install a new scrubber reagent preparation system
and an improved scrubber waste material handling system to meet environmental
requirements. The detailed description of the Hunter Unit 1 scrubber project is for
the most part identical to that provided for Hunter Unit 2 above.
Costs associated with the capital investment for the Hunter Unit 1
scrubber project ARE NOT included in the revenue requirement in this case due
to the projected in-service dates of the respective portons of the project.
Constrction began in 2011, and the scrubber FGD system portion of the project
is expected to be fully placed in service by May 2014 following a scheduled plant
maintenance outage on the unit. The scrubber reagent preparation portion of the
project is scheduled to be placed in service by March 2012. The scrubber waste
material handling portion of the project is expected to be placed in service by
March 2013. Installation of the reagent preparation and waste handling portions of
the project wil be completed while the plant is in service, and wil not require an
extended plant maintenance outage for tie-in.
Please describe the Jim Bridger Unit 3 power plant scrubber project and
associated equipment.
The scrubber project at the Jim Bridger Unit 3 power plant wil result in improved
S02 controls for the unit by allowing the scrubber bypass dampers to bypass less
flue gas. The scrubber project wil increase the unit's existing FGD slur
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delivery system capacity by replacing recycle pumps and reagent supply piping
and appurenances, effectively increasing the liquid ("slur") to flue gas ratio
within the absorber vessels ("scrubbers"); install new scrubber vessel internals
("trays, piping and nozzles"); replace induced draft fans; install variable
frequency drves; and install the associated power distrbution, controls and
appurenances. The FGD system injects sodium-based slur in the top of a
scrubber with a network of spray nozzles and trays. The distribution of spray
nozzles and trays causes the slur to intermix with the flue gas passing though
the absorber vesseL. The S02 in the flue gas reacts with the sodium in the slur to
form a slur waste of sodium sulfite and sodium sulfate. The scrubber waste, in
slur form; is sent to a waste pond where the waste liquor is allowed to evaporate
and the solids are ultimately impounded in the landfill.
The Company's share of the capital investment for the scrubber project
being placed in service durng the test period is approximately $17 millon.
Constrction began in 2010, and the scrubber project activities are expected to be
completed in June 2011. The scrubber waste material handling portion of the
project is expected to be completed by July 2011. The scrubber project scope of
work is being completed durng a scheduled plant maintenance outage.
Please describe the other major pollution control projects and associated
equipment contemplated in this case.
The other major pollution control projects to be placed in servce durng the test
period include:
(1) the Naughton Unit 2 low NOx bumers installation project;
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(2) the Wyodak low NOx bumers installation project; and
(3) the Hunter Unit 2 low NOx bumers installation project.
The low NOx bumers projects referenced above wil install new bumers that
utilze improved combustion characteristics and a separated over-fire air supply to
the boiler to reduce NOx emissions.
Please describe the emissions improvements that wil be achieved with the
pollution control projects described above.
The pollution control equipment investments described above are required by the
permit terms and conditions issued in response to the environmental requirements
described herein and support the Company's ongoing commitment to reduce S02
emissions from the Company's generation fleet by approximately so percent
compared to 200S levels. In addition to reducing S02 emissions, the projects
support the Company's ongoing commitment to reduce NOx emissions from the
Company's generation fleet by approximately 40 percent compared to 200S
levels. The Company believes that these investments are complementar to and
consistent with BART Regional Haze planning requirements intended to improve
the visibility in certin national parks and wilderness areas, and that they
exemplify a reasonable approach to achieving emission reductions in our
operating territory. The emission reductions that result from these projects have
been incorporated into the approved operating permits for the respective units.
Have the costs of the projects been prudently managed by the Company?
Yes. The scrubber and bag house projects described above have been contracted
under lump-sum, tuey, engineer, procure and constrct ("EPC") contract terms
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which resulted from competitive bidding processes. The bumer replacement
projects have been contracted under multiple lump-sum contracts which resulted
from competitive bidding processes or job-specific work releases under
established service level agreement rate strctues. PacifiCorp management
continues to provide oversight of the projects and closely manages any project
execution plan changes or potential contract scope changes. PacifiCorp believes
that the permitted and constrcted pollution control projects and their timing
appropriately balance the need for emission reductions over time with the costs
and other concerns of our customers, our state utility regulatory commissions, and
other stakeholders.
Are there additional operating costs that wil be incurred as a result of the
installation of pollution control equipment?
Yes. Unfortately, but unavoidably, the operation of the new pollution control
equipment results in increased operation and maintenance costs associated with
reagent, waste disposal, and equipment maintenance. Incremental operation and
maintenance costs associated with the Dave Johnston Unit 3 scrubber and
baghouse project placed in service in May 2010, the Wyodak pollution control
project placed in service in April 2011, and the Naughton Unit 2 scrubber project
to be placed in service in November 2011 are included in this case. These costs,
as well as the capital investments identified above, are included in the revenue
requirement calculations for this case as explained in Mr. Steven R. McDougal's
direct testimony.
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1 Description of Generation Plant Turbine Upgrade Investment
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Please describe the Hunter Unit 2 power plant turbine upgrade project
presented in this case.
The Hunter Unit 2 power plant high pressure ("HP"), intermediate pressure
("IP"), and low pressure ("LP") tubine sections were replaced as part of this
project. The project was placed in service in April 2011.
Please describe the effciency improvements that will be achieved with the
turbine upgrade project described above.
The Company expects the Hunter Unit 2 tubine upgrade to allow more effcient
tubine performance without increasing emissions, such that approximately 9
megawatts (Company share, adjusted for pollution control equipment auxilar
load) of incremental capacity can be generated by the unit. Mr. Gregory N. Duvall
has included incremental capacity upgrade in the net power cost analysis
associated with these projects in his direct testimony.
What is the basis for justification of this investment?
As part of the Company's efforts to meet the growing demand for generation, and
given the advancing technological improvements in steam tubine design and
manufactuing, the Company has initiated a tubine upgrade initiative. This
tubine upgrade initiative wil fuher enhance PacifiCorp's overall generation
capability and cycle efficiency for the large thermal units being provided with this
equipment.
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1 Description of Other Generation Plant Investments
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What other generation plant capital investments are included in~ this
application?
Generation plant repair and replacement investments and a coal unloading facility
addition at the Hayden power plant are the remaining projects included in this
case. The repair and replacement projects fall primarily wìthin three major
categories: (i) boiler section replacements; (ii) control system upgrades; and (iii)
other. The revenue requirement impact of these investments has been included in
Mr. McDougal's direct testimony.
How will customers benefit from the repair and replacement capital
expenditures contemplated in this case?
These capital expenditues enable the Company to maintain safe, reliable, and
cost-effective operation of an agig generation fleet. The Company's plants
produce energy at costs lower than market prices, enabling the Company to serve
its customers at some of the lowest retail electrcity prices in the United States.
Prudent investment in the Company's existing generating units increases the
probabilty of continued safe and reliable operation of these low-cost resources.
Please describe the Wyodak air cooled condenser replacement project.
The Wyodak air cooled condenser ("ACC") has been in service for 33 years and
has reached its end of useful life. This replacement project replaces all of the
ACC's tube bundles and headers, both of which are experiencing failures. Failed
tubes and welds are allowing air in-leakage to the ACC which increases tubine
backpressure, allows for accelerated corrosion of the carbon steel tubes and
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headers in the ACC, and results in freeze/thaw damage during cold weather
operation. The new project was placed in service in May 2011. The PacifiCorp
share of the capital investment for the scrubber project being placed in service
during the test period is approximately $22 millon.
How will customers benefit from the Wyodak air cooled condenser
replacement project?
The Wyodak air cooled condenser replacement project is expected to result in
improved unit reliability and effciency. From a unit reliabilty perspective,
continued operation of the ACC in its curent condition has a high potential of
causing progressively more unit outages and/or derates. From a unit efficiency
perspective, durng the winter months it is tyical for the Wyodak plant to
increase tubine back pressure to ensure that the ACC does not freeze. Durng the
summer months, poor ACC performance also causes the plant to ru with high
tubine back pressure. Increasing unit back pressure leads to increased fuel
consumption for a given megawatt output. By proceeding with the ACC
replacement project, customers wil benefit from improvements in the areas
discussed above as well as advancements in curently available ACC technology.
Technology improvements have resulted in increased equipment efficiency
without increasing the size of the ACC strctue. This effciency improvement
comes without increasing the power consumption of the existing cooling fans.
Please describe the Hayden power plant coal unloading facilty project.
Curently, the Hayden plant can only receive coal which is shipped by trck. The
new coal unloading facilty will allow the Hayden plant to also receive coal that is
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shipped by raiL. The project includes construction of a new rail spur and loop,
bridges, unloading hopper, belts, transfer points, feeders, crushers and other
equipment. The project is expected to be ready for service in October 2011, at a
total loaded cost of approximately $12 milion (Company's share).
How wil customers benefit from the Hayden power plant coal unloading
capital expenditure?
Hayden Units 1 and 2 curently consume coal produced at Peabody Energy's
Twentyile mine. This coal is transported to the plant by trck over county roads.
The curent contract with Peabody to supply coal for Hayden expires at the end of
2011. In order to ensure a reliable, long-term supply oflow-cost fuel to the plant
after expiration of the Peabody contract, Hayden's owners (Public Service
Company of Colorado, Salt River Project Agricultural Improvement and Power
District, and PacifiCorp) requested bids from a number of regional mines that
have capability to supply suitable coal to Hayden. Many of these regional mines
are located too far from the Hayden plant to economically deliver coal to the
facilty by trck. Constrction of the rail unloading facilty allows these suppliers
to ship coal to the plant at economic rates and to compete effectively with nearby
suppliers. Ratepayers wil benefit from the increased competition to supply cost-
19 effective fuel to the plant.
20 Description of Hydro Investments
21 Q.
22 A.
What hydro plant capital investments are included in this application?
The hydro plant regulatory and new infrastructue investments contemplated in
23 this case are primarily associated with new license implementation measures for
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the North Umpqua Hydroelectric Project; Federal Energy Regulatory Commission
No. 1927; and dam remediation work at the Ashton Hydroelectrc Project; Federal
Energy Regulatory Commission No. 2381. The revenue requirement impact of
these investments has been included in Mr. McDougal's direct testimony.
Please describe the Lemolo Unit 2 reroute project.
The Company's investment in the Lemolo Unit 2 reroute project is drven by
Settlement Agreement Section 6.1 of the referenced FERC license. These new
reach pipe facilities wil collect the outflow from the Lemolo 2 plant and transport
the water to Toketee Lake. The purose of the project is to prevent significant
increases and decreases in the flow levels in the Umpqua River downstream of the
plant which could have detrimental impacts on the native fishery. The project is
planed to be placed into service in December 2011 and is expected to cost
approximately $9 milion.
Please describe the Slide Creek tailrace barrier project.
The Company's investment in the Slide Creek tailrace barier project is drven by
Settlement Agreement Section 4.1.1(f) of the referencedFERC license. These
new facilities wil reduce water tubulence and prevent access to the Slide Creek
plant in order to prevent delay or injur to anadromous fish during their migration
up the North Umpqua River. The project is planned to be placed into service in
December 2011 and is expected to cost approximately $9 millon.
Please describe the Ashton Dam seepage control project.
The Company's investment in the Ashton Dam seepage control project was
drven by the need to remediate the dam embankent with a state of the art
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engineered filL. The project being considered by this proceeding consists of the
low level flow bypass tuel installation, which wil allow for the removal and
reconstrction of the dam embanent. It is a non-elective, regulatory and
mandated project under the jursdiction of the Federal Energy Regulatory
Commission and a Board of Consultants. The bypass tuel was placed into
service in March 2011 at a cost of approximately $8 millon.
What is the basis for justification of these investments?
The Soda Springs hydroelectrc project with a nameplate rating of 11 megawatts
and the Lemolo 2 hydroelectric project with a nameplate rating of 33 megawatts
are part of the eight project development comprising the North Umpqua
Hydroelectrc Project. The economic evaluation for the entire development was
conducted in association with the FERC re-licensing process prior to the issuance
of the curent 2003 license. The analysis indicated that the 35-year license would
provide energy for customers at rates substantially lower than market prices. The
Ashton Dam seepage control project was determined to be the least cost dam
remediation or dam removal alternative that would meet the approval of the
17 FERC and the project Board of Consultants.
18 Customer Benefits
19 Q.
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How will customers benefit from these capital expenditures?
The capital expenditues described above and otherwise included in this case
enable the Company to maintain safe, reliable, and cost-effective operation of an
aging generation fleet. The Company's plants produce energy at costs lower than
market prices, enabling the Company to serve its customers at some of the lowest
Teply, Di - Page 34
Rocky Mountain Power
1 retail electrcity prices in the United States. Prudent investment in the Company's
2 existig generating units. increases the probability of continued safe and reliable
3 operation ofthese low-cost resources.
4 Description of Incremental O&M Costs
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Are there incremental O&M costs contemplated in this case associated with
recently completed wind projects?
Yes. Incremental O&M costs for the Company's recently completed Dunlap I
wind project are included in this case. The Dunlap I wind project achieved
commercial operation on October 1,2010. The incremental O&M costs included
in this case are known and measurable costs associated with ongoing operation of
the facilities, including labor, contracts, parts, and consumables. These costs are
summarized in Mr. McDougal's direct testimony.
Are there incremental O&M costs contemplated in this case associated with
operation of the Cholla Unit 4 power plant?
Yes. The mine which historically supplied cost-effective coal to Cholla Unit 4
was completely mined out in 2010. While also cost-effective, the new fuel being
supplied to the facility contains more sulfu and ash. In order to continue to
comply with environmental requirements while buming the new fuel, a new
scrubber and bag house were installed on the unit in 2008. The new high-
removal-rate scrubber and the higher sulfu coal have combined to raise limestone
consumption significantly. Also, the new fuel has raised costs for pulverizer and
boiler maintenance in the plant. Even with these changes, Cholla Unit 4 continues
to provide essential energy and system regulation benefits to PacifiCorp's electrc
Teply, Di - Page 35
Rocky Mountain Power
1 system at an attactive price. Incremental operation and maintenance costs of
2 approximately $1.2 milion associated with the operational changes described
3 above are included in this case. These costs are sumarized in Mr. McDougal's
4 direct testimony.
5 Conclusion
6 Q.Please summarize your testimony.
7 A.The pollution control equipment investments presented in this case are required to
8 comply with curent, proposed, and probable environmental regulations. The
9 investments allow for the continued operation of low-cost coal-fired generation
10 facilities, while achieving significant environmental improvements.
11 The Company is also making other prudent capital expenditues in its
12 existing generation fleet, including hydro resources, which will benefit customers
13 by maintaining safe, reliable, effcient, cost-effective generating resources and
14 production facilities. The capital investments included in this case are reasonable
15 and prudent, and the Company should be granted full cost recovery for these
16 investments.
17 The Company continues to prudently manage O&M costs. The Company
18 should be granted full recovery of the incremental O&M costs presented in this
19 case.
20 Q.Does this conclude your direct testimony?
21 A.Yes.
Teply, Di - Page 36
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2U1H1AY 27 AM II: 04
CONFIDENTIAL
Case No. PAC-E-l1-12
Exhibit No. 22
Witness: Chad A. Teply
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Chad A. Teply
2009 Embedded Generation Bus Bar Costs
May 2011
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER
28ll MAY 27 AM It: 04 CONFIDENTIAL
Case No. PAC-E-11-12
Exhibit No. 23
('''1i't Witness: Chad A. Teply
BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION
ROCKY MOUNTAIN POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Chad A. Teply
Comparison Bus Bar Costs with Pollution Control
May 2011
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER
\ FI1
201 U1AY 27 AM It: 04 CONFIDENTIAL
Case No. PAC-E-11-12
Exhibit No. 24
Witness: Chad A. Teply
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Chad A. Teply
2008-2009 Comprehensive Air Initiative - PVRR Study
May 2011
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER
REv::.
CONFIDENTIAL
Lili ~1AY 27 AMIl: ottase No. PAC-E-11-12
Exhibit No. 25
i't3S¡OWitness: Chad A. Teply
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Chad A. Teply
2011 Comprehensive Air Initiative - PVRR Study
May 2011
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARA TECOVER
-1\lED
20nMAY27 AMll=Or.CONFIDENTIAL
Case No. PAC-E-11-12
Exhibit No. 26
Witness: Chad A. Teply
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Chad A. Teply
2011 Coal to Natual Gas Conversion PVRR
May 2011
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER
lOI i .rtA Y 27 AM II: 04 CONFIDENTIA
Case No. PAC-E-11-12
Exhibit No. 27
Witness: Chad A. Teply
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Chad A. Teply
NOx, S02, PM Cost per Ton Removed
May 2011
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER
2011 HAY 27 AM II: 04 Case No. PAC-E-11-12
Exhibit No. 28
Witness: Chad A. Teply
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
Exhibit Accompanying Direct Testimony of Chad A. Teply
Requirements Matrx
May 2011
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Exhibit No. 28 Page 1 of 1
Case No. PAC-E-11-12
Witness: Chad A. Teply
EIVEO
2011 HAY 27 AM HtÇ~ No. PAC-E-11-12
"Exhibit No. 29
¡,.n':;Witiêss: Chad A. Teply
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Chad A. Teply
PacifiCorp's Emission Reduction Plan
May 2011
November 2, 2010
Rocky Mountain Power
Exhibit No. 29 Page 1 of 10
Case No. PAG-E-11-12
Witness: Chad A. Teply
Exhibit A
PacifiCorp's Emissions Reductions Plan
In connection with its Best Available Retrofit Technology ("BART") determinations and its
other regional haze planing activities, the Wyoming Deparent of Environmental Quality, Air
Quality Division ("AQD") asked PacifiCorp to provide additional information about its overall
emission reduction plans through 2023. The purose is to more fully address the costs of
compliance on both a unit and system-wide basis. PacifiCorp is committed to reduce emissions
in a reasonable, systematic, economically sustainable and environmentally sound manner while
meeting applicable legal requirements. These legal requirements include complying with the
regional haze rules which encompass a national goal to achieve natual visibility conditions in
Class 1 areas by 2064
Summary
PacifiCorp owns and operates 19 coal-fueled generating units in Utah and Wyoming, and owns
100% of Cholla Unit 4, which is a coal-fueled generating unit located in Arona. PacifiCorp is
in the process of implementing an emission reduction program that has reduced, and will
continue to significantly reduce emissions at its existing coal-fueled generation units over the
next several years. From 200S through 2010 PacifiCorp has spent more than $1.2 bilion in
capital dollars. It is anticipated that the total costs for all projects that have been committed to
will exceed $2.7 bilion by the end of 2022. The total costs (which include capital, O&M and
other costs) that wil have been incured by customers to pay for these pollution control projects
durng the period 200S through 2023, are expected to exceed $4.2 bilion, and by 2023 the
annual costs to customers for these projects wil have reached $360 milion per year.
Environmental benefits, including visibilty improvements wil flow from these planned
emission reductions. PacifiCorp believes that the emission reduction projects and their timing
appropriately balance the need for emission reductions over time with the cost and other
concerns of our customers, our state utilty regulatory commissions, and other stakeholders.
PacifiCorp believes this plan is complementa to and consistent with the state's BART and
regional haze planing requirements, and that it is a reasonable approach to achieving emission
reductions in Wyoming and other states.
PacifiCorp's Long-Term Emission Reduction Commitment
Table 1 below identifies the emission reduction projects and related constrction schedules as
curently included in PacifiCorp's reduction plan.
Exhibit A - PacifiCorp's Emissions Reduction Plan
November 2,2010
Page 2 of 10
Rocky Mountain Power
Exhibit No. 29 Page 2 of 10
Case No. PAC-E-11-12
Witness: Chad A. Teply
Table 1: Long-Term Reduction Plan
Status of S02
S02 Scrubbers LowNOx /LNB/Selective
Installation - I Burer Baghouse Baghouse Catalytic
Plant Name Upgrades - U Installations Installations Permtting Reduction
Hunter 1 2014 - U 2014 2014 Permtted
Hunter 2 2011- U 2011 2011 Under
Constrction
Hunter 3 Existing 2008 Existing Completed
Huntigton 1 2010 - U 2010 2010 Under
Constrction
Huntington 2 2007 - I 2007 2007 Completed
Dave Johnston 3 2010 - I 2010 2010 Completed
Dave Johnston 4 2012 - I 2009 2012 Under
Constrction
Jim Brid~er 1 2010 - U 2010 Completed 2022
Jim Bridger 2 2009 - U 2005 Completed 2021
Jim Bridger 3 2011 - U 2007 Permtted 2015
Jim Bridger 4 2008 - U 2008 Completed 2016
Naughton 1 2012 - I 2012 Under
Constrction
Naughton 2 2011 - I 2011 Under
Constrction
Naughton 3 2014 - U 2014 2014 Baghouse 2014Permtted
Wyodak 2011 - U 2011 2011 Under
Constrction
Cholla 4 2008 - U 2008 2008 Completed
The following chars represent the reductions in emissions that wil occur at units owned by
PacifiCorp in Utah, Wyoming and Arzona!. It is significant to note that permitting has been
completed for all but the SCR projects; permitting for the SCR projects wil be completed as
needed in advance of project constrction. The emission estimates shown in these charts have
been calculated using projected unit generation and heat rate data in conjunction with each unit's
permitted emission rate. In those cases were the units do not have emissions controls the
estimates have been based on projections of the futue coal quality. All projections used are from
PacifiCorp's ten-year business plan. Actual futue emissions wil be less than those estimated in
these charts since the units wil operate below their permitted rates.
1 PacifiCorp is also a joint owner of coal-fueled facilities in Colorado and Montaa that are subject to regional haze
planning requirements and for which PacifiCorp wil incur associated costs of emissions controls.
Exhibit A - PacifiCorp's Emissions Reduction Plan
November 2,2010
Page 3 of 10
Rocky Mountain Power
Exhibit No. 29 Page 3 of 10
Case No. PAC-E-11-12
Witness: Chad A. Teply
120,000
112,500
105,000
97,500
90,000
82,500
75,000
'" 67,500=
~ 60,000
-: 52,500
=~ 45,000
37,500
30,000
22,500
15,000
7,500
o
110,000
100,000
90,000
80,000
70,000
..60,000=
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'¡50,000===40.000..
30,000
20,000
10,000
0
2005 - 2009 Actual and 2010- 2023 Projected S02 Emissions
PacifiCorp's Arizona, Utah & Wyoming Coal-Fired Units
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-Tons of NO x Emitted
Exhibit A - PacifiCorp's Emissions Reduction Plan
November 2,2010
Page 4 of 10
Rocky Mountain Power
Exhibit No. 29 Page 4 of 10
Case No. PAC-E-11-12
Witness: Chad A. Teply
Project Installation Schedule
Emission reduction projects of the number and size described above take many years to engineer,
plan and build. When considerig a fleet the size of PacifiCorp's, there is a practical limitation
on available constrction resources and labor. There is also a limit on the number of units that
may be taken out of service at any given time as well as the level of constrction activities that
can be supported by the local infrastructues at and around these facilities. Such limitations
directly impact both the overall timing of these projects as well as their timing in relation to each
other. Additional cost and construction timing limitations include the loss of large generating
resources durng some pars of constrction and the associated impact on the reliability of
PacifiCorp's electrcal system durg these extended outages. In other words, it is not practical,
and it is unduly expensive, to expect to build these emission reduction projects all at once or
even in a compressed time period. The pressure on emission reduction equipment and skilled
labor is likely to be exacerbated by the significant emission reduction requirements necessitated
by the Environmental Protection Agency's Clean Air Transport Rule which requires emission
reductions in 31 Eastern states and the Distrct of Columbia beginning in 2012 and 2014. The
Environmental Protection Agency has indicated that a second Transport Rule is likely to be
issued in 2011, requirig additional reductions in the Eastern U.S. beyond those effective in
2014. The balancing of these concerns is reflected in the timing of PacifiCorp's emission
reduction commitments.
Priority of Emission Reductions
PacifiCorp's initial focus has been on installing controls to reduce S02 emissions which are the
most significant contributors to regional haze in the western US. In addition, PacifiCorp
continues to rely on the rapid installation of low NOx bumers to signficantly reduce NOx
emissions. Also, the installation of five SCRs (or similar NOx-reducing technologies) wil be
completed by 2023 and reduce NOx emissions even fuer. PacifiCorp's commitment also
includes the installation of severalbaghouses to control particulate matter emissions. For those
units which utilze dr scrubbers, baghouses have the added benefit of improving S02 removaL.
Baghouses also significantly reduce mercur emissions.
In addition to reducing emissions at existing facilities, PacifiCorp has avoided increasing
emissions by adding more than 1,400 megawatts of renewable generation between 2006 and
2010. In order to meet growing demand for electricity, PacifiCorp added non-emittng wind
generation to its portfolio at a cost of over $2 bilion and has dismissed fuher consideration of a
new coal-fueled unit.
Emission Reductions and BART Deadlines
As depicted in the table and charts above, PacifiCorp began implementing its emission reduction
commitments in 200S. This was well ahead of the emission reduction tielines under the
regional haze rules which require BART to be installed no later than five years following
approval of the applicable Regional Haze SIP. This also provides a graphic demonstration of the
constrction schedule and other limitations described above, as PacifiCorp was required to begin
installing emission control projects at some units earlier in order to complete projects at other
Exhibit A - PacifiCorp's Emissions Reduction Plan
November 2, 2010
Page 5 of 10
units wìthin the five years after SIP approvaL. The table above demonstrates that most of the
projects to be built between 2010 and 2014, likewise, wil be installed in advance of the required
completion date under BART requirements.
Rocky Mountain Power
Exhibit No. 29 Page 5 of 10
Case No. PAC-E-11-12
Witness: Chad A. Teply
Customer Impacts
The following charts identify the timing and magnitude of the capital and O&M expenses that
wil be incured due to the projects identified in Table 1. The charts identify:
1. The timing and magnitude of the capital costs.
2. The O&M expenses that wil be incured due to these projects.
3. The expected annual costs2 through 2023 that customers wil be incur as a result of these
specific pollution control projects.
Capital Expenditures to Add Pollution Control Equipment onPacifCorp's
Arona, Utah & Wyoming Coal-Fired Units
$600,000
$500,000
sg $400,000
¿
~
i: $300,000
$200,000
$100,000
$0
10 r-oo 0\0 -N l"::on ~r-oo 0\0 Ñ N l"0 0 0 0 õ ---N N N00000000000000000NNNNNNNNNNNNNNNNNN
Year
.Capital Expenditues
2 PacifiCorp has made every attempt to provide an accurate estimate of the anticipated increase in anual revenue
requirements that wil ultimately be trnslated to increases in customers' electrcity rates. However, there are several
variables such as interest rates, inflation rates, discount rates, depreciation lives, and final constrction costs and
operating and maintenance expenses that wil be considered at the time these projects actully go into rate base and
wil influence the actual revenue requirements associated with these capital projects.
Exhibit A - PacifiCorp's Emissions Reduction Plan
November 2,2010
Page 6 of 10
Rocky Mountain Power
Exhibit No. 29 Page 6 of 10
Case No. PAC-E-11-12
Witness: Chad A. Teply
$60,000
$50,000
S $40,000..=;e
~
:§$30,000ClQ..===$20,000..
$10,000
$0
$400,000
$350,000
$300,000
S..=;$250,000e
~
~$200,000Q..=$150,000==..
$100,000
$50,000
$0
Increases In O&M Expenses Due to Additional Pollution Control Equipment
on Arona, Utah & Wyoming Coal-Fired Units
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Year
-Annual O&M Expenses
Annual Increase to Customers Due to Additional Pollution Control
Equipment on Arizona, Utah & Wyoming Coal-Fired Units
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Year
I -Annual Revenue Requiren I
Exhibit A - PacifiCorp's Emissions Reduction Plan
November 2,2010
Page 7 of 10
Rocky Mountain Power
Exhibit No. 29 Page 7 of 10
Case No. PAC-E-11-12
Witness: Chad A. Teply
As can be seen from the previous charts, the rate increases for PacifiCorp customers associated
with PacifiCorp's emission reduction strategy alone wil be significant. In the event that
PacifiCorp is required to accelerate or add to the planned emission reduction projects, the cost
impacts to our customers can be expected to increase incrementally, paricularly as plant outage
schedules are extended and the need for skiled labor and material increases in the near term.
Of paricular note, the projected costs reflect only the installation of the noted emission reduction
equipment. These cost increases do not include other costs expected to be incured in the futue
to meet further emission reduction measures or address other environmental initiatives, including
but not limited to (see Attachment 1):
1. Implementation of Utah's Long Term Strategy for meeting regional haze requiements
during the 2018-2023 time period.
2. The addition of mercur control equipment under the requirements of the upcoming
mercur MACT provisions. PacifiCorp estimates that $68 milion in capital wil be
incured by 2015 and annual operating expenses wil increase by $21milion per year to
comply with mercur reduction requirements. In addition, anticipated regulation to
address non-mercur hazardous air pollutant (HAPs) emissions may require significant
additional reductions of S02, as a precursor to sulfuic acid mist, from non-BART units
that currently do not have specific controls to reduce S02 emissions.
3. Mitigating and controlling C02 emissions. While Congress has not yet passed
comprehensive climate change legislation, in December 2009, the Administrator of the
Environmental Protection Agency made a finding that greenhouse gases in the
atmosphere threaten the public health and welfare of curent and futue generations.
Having made the so-called "endangerment fiding," EPA issued the final greenhouse gas
tailorig rule, effective January 2, 2011, which wil require greenhouse gas emissions to
be addressed under PSD and Title V permits3. Likewise, mandatory reporting of
greenhouse gas emissions to the Environmental Protection Agency commenced
begiing in January 2010.
4. In addition, there are a number of regional regulatory initiatives, including the Western
Climate Initiative that may ultimately impact PacifiCorp's coal-fueled facilties.
PacifiCorp's generating units are utilzed to serve customers in six states - Wyoming,
Idaho, Utah, Washington, Oregon and California. California, Washington and Oregon are
participants in the Western Climate Initiative, a comprehensive regional effort to reduce
greenhouse gas emissions by 15% below 2005 levels by 2020 through a cap-and-trade
program that includes the electricity sector; each state has implemented state-level
emissions reduction goals. California, Washington and Oregon have also adopted
greenhouse gas emissions performance standards for base load electrcal generatig
resources under which emissions must not exceed 1,100 pounds of C02 per megawatt
3 The Environmental Protection Agency has not yet published its proposed guidance on what constitutes Best
Available Control Technology for greenhouses gases.
Exhibit A - PacifiCorp's Emissions Reduction Plan
November 2,2010
Page 8 of 10
hour. The emissions performance standards generally prohibit electrc utilties from
entering into long-term fmancial commitments (e.g., new ownership investments,
upgrades, or new or renewed contracts with a term of 5 or more years) unless the base
load generation supplied under long-term financial commitments comply with the
greenhouse gas emissions performance standards. While these requirements have not
been implemented in Wyoming, due to the treatment of PacifiCorp's generation on a
system-wide basis (i.e., electrcity generated in Wyoming may be deemed to be
consumed in California based on a multi-state protocol), PacifiCorp's faciliies may be
subject to out-of-state requirements.
Rocky Mountain Power
Exhibit No. 29 Page 8 of 10
Case No. PAC-E-11-12
Witness: Chad A. Teply
5. Regulations associated with coal combustion byproducts. In June 2010, the
Environmental Protection Agency published a proposal to regulate the disposal of coal
combustion byproducts under the Resource Conservation and Recovery Act's Subtitle C
or D. Under either regulatory scenario, regulated entities, including PacifiCorp, would be
required, at a minimum; to retrofit/upgrade or discontinue utilization of existing surface
impoundments within five years after the Environmental Protection Agency issues a fmal
rule and state adoption of the appropriate controlling regulations. It is anticipated that the
requirements under the fmal rule wil impose significant costs on PacifiCorp's coal-
fueled facilities within the next eight to ten years.
6. The installation of significant amounts of new generation, including gas-fueled
generation and renewable resources.
7. The addition of major transmission lines to support the renewable resources and other
added generation.
8. Increasing escalation rates on fuel costs and other commodities
BART and Regional Haze Compliance
PacifiCorp firmly believes that the commitments described above meet the letter and intent of the
regional haze rules, including the guidance provided by the EPA known as "Appendix y''' The
regional haze program is a long-term effort with long-term goals ending in 2064. It must be
approached from that perspective. It was never intended to require SCR on BART-eligible units
within the first five years of the program. Rather, it calls for a transition to lower emissions
exactly as PacifiCorp has implemented to date and as it has proposed going forward though
2023.
In its evaluation of emission reductions for regional haze puroses, the state should also consider
several other variables which wil significantly affect emissions and costs over the next ten years.
These include such things as the development of new emission control technology, anticipated
new emission reduction legislation and rules, the new ozone standad, the one hour S02 and N02
standards, the PM2.5 stadard, potential C02 regulation and costs, an aging fleet, and changing
economic conditions. All of these variables matter and wil affect the long-term viability of each
PacifiCorp coal unit and wil contrbute to the reduction of regional haze in the course of the
Exhibit A - PacifiCorp's Emissions Reduction Plan
November 2,2010
Page 9 of 10
implementation of these programs. This, in tu, wil affect the
operational expectations associated with these generating resources.
Rocky Mountain Power
Exhibit No. 29 Page 9 of 10
Case No. PAC-E-11-12
Witness: Chad A. Teply
controls, costs and futue
Conclusion
PacifiCorp has made a significant, long-term commitment to reducing emissions from its coal-
fueled facilities and requests that the AQD consider this commitment as a reasonable approach to
achieving emission reductions in Wyoming.
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