20131011Direct & Exhibits M. Louis.pdf

BEFORE THE
:'" - : ii , ""''1+
IDAHO PUBLIC UTILITIES COMMTSSION
rN THE MATTER OF IDAHO POWER )
coMPANY',S APPL|CATTON FOR A ) CASE NO. rpC-E-{3-16
GERTTFTCATE OF PUBLTC CONVENTENCE )
AND NECESSITY FOR THE INVESTMENT )
lN SELECTTVE CATALYTIC REDUCTTON )
CoNTROLS ON JrM BRTDGER UNrrS 3 )
AND 4.)
)
)
)
NON.PROPRIETARY DIRECT TESTIMONY AND EXHIBITS
OF MIKE LOUIS
IDAHO PUBLIC UTILITIES COMMISSION
ocToBER 11 ,2013
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O. Please state your name and business address for
the record.
A. My name is Mlke Louis. My business address is
472 West Washington Street, Boise, Idaho.
O. By whom are you employed and in what capacity?
A. I am employed by the Idaho Public Ut.ilities
Commission as a UtiliE,ies Analyst.
O. What is your educational and professional
background?
A. I recej-ved my Bachelor and Master of Science
degrees in rndustrial Engineering with concentrations in
manufacturing systems and engineering economics from Purdue
University ln 1985 and 1,992, respectively. I also received
my Masters in Public Policy and Administration at Boise
St,ate University in 2005. In addition to my formal
education, I have attended Michigan SEate University
Institute of Public Utilities Annual Regulatory Studies
Program, NARUC Utility Rate School, Electricity Grid
School, and Advanced Regulatory Studies Program.
My work experience includes L8 years of
industrial/commercj-aI practj-ce developing and managing
manufacturing systems and operatj-ons, planning processes,
and supply chaJ-ns for General Motors, Hewlett-Packard,
,Jabi1 Circuit, and Albertsons Companies. I also have spent
sj-x years administratJ-ng and conducting energy policy
CASE NO. IPC-E-13-]-5
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research with the Energy Policy Institute at Boise State
University. As part of my manufacturing and academia
experience is the management of departmental budgets as a
mid-Ieve1 manager and project budgets as a manager of
several large strategically-oriented projects. I have also
taught classes in program and project management in the
Department of Public Policy and AdminisEration at Boise
State University.
At the Idaho Public Utilities Commission, my work
responsibilities have included a variety of electric and
natural gas cases including integrated resource p1ans,
purchased gas and power cost adjustment cases, prudence
reviews of power plant investments, and several general
rate cases looking specifically at emission control
investments.
O. What is the purpose of your testimony in this
proceeding?
A. The purpose of my testimony is to describe
Staff's analysis as to the prudence of the Company's
proposed investment in selective catalytic reduction (SCR)
controls on Jim Bridger Units 3 and 4. In addition, I
provide recommendations related to the issuance of a
Certificate of Public Convenience and Necessity (CPCN) and
propose ratemaking treatment.
O. Please summarize your testimony in this case.
cAsE NO. rPC-E-13-l-5
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A. I believe the Company's decision to move forward
with the emission control investment project for ,Jj-m
Bridger Units 3 and 4 is prudent; supporting authorizatj-on
of a CPCN issued under Idaho Code 56l--526. However, f only
recommend authorization of $81,378,000 in direct project
costs of the $117,947,962 requested in the Company's
Applicat,ion based on provisions for binding ratemaking
Ereatment under ldaho Code S5l--541. I have also made
several recommendations related to the handling of
variances between the Commitment Esti-mate and actual costs.
O. What documents did you analyze that lead to your
recommendation?
A. I examined the following documents:
l-. The Company's Application, direct Eestimony
of Company witnesses, and accompanying
exhibits;
2. Idaho Power's 20L3 fntegrated Resource Plan;
3. Discovery by Staff and intervening parties
including but, not limited to the Company's most
recent business pIan, Engineering, Procurement,
and Const.ruction (EPC) contractor evaluation
documents, EPC Contract, and the Jim Bridger
operations contract between Idaho Power Company
and PacifiCorp;
4. PacifiCorp's CPCN cases in Wyoming and Utah
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includj,ng the Application, testimony,
discovery requests, and orders;
5. Idaho's CPCN statutes including ldaho Code
$st-s+t, and $$or -526 through 6L-530,.
5. Environmental Protection Agency's (EPA)
proposed rule on the Wyoming SIP cont,ained in the
Federal Regist,er (VoI . '7I , No . 1Ll-, ,.Tune 10 ) .
O. How will your Eestimony be organized?
A. My testimony can be broken down to an analysis of
two objectives related to concepts of prudency: L) whether
or not it is prudent to recommend issuance of a CPCN
pursuant to ldaho Code $ef-sZe and 2) whether and to what
extent the Company's proposed budget should be pre-approved
for binding ratemaking treatment pursuant to ldaho Code
Ser-sar.
I begin by considering quest,ions related to
whether or not a CPCN should be issued. f consider if the
Company's decision to invest in emission controls is
necessary and whether the project is least cost and least
risk for customers over the long-term when compared to
other alternatives given information known at this time.
The second objective considers factors that
ensure the projecE is constructed and deployed in a cost
ef fectj-ve manner. FirsE, under ldaho Code 55l--541
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(2) (b) (iii), I analyze whether any or all of the Company's
proposed budget for the SCR investments should be pre-
approved by the Commission. Second, under ldaho Code
551-s4L (2) (b) (iv) ,
project variances.
Table of Contents
recommend an approach for handling
table of contents is provided be1ow.
Page No.
I
A
Prudence of Proposed Investment
Drivers for Investment
Sufficiency of Company Analysis
Prudence of the Project Budget
Maximum Pre-approved Amount
page 5
page 5
page 6
page 20
page 20
page 32
LOUTS, M. (Di)
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Method of Handling Project Variances page 29
Summary and Recommendatj-ons
Prudence of Proposed fnvestment
Drivers for Investment
CASE NO. IPC-E-]-3.16
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O. Please describe the primary drivers for the need
to invest in SCR emission controls for Jim BrJ-dger
generating Units 3 and 4.
A. In complj-ance with Clean Air Act Regj-onal Haze
(RH) ru1es, The Wyoming Department of Environmental Quality
(WDEQ) through its stat,e Implementation Plan (sIP) requires
the Company to install SCR emj-ssion controls by December
20L5 on Jim Bridger Unit 3 and by December 2015 on Unit 4
Eo limit Nitrogen Oxide (Nox) emiss j-ons to 0.07 Ibs/MMBtu
(on a 30-day rolling average) . Because the SIP is
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enforceable by the State of Wyoming, the Company must
discontinue operation or install Lhe necessary cont.rols by
the dates stipulated in the SIP to conEinue operation.
The Company relies on 1-74 MW and 177 MW of net
dependable baseload capacity from Unj-ts 3 and 4,
respecEively. This represents approximately 10? of Idaho
Power's total system generation capacity and approximately
19* of the Company's baseload capacity. The Company would
need to maintain at least, an equivalent amount of baseload
capacity to continue to reliably and economlcally meet
customer's electriclty needs. Therefore, permanently
halting operat.ion of Bridger Units 3 and 4 without
replacing its generation capacity is not an option.
Sufficj-ency of Company Analysis
O. Please provide a brief description of the
Company's analysis.
A. The Company's analysis consisted of two separate
types of studies: (1) a static unit by unit analysis
performed by an outside consultant, and (2) a system
analysis using fixed cost assumptions from the static
analysis combined with variable costs derived from the
Company' s AURORA mode1.
For bot.h studies, net present value (NPV) cost
comparisons were made using alternatives to investing in
SCR conErols. Nine different combinations of natural gas
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and carbon price forecasts were examined. The NPV costs
were calculated across a twenty-year tj-me period from the
year 2OL3 through 2032.
The static analysis looked at each Jim Bridger
unj-t, individually. This analysis provides a cosE
comparison for each alternative resource as if it is
dispatched in exactly the same way as the Jim Bridger unit
it is assumed to replace. Although this analysis
illustrates the operating characteristic differences
between the different alternatives, its value j-s limited
because the calculated NPV cosEs are not representative of
how the alternative would be realistically dispatched
within the Company's overall system.
By contrast, the system analysis dispatches each
generation resource based on j-ts own costs and operating
charact.erj,stics. For example, gas generatj-on alternatives
are dispatched according to their respective fuel costs and
heat rates, instead of being dispatched like the coal units
they are intended to replace. Because of these reasons,
the Company's system analysis more realist,ically reflects
how each alternative might actually operate in the
Company's system. This provides more realj-stj-c NPV
comparisons when testing sensitivity to natural gas and
carbon prices.
A. What alternat j-ves to the "Upgrade" proposal,
cAsE NO. rPC-E-l_3-16
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investing in SCR controls for ,Jim Bridger Units 3 and 4 on
the SIP compliance deadlines, did the Company choose to
compare?
A. Idaho Power analyzed and compared the followlng
four different alternatives to the "Upgrade" proposal:
1. Natural Gas Conversion - Each Jim Bridger
unit is converted to natural gas fuel by the SIP
compliance deadlines.
2. Retire and Replace Each .fim Bridger
unit is ret,j-red and replaced by an equal-sj-zed
combined cycle combustion Eurbine (CCCT) gas
plant with operating characteristics similar to
the Langley Gulch CCCT plant by the SfP
compliance deadlines.
3. CTA Natural Gas Conversion - This is a
compliance timing alternative (CTA) that is
identical to the "natural gas converslon"
alternative described in number l- above,
except it is assumed the SIP compliance deadline
can be delayed by five years.
4. CTA Retire and Replace - This is a
compliance timing alternative (CTA) that
is identical to the "retire and replace"
alternative described in No. 2 above, except it
is assumed the SIP compliance deadline can be
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delayed by five years.
O. Were the number and type of resource alternatives
reasonable for comparison purposes?
A. I believe so. Based on Idaho Power's analysis
methodoloSy, f believe the goal was more Eo confirm the
i-nstallatlon of emission controls as the most economi-caI
solution given current and future circumstances rather than
to identify the one best sol-ution using a clean sheet
approach. By using an incremental approach, the Company
was able to use a minimal set of highly feasible
alternatives to get an indication it was choosing the best
course of action. The strength of that indication, which
in this case is the magnitude of difference in NPV between
each alternative and the "Upgrade" proposal, told the
Company if it was making the best decision or if a more
detailed and rigorous analysis was warranted.
a. How did you assess if the alternatives used were
feasible and suiEable for comparison?
A. I identified four factors that are important to
test feasibility. To be feasible, the alternative needed
to meet all four criteria. First, all the alternatives
needed to meet the reliability needs of Idaho customers.
As explained previously, Jim Bridger Units 3 and 4 provide
approximately l-9? of the Company's baseload generatlon
capacity. In addition, Idaho Power already has a large
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amount of seasonal or intermittent hydropower and wind
resources. Alternative resources considered as part of the
analysis must be dispatchable and reliable year round.
Second, the alternatives needed to have a cost
that can reasonably compete with an SCR equipped Bridger
unit to minimize rate J-mpact to ldaho customers. The Jim
Bridger facility currently has the lowest dispatch cost of
all of the Company's generation resources. The types of
alternatives that can compete economically while meeting
all the other criteria is realistically very limited, even
with the addj-t,ionaI cost of SCR controls and potential
future environmental compliance costs.
Third, the alternatives needed to meet or surpass
all currenL and potential environmental regulations
relevant to each alternatj-ve, including regulations under
consideration for the Jim Bridger unlts.
Fina11y, all alternatj,ves for comparison needed
to be constructed and operational by the SIP compliance
deadline.
O. Do you believe the compliance timing alternatives
considered by Idaho Power were realistic?
A. At one time there may have been an opportunity to
negotiate a delay in the Regional Haze compliance dates in
exchange for shutting down one or both units and replacing
them with an alternative resource. However, I believe the
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opportunity for delay no longer exists.
O. Why do you believe the opportunity to delay
compliance no longer exists?
A. There are several reasons. First, the Wyoming
SIP carries the force of 1aw in the State of Wyoming until
such time as the EPA approves it or replaces it with a
Federal Implementation P1an. Second, on May 23, 20r.3, the
EPA created additional certainty by re-proposing rules that
will approve the Wyoming SIP making the SIP requirements
federally enforceable upon final approval. Third,
PacifiCorp, as a majority partner and owner-operator of the
Jim Bridger facility, is moving forward with installing the
controls. It received a CPCN in both Utah and Wyoming on
Nlay 29 , 201-3 and May 10, 201-3, respectJ-ve1y, and signed an
Engineering, ProcuremenE, and Construction (EPC) contract
to install the controls. In reviewing the contractual
obligations between the two companies, I believe it. would
be very difficult for Idaho Power to pursue a different
alternative than what PacifiCorp has already selected
without significant additional cost.
O. What would Idaho Power need to do if it decided
not to parti-cipate in PacifiCorp's installaEion of
environmental controls?
A. I belj-eve the most feasible option would be for
fdaho Power to se11 its share of the facility to PacifiCorp
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or a third party. Although the possibility exists, I
believe there is littIe incentive for PacifiCorp or a third
party to buy out Idaho Power's share ln the time frame
requlred. Moreover, Idaho Power would j-ncur potential
costs associated with stranded assets, the additional cost
of replacing lost .Tim Bridger capacity, and damages owed to
PacifiCorp for breach of contract, (See Company response to
Staff Production Request No. 9 attached as Staff Exhibit
No. 101).
O. Despite your belief t,hat negotiating a delay in
the compliance deadlj-nes in exchange for shutting down
Units 3 and 4 is not realisEic, do you see value in
analyzing the compliance timing alternatives?
A. Yes I do. I believe the CTA analysis
demonst.rates how much more cost. effective Idaho Power's
proposal is over the "natural gas conversion" or "retire
and replace" alternatives. With the CTA option, the
"natural gas conversion" and "retj-re and replace"
alternatives a1low operation of Jim Bridger Units 3 and 4
without addltional operational and capital costs of SCR
controls for a period of five years. It also avoids five
years of carrying costs assocj-ated with the capital
required to build a CCCT plant or to convert Jim Bridger
Units 3 and 4 to burn natural gas. Even with these
advantages, the SCR "Upgrade" option was most economical,
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providing further evidence justifying the Company's
proposal.
0. Please describe how fdaho Power evaluated risk
associated with each of the alternatives considered.
A. The Company's analysis focused on two primary
risk factors that would cause significant NPV differences
between each of the alternatives: carbon dioxide (CO2)
price and natural gas price. These factors were chosen
because the alternatives being compared are primarily
fueled by coal or natural gas. The Company calculated nine
NPV results using combinations of three different CO2 and
three different natural gas price forecasts. Comparing the
NPV results across the nine alternative model runs provides
an effective evaluation of risk associated with each
resource alternative.
Overa1l, I believe the factors chosen and the
methodology used t,o evaluat.e risk in the Company's analysis
are reasonable.
O. Do you believe the natural gas and CO2 price
forecasts used are reasonable?
A. I do, with some caveats related to the natural
gas price forecast. First, the natural gas and CO2 price
forecasts were identical t.o the forecasts used to develop
the 20]-3 Integrated Resource Plan (IRP). This means they
were reviewed publically through the IRP Advisory Council
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as part of the IRP development process.
Second, the forecasts were based on data from
reputable third party sources. The CO2 price forecast
utilized data from the "2011" and "20]-2 Carbon Dioxide
Price Forecast" published by Synapse Energy Economics, Inc.
The natural gas forecast was derlved from the "Annual
Energy Outlook, 201-2" published by the US Energy
Information Administratj-on (EIA) .
With respect to CO2, the fdaho Power CO2 price
forecast is somewhat more conservative when compared to the
forecast used by PacifiCorp ln its 20L3 IRP. This favors
the "natural gas conversion" and "retire and replace"
alternatives by phasing in CO2 cost earlier. It also
provides a forecast that is approximately equal to the
PacifiCorp forecast in t.he low and planning CO2 cases and
consistently higher in the high CO2 case over the analysis
time period.
However, I believe the Company's natural gas
forecast may be less conservative by being higher than
other nominal forecasts. This favors investment in SCR
controls over natural gas fueled alternatj-ves. The Company
applied a three percent inflation rate to the EIA forecast
in real 20L0 dollars to get a nominal dollar forecast over
the planning period. When compared to PacifiCorp or EIA's
nominal dolIar forecast, Idaho Power's gas price forecast
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is considerably higher, especially in the out years.
Although I don't believe the Company's method is
necessarily unreasonable, f believe that using EIA's
nominal dollar forecast is more transparent and uses an
inflation rate that is 1ike1y more accurate for natural
gas. For comparison purposes, these forecasts are
illust.rated in Staff Exhibit No. 1-02.
a. How does Idaho Power's comparatively higher
natural gas price forecast affect the analysis?
A. To better understand how the natural gas forecast
affected the analysis, I looked at t,he "tipping point"
analysis provided by the Company in response to Staff
Production Request No . 44. The analysis determined how
much gas prices would need to decrease to make the next
best alternatj-ve more economical than investing in SCR
controls (the ptanning CO2 price forecast was used as the
baseline). The analysis showed that natural gas prl-ces on
average would need to decrease by 52 percent in order to
make the "retire and replace" with a CCCT alternative more
economically favorable. Because this percentage decrease
is larger than the percentage difference between the
Company's gas price forecast and EIA's nominal forecast, I
concluded that the differences in the natural gas prj-ce
forecasts are not substantial enough to change the
Company's final recommendation. Regardless of the forecast
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used, the forecast would have to be considerably Iower.
a. Were there any other important factors to
consider regarding risk?
A. The other important factor is the cost of
compliance for future environmental regulations beyond
Regional Haze. For some of the regulat.ions, there is
considerable uncertainty about, what will be required.
Pot.ential future regulations subject to considerat.ion for
Jim Bridger Units 3 and 4 include: (1) Mercury and Air
Toxic Standards (MATS) Rule, (2) Clean Water Act, SecEion
3L5 (b) , (3) Coal Combustion Residuals (CCR), and (4) future
regulat,ions to limit greenhouse gas emissions.
O. How did Idaho Power account for these potential
compliance costs?
A. With the exception of greenhouse gas regulations,
the Company included incremental capital and operation and
maintenance costs for controls required by each regulation
depending on the type and technology of each alternative
under consideration. Most of the incremental cost
estimates were originally developed by PacifiCorp.
However, the consultant hired by ldaho Power to do the
"static" analysis was tasked to review and validate all of
the capital and variable cost assumptions, including the
cost of replacement capacity and environmental compliance
costs for each alternatj-ve. Given the highly technical
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nature of environmental control technology, I believe this
approach provided reasonable assessment of potential future
envj-ronmental costs and added credibility to the Company's
analysis.
a. How did Idaho Power account for greenhouse gas
regulation compliance costs?
A. EPA Greenhouse gas regulat,J-ons for existing
sources are currently not expected to be finalized until
,June of 20L5. Nevertheless, the Company included a
surrogate CO2 cost adder to the variable cosL of each
alternatj-ve on a dolIar per megawatt-hour basis with the
fuII CO2 cost charged to coal-fueled alternatives and 50?
of the cost charged to natural gas fueled alternatives
because CO2 emissj-ons for natural gas are approximately
half that of coal. As mentioned earlier, the CO2 cost was
included as a sensitivity variable. I believe this is
reasonable treatment for greenhouse gas compliance costs
until a framework for EPA rulemaking is proposed and
finalized.
a. Did higher CO2 prices affect the NPV results?
A. When high CO2 costs were combined with the low
natural gas price forecast in the Company's analysis, the
"retire and replace" was a better alternative economically
than the "upgrade" proposal based on t,he NPV results. To
understand the sensitivity of the analysis on CO2 price
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alone, f requested the Company perform a "tJ-pping poj-nt"
analysis to determine how much CO2 prices would need to
increase to make the next best alternative more economical
than investing in SCR cont.rols using the plannlng natural
gas price forecast case as a baseline. The analysis showed
that CO2 prices on average would need to increase
approximately 423 percent in order to make the "retire and
replace" alternative more economically favorable.
O. Is there anything else you considered in the
Company's analysis leading to its decision to upgrade Jim
Bridger Units 3 and 4?
A. Yes. The EPA has not, yet approved the Wyoming
SIP regarding NOX compliance for Bridger UnJ-ts 3 and 4.
However, after several delays by the EPA, the agency
released a re-proposal to effectively approve SCR
installation on Units 3 and 4 by December 2015 and 201-5,
respect j-veIy, by authorizing an emission limit of 0. 07
lbs/MMBtu. rf the EPA issues a notice of final rulemaking
on November 21, 20L3 as expected with no changes to the re-
proposal, it will effectively make installation of SCR
controls federally enforceable. In the unlikely event that
the EPA decides to change the Wyoming SIP, it would
probably make the requj-rements more stringent.
O. Did the Company consider this contingency?
A. Yes. The Company, through PacifiCorp as the
cAsE NO. rPC-E-13-l-6
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operator of the plant, has signed a Limited Notice to
Proceed (LNTP) contract with an EPC contractor to design
and install the controls. The LNTP alIows the Company
flexibility to make changes to the specifications of the
design and purchased equipment to meet a 0.05 Ibs/MMBtu NOX
limit up to the date the EPA is expected to j-ssue its final
rules.
O. Would the additlonal cost of meeting a more
strj-ngent emission limit change the outcome of the
alternative analysis performed by the Company?
A. f do not believe it wouId. Based on the
Company's response to Staff Production Request No. 5, the
incremental capital cost of meeting a 0.05 Ib/MMBtu NOx
limit is estimated to be less than $1.7 million per unit.
Amortized over the life of the unit and brought back to
present value over the study period, the effect on the NPV
results for the "upgrade" proposal would not make a
material difference.
O. What do you recommend based on your review of the
Company's analysis?
A. Based on t,he overall sufficiency and
reasonableness of the Company's analysis and also based on
the overall magnitude of difference j-n net present value
between each alternative and the "upgrade" proposal for the
different sensj-tivity scenarios, I agree with the Company's
CASE NO. IPC-E-13-].6
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"upgrade" proposal and recommend the Commission issue a
CPCN pursuant Eo ldaho Code 551-525.
Prudence of the Project Budget
Maximum Pre-approved Amount
O. How did you determine your recommended Ieve1 of
project costs eligible for binding ratemaking treatment
pursuant to ldaho Code 551-541?
A. Pursuant ro ldaho code s0r-s+r (2) (b) (iii), the
Commission is to consider "the maximum amount of costs that
the Commission will include i-n rates at the time determined
by the Commission without the public ut,ility having the
burden of moving forward with additional evidence of the
prudence and reasonableness of such cosEs. " Based on this
gui.dance, I believe binding ratemaking treatmenE in this
case should be limited to only those expense categories
that are necessary, and known and measurable with a high
leveI of certainty. I also recommend that each category of
costs should be pre-approved individually rather than on a
total project cost perspective. This prot,ects against
premature approval of budgeted amount,s when actual costs on
an individual category basis could be potentially 1ower.
This approach ensures the Commission's right to review the
prudency of actual cost before they are put into rates.
O. Why should uncertain budgeted amounts for
individual project categories be excluded from pre-
CASE NO. IPC-E-].3-15
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approval?
A. There are two reasons. First, excluding
uncertaj-n amounts incents the Company to continue to find
cost-effective ways of implementing a project once it is
underway. Pre-approval of budgeted amounts that are set
using liberal estimating methods or that include slack from
contingency amounts allow project managers to spend up to
the amount of their authorized budget without regard for
potential savings. Second, excluding uncertain amounts
protects against recovery of a fu1I pre-approved amount if
actual costs are 1ess. Consequently, I recommend that the
Commission conservatively set pre-approved project costs to
assure costs are reasonably incurred in all cost item
categories throughout project development.
O. Will the Company have difficulty financing the
project if the Commission denies pre-approval of costs on a
total project basis?
A. Not necessarily in this case. In response to
Staff's Production Request No. 18, which asks how the
project will be flnanced, the Company said,
Idaho Power expects to finance this projectconsistent with the financing of its totalconstructj-on program. The Company expectsto finance its capital requirements with acombination of internally generated fundsand externally financed capital. Idaho
Power has not entered into any alternatj-vefinancing agreements and t,herefore has not
developed a financing payment schedule based
on non-traditional financing schemes.
CASE NO. IPC-E-13.15
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Because Idaho Power is using a combination of
internally generated funds and capital from its overall
construction program budget. and is not required to secure
financing specifically for this project, the need for
binding ratemaking treatment to secure favorable financing
ls reduced. Moreover, the Company's ability to secure
favorable financing is not a requirement of ldaho Code
s51- s4t.
Therefore, more of Ehe focus should be placed on
assuring that project costs are properly incurred and are
subject to revj-ew when actual costs are known. This means
that uncertain budgeted amounts should not be j-ncluded in
t,he pre-approved tota1.
O. Does Idaho Power's shared ownership of Bridger
with PacifiCorp affect your recommendations in this case?
A. Yes. PacifiCorp, as the operator of the pIant,
has the responsibility to manage the project. However,
Idaho Power stil1 has a responsibility to make sure
PacifiCorp does everything it reasonably can to implement
the project cost-effectively.
a. Is there evidence that the Company has had
difficulty providing managerial oversight of j.ts operating
partner's operating and investment decisions in the past?
A. Yes. For example, in Oregon Case UE 233 (Order
No. 1-3-132), the Oregon Commission disallowed fdaho Power
CASE NO. IPC-E-13-15
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management expenses because the Company was "unaware of the
existence of a key study underlying the decision to upgrade
Bridger 3," in its general rate case.
O. What amount do you recommend for pre-approval in
this case?
A. The only costs I recommend for binding ratemaking
treatment are the amount of the EPC contract and actual
costs already j-ncurred during the development phase. I
have illustrated my recommendations for budget pre-approval
by expense category in Staff Exhibit No. l-03.
O. Please explain how Staff Exhibit No. 103 is
organi-zed relative to your testimony.
A. Staff Exhibit No. 103 illustrates amounts
included and excluded in Staff's proposed Commitment
Estimate by cost item category. Amounts included in
Staff's proposed Commitment Estimate are further broken
down by actual cost shown in Column l- and by estimates from
competitive bids and contracts shown in Column 2 with
Staff's total proposed amounts shown in Column 3. Amounts
excluded from Staff's proposal are shown in Columns 4 and
5. Column 4 shows amounts that require both ful1 prudence
review and cost verification because there are questions
whether the cost item is necessary. Column 5 reflects
amounts for cost item categorJ-es that I believe are
necessary; however, the amounts are uncertain at this time
CASE NO. rPC-E-13-l_5
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requiring future cost verification. Column 5 reflects
Idaho Power's proposed Commitment Estimate contained in the
Company' s Application.
a.Why did you recommend pre-approval of only I
-
in actual costs from the development phase
category?
A. r was able to revie*
-
in actual cost
included in the development phase and determine it was
reasonable and prudent. The certainty of remaining
forecasted costs were harder to ascerLain. Thus, ffiy
recommendation to leave them out of the Commitment Estimate
for future approval.
o.Why do you recommend that the fuII
-
-
cost for the EPC contract be j-ncluded in Staff 's
Proposed Commitment Estimate?
A. The EPC contractor was select,ed through a
reasonable and prudent competitive bidding process. The
process provided certainty that the contract would be
awarded to the lowest cost contractor best able to meet
PacifiCorp's needs. Because a contract was signed, a
framework to ensure performance and cost guarantees was
developed that provides certainty around the Company's
estimate, thereby making it known and measurable.
O. Please generally describe PacifiCorp's
competitive bidding process.
CASE NO. IPC-E-13-].5
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A. Twenty-seven request-for-proposals (RFP) were
distributed. Of the RFP's sent out, only five bids were
returned or were complete. Using criteria developed prior
to the start of the evaluation process, the bids were
evaluated using a cross-functional team including a member
from an outside engineering firm. Negotiations were
conducted with the two finalists with the final selection
going to the lowest cost bidder.
O. Has the Company through its managing partner,
PacifiCorp, signed a limited notice to proceed contract t,o
install SCR controls on ,Jim Bridger Units 3 and 4?
A. Yes. PacifiCorp and, by default due to their
joint-ownership, Idaho Power have slgned a llmited notice
to proceed (LNTP) contract with the EPC Contractor to
design and j-nstalI SCR controls. This aI1ows the EPC
contractor to begin work on the project while delaying the
Company's exposure t.o significant costs up until the FuI1
Notice to Proceed deadline on December 1 , 20:.3.
O. Is there an incremental cost associated with this
type of contract?
A. Yes. There is a premium of approximately I
I for the LNTP contract above the cost of the base
contract according to documents supplied by fdaho Power in
response to Staff Production RequesE Nos. 1 and 40.
O. Is this prudent?
CASE NO. IPC-E-13-16
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A. I beli-eve it is. As described in the first
section of my testimony, uncertainty sti11 exists
surrounding EPA's final approval of the Wyoming SIP which
the EPA indicated would occur on November 2]-, 20]-3.
According to Staff Productj-on Request No. 2 and PacifiCorp
testimony in the Utah CPCN case, delaying the contract past
May 31, 20l-3 would put Regional Haze compliance by the
Wyoming SIP deadlines at risk. Although the EPA did
recommend approval of the Wyoming SIP in its re-proposal
submitted on May 23, 20]-3, because of the number of EPA
delays that have already occurred, uncertainty remains
whether the requirements will change. Signing a LNTP
contract provides a way to alleviate risk of non-compliance
due to tj-me constraints while providing flexibility to
change the design to meet more stringent emission
requirements if the EPA changes them in its final rules.
In response to Staff Production Request No. 57,
the Company justified the cost premium based on increased
equipment and material cost due to delayed purchase orders
and higher labor rates from a compressed construction
schedule. I believe the costs are justified.
O. Please explain why you specifically excluded the
Company's estimate for the Boiler and Pre-heater Economizer
Upgrade in Staff's proposed Commitment. Estimate.
A. I excluded the fuII cost from the
CASE NO.
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Commitment Estimate because it is not known and measurable
at this point in t,ime.The basi-s for the estimate is
partly derived from a non-competitive proposal from a
potential service provider. Without a competitive bidding
process or something equivalent, it j-s dlfflcult to
ascertain whether or not the price is reasonable. In
addition, information in the proposal reflects uncertainty
as to the extent of work that needs to be performed. For
example, there j-s an Electrostatic Precipitator optj-on for
Unit 4, which would cost an additional
-
that
PacifiCorp is not certain is required. The proposal also
indicates there is uncertainty due to E
which has prevented the service
provider from providing a fuII and firm price for
installation. PacifiCorp estimated thls additional cost by
basj-ng it on comparable cosL for a similar installation on
PacifiCorp's Naughton Unit 1. Given the potential cost
difference in estimates for Bridger UniE g
-
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Unit 4
for the same type of work within
the same proposal, I believe estimates for additional work
at a t,ot,a11y different facility to be at least equally
uncertain.
O. Why did you exclude the Company's estimate for
the Low Temperature Economj-zer in Staff's proposed
cAsE NO. rPC-E-13-l-6
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Commitment Estimate?
A. r excluded the fuII
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Commj-tment Estimate because there is a question whether any
investment is necessary at all, requiring a fu11 prudency
review when there is more certainty. The basis for the
estimate is a non-competitive proposal from a potential
service provider. In the proposal, the service provider
recommends five separate options that range in cost from !
only requiring a change in operating procedures to
installing an economizer that could cost, up to
Because of the potential to operate the generatj-ng units
without any investment, in my opinion, a fuII prudence
review is required.
O. Why did you exclude the Company's estimate for
the E cost for the economizer upgrade, the
-
cost for flue gas reinforcement, the I
-
cost for spare parts allowance, t.rd
-
in other cost expense in Staff's Proposed Commj-tment
EstimaLe?
A. Again, none of these costs are known and
measurable at this time. A11 of these costs were estimated
using comparable costs for similar work and expenses at
Naughton Unit 3, and Naughton Units l- and 2. For reasons
stated earlier regarding a lack of a competitive bidding
process or equivalent, and the 1eve1 of difference and
CASE NO. IPC-E- 1-3 - 15
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uniqueness between generation units contributing to a high
level of uncertainty, I believe the amounts should be
reviewed as actual costs when they are known and when the
Company files to have them recovered in rates.
O. Please provj-de a summary of your recommendations
for a pre-approved budget amount.
A. The amounts below summarize the Commitment
Estimate I am recommending the Commission adopt in this
case.
SLaff Commitment Estimate ($000's)
Unit 3
cAsE NO. rPC-E-13-15Lo/tL/1-3
Unit 4 TotaI
Development Phase
EPC Contract
TotaL Direct #39,649 $41-,729 $81,379
Method of Handling Project Variances
A. What are the Commission's responsibilities
regarding project variances?
A. Idaho Code S51-se1 (b) (iv) states that ratemaking
treatments are Eo include "the method of handling any
variances between cost estimates and actual costs. "
O. How do you recommend that. variances between cost
estimates and act.ual cost be handled?
A. I have five recommendations. First, there should
be a mandatory prudence review of actual costs in a
subsequent proceeding before the expenses can be put into
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rates.
Second, in those proceedings, all actual
expenditures should be reviewed against pre-approved
amounts by cost item category. Any actual cost item
category that exceeds the pre-approved budget amount should
be reviewed to ensure any amount above the soft-cap for
each category is reasonable and prudent.. Soft-cap is
defined as the maximum amount the Commission will a11ow
without performing a prudence review of any excess amount
above the cap before being put into rates. This
recommendation is an augmentation of the soft-cap used in
the Langley Gulch CPCN case (IPC-E-09-03), where the soft-
cap was set for the total approved Commitment Estimate.
Unlike Langley Gulch, however, in which the project was
constructed mostly under a single EPC contract, this
project will possibly entail as many as four additional
contracts. Setting a soft-cap for each cost. category will
ensure a higher 1evel of cost control by not allowing slack
in one expense category estimate to serve as a cost
contingency for another category with unrelated expenses.
Third, I recommend that the Commission a11ow
either all or none of the expense in any category to be
approved. ff the Commission only pre-approves a percentage
of each category, it is 1ike1y the Company will exceed the
soft-cap for those categories requiring a fu11 prudence
CASE NO. IPC-E-13-16
1o/11-/1,3
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review of all expenses within that category at the time
they are put into rates.
Fourth, if the Commission does al1ow partial pre-
approval of the Company's estimate of a cost item category,
any amount put into rate base should not exceed the actual
cost of that category. The Company says in its Application
that, "Should the cost of the project be less than the cost
estimate, the savings would directly benefit the customer
through a lower amount in rate base." I agree with the
Company's proposal that any amount put into rate base
should not exceed actual cost. However, I recommend,
consistent with my earlier recommendation, that this apply
to each cost item category in isolation and not for the
total pre-approved amount.
Fifth, the Company should provide to the
Commission quarterly project updates that illustrate plan
vs. actual status of expenditures by cost item category and
for the overall project timeline. This will alert the
Commj-ssion of major difficultj-es, unseen circumstances or
changes in scope throughout, the life of the project. It
will also provide better documentation when reviewing
prudence in a subsequent proceeding. Finally it will
ensure that Idaho Power is actively performing oversight of
a project PacifiCorp is managing.
O. Please discuss any other issues related to
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variances between cost estimates and actual costs.
A. There was difficulty in reviewing actual
development phase expenses. This is due to the way
PacifiCorp invoj-ces Idaho Power for its share of the
expenses. The line items on the invoice show a breakdown
based on t.he amount of labor, material, travel, etc., which
can cut across multiple contracts, work breakdown structure
elements, and commitment cost item categories, effectively
removing the abilit,y to trace the activity causing the
cost. I recommend that the Company develop a method with
its partner, PacifiCorp, to ensure the ability to track
expenditures by commitment cost category and work breakdown
structure element to enable review in future proceedings.
Summary and RecommendationE
O. Please summarize Staff's position
recommendations regarding Idaho Power's CPCN
A. I believe the Company's decision to
with the emission control investment project
Bridger Units 3 and 4 is prudent, supporting
Application.
move forward
for Jim
authorization
of a CPCN under ldaho Code 551-525.
Regarding binding ratemaking treatment under
Idaho Code $6t-S+t, I recommend that the Commj-ssion pre-
approve by cost item category in the amounts of I
I for Unit 3 and
-
for Unit 4 in
development phase cost, and
-for
Unit 3 and
cAsE NO. rPC-E- t_3 - 15
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for Unit 4 for the EPC contract, for a total
of $81-.378 milIion. I also recommend the following
regarding methods of handling variances between cost
estimates and actual costs:
1-. There should be a mandatory prudence review
of actual costs in a subsequent. proceeding before
the expenses can be put, into rates.
2. fn that proceedj-ng, all actual
expenditures should be reviewed against pre-
approved amounts by cost item category. Any
actual cost item category that exceeds the pre-
approved budget amount should be reviewed to
ensure any amount above the soft-cap for each
category J-s reasonable and prudent.
3. The Commi-ssion should aIIow ei-ther all or
none of the expense in a cost item category
subject to later approval.
4. If the Commission does a11ow partial
approval of the Company's estimate of a cost item
category, EDy amount put into rate base should
not exceed actual cost of that category.
5. The Company should provide to the Commission
quarterly project updates that i-llustrate plan
vs. actual status of expenditures by cost item
cat,egory and for the overall project timeline.
cAsE NO. rPC-E-r_3-l_5
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6. The Company should develop a method with its
partner, Pacj-fiCorp, to ensure the ability to
track costs by cost item category and Work
Breakdown Structure element so that
prudency can be reviewed on an on-going basls.
O. Does this conclude your direct test,imony in this
proceeding?
A. Yes, it does.
cAsE NO. rPC-E-13-L5
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CASE NO. IPC-E-13.16
EXHIBIT NO. 101 OF MIKE LOUIS
IS PROPRIETARY
t
dI
E
E
<r'
s14.00
512.00
s10.00
58.00
s6.00
s4.00
s2.00
q-
Natural Gas Forecast Comparison
"dP"""rS".,t""$""P"rS"..e"".,f "^S"dP"dF"S,$e""-S"-f "S"st"dl"dP--f-2012 EIA AEO Henry Hub {Nominal} **e-,- IPC 2013 IRP Henry Hub Base Case (Nominal}
-rq*PAC ?013lRP l"lenry l"lub Base Case (Nominal)
Exhibit No. 102
Case No. IPC-E-13-16
Mike Louis, Staff
t0n0lt3
CASE NO. IPC-E.13-16
EXHIBIT NO. 103 OF MIKE LOUIS
IS PROPRIETARY
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS llTH DAY OF OCTOBER 2013,
SERVED THE FOREGOING NON.PROPRIETARY DIRECT TESTIMONY OF MIKE
LOUIS, rN CASE NO. IPC-E-13-16, BY E-MAILING AND MAILING A COPY
THEREOF, POSTAGE PREPAID, TO THE FOLLOWING:
LISA D NORDSTROM
JENNIFER REINHARDT.TES SMER
IDAHO POWER COMPANY
PO BOX 70
BOISE rD 83707-0070
E-MAIL: [e-mail]
j reinhardt@ idahopower. com
dockets@idahoppwer. com
CB earry @ i dahopower. com
PETER J RICHARDSON
GREGORY M ADAMS
RICHARDSON ADAMS
515 N 27TH ST
BOISE ID 836I6
E-MAIL: [e-mail]
sre s fA.ri chard sonad ams. c om
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
7IO N 6TH ST
BOISE ID 83702
E-MAIL: [e-mail]
KEN MILLER
SNAKE RIVER ALLIANCE
BOX 1731
BOISE ID 83701
E-MAIL: [e-mail]
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: [e-mail]
DEAN J MILLER
McDEVITT & MILLER LLP
420 W BANNOCK
BOISE ID 83702
E-MAIL: [e-mail]
CERTIFICATE OF SERVICE