20200121Comments.pdf

EDWARD JEWELL
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, rDAHO 83720-0074
[phone]
IDAHO BAR NO. I0446
RECEIVED
l.llt JtN ? I PH t: bS
l!,
Street Address for Express Mail:
1 1331 W. CHINDEN BLVD, BI,DG 8 SUITE 20I.A
BOISE. IDAHO 83714
Attorney for the Commission Staff
BEFORE THE TDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E.I8-16
COMMENTS OF THE
COMMISSION STAFF
BACKGROUND
On May 9,2018, the Commission ordered Idaho Power Company ("Company") to "...file
a study with the Commission exploring fixed-cost recovery in basic charges and other rate design
options prior to its next general rate case." Order No. 34046 at 31. The Commission also ordered
the Company:
to undertake a comprehensive customer fixed-cost analysis to determine the
proper methodology and "spread" of fixed costs as they relate to the
Company's customers. The Company. with input from interested parties,
shall outline the scope of the study that should include exploring fixed-cost
recovery in basic charges and other rate design options. A status update shall
be filed with the Commission on a quarterly basis, with more specific
deadlines prescribed in the coming notice ofapplication in that matter.
Order No. 34046 at 23.
On Oct 19,2018 the Company petitioned the Commission to initiate a docket in order to
study fixed-cost recovery in basic charges and other rate design options as required by Order
No. 34046. On Nov 9, 2018, the Commission issued Order No. 34190, Notice of Petition and
STAFF COMMENTS JANUARY 21,2020
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IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY TO STUDY
FIXED COSTS OF PROVIDING ELECTRIC
SERVICE TO CUSTOMERS
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Notice of Intervention Deadline, which directed Stafl'to inlbrmally confer with parties about the
procedural and substantive scope ofthe docket, proposed schedule, and othcr matters, and then
repo( back to the Commission by April 30" 2019. Stafl-s report ("Staffls Report") includcd
tables ofrate designs and rate design attributes under consideration by parties at that time.
Intervening parties ("Intervenors" or "Parties") are Idaho Conservation League, Avista
Corporation, NW Energy Coalition, Idahydro, Idaho Inigation Pumpers Association, Inc., Rocky
Mountain Power, Vote Solar, City of Boise City, Idaho Sierra Club, Idaho Clean Energy
Association, Industrial Customers of Idaho Power, and Russell Schiermeier. Parties met for a
total ofone pre-settlement conference and five settlement mectings.
On August 9,2019, the Company provided a draft copy of the Fixed Cost Report to
Parlies, requesting their feedback. The Company submitted its Fixed Cost Report to the
Commission, along with a motion to accept this report, on September 30,2019. The Company
updatcd its Fixed Cost Report to correct some incorrect references on Deccmber 10,2019.
STAFF ANALYSIS
Summary
After conducting a comprehensive review ofthe Company's Fixed Cost Reporl and
supporting workpapers, Staffbelieves the Fixed Cost Report is incomplete and cannot be relied
upon as a basis lor changing rate designs. In particular:
r The evidence presented by the Company is insufficient to determine whether
current ratemaking methods allow the Company to currently over-recover or
under-recover all ol'the flxed costs authorized by the Commission;
o The Company did not provide sullicient evidencc to support a change in rate
design;
o Rather than undertaking a comprchensive customer fixed-cost analysis, the
Company provided the Commission a position paper advocating its preferred rate
design; and
o The Company did not adequately consider input lrom Parties regarding the scope
ol the report. The Company should have heeded Parties' input and provided a
much more comprehensive and quantitative analysis ofrates design options.
2..rA){t rARY 21 . 2010STAFF COMMEN'IS
Introduction
Staff believes the Company's Fixed Cost Recovery Report should have given more
attention to the topic of fixed cost recovcry and the options for fixed oost recovery. Instead, the
Company's Fixed Cost Report focuses on the proportion ofrevenue recovered from each class
through the Company's preferred billing mechanisms: Customer Charges, Demand Charges, and
Energy Charges. Nowhere in its Fixed Cost Report does the Company provide any quantitative
infbrmation showing whether or not it is adequately collecting its fixed costs, either through its
basc tarifTrates, or through riders such as the Fixed Cost Adjustment C'FCA") and Sales Based
Adjustment Rates ("SBAR").
StafTexplains the difference between revenue and t'ixed costs as follows. The costs of
serving each class include variable costs, such as the costs of fuel and market purchases; and
fixed costs, such as employee salaries, capital depreciation, debt service, and Commission
authorized return on equity in capital investments. When the revenue recovered from a class
tkough rates equals, or excceds. the cost of serving that class, the Company will recover all of
its fixed costs from that class. This is true, regardless ofwhether the rcvcnue is recovered
through Customer Charges, Demand Charges, or Energy Charges.
When the revenue recovered liom a class is less than the cost ofserving that class, then
the Company may not f'ully recover the fixed costs of serving that class. Because the Company
is obligated to pay lbr fuel. purchased power, and employee salaries, thc inability to recover
fixed costs first manifcsts itselfas a Retum on Equity ("ROE") that is less than that authorized
by the Commission.
The Fixed Cost Report does not provide any quantitative comparison showing how
alternative rate designs proposed by the Company would better collect thc Company's fixed costs
than cunent rate designs. In Stafl s discussion oflixed cost recovery, Staff will provide a more
in-depth discussion ofthe Company's ability to recovcr its fixed costs and will outlinc the
analysis that should be conducted prior to considering altemative rate designs for adoption.
Staffs fixed cost recovery scction will also discuss the Company's ability to recover its fixed
costs through basic rates and charges, as well as through riders. such as the Power Cost
Adjustment ("PCA'), SBAR, and FCA mechanisms. Using evidence provided by the Company
in its Fixed Cost Report and supporting work papers, Staff was unable to determine that the
Company is either over-collecting or under-collecting its Ilxed costs.
STAFF COMMENTS JANUARY 21.2020J
The Company's Fixed Cost Report focuses narrowly on the use ofrates to collect the
Company's revenue requirement. Although Staff takes it as axiomatic that rates must allow the
Company a fair opportunity to recover its revenue requirement, Staffnotes that many different
rate designs can achieve this goal. So long as rates afford thc Company an opportunity to
recover its revenue requirement, Staffbelieves that rates may be chosen to achieve other goals,
such as energy e1'ficiency, incenting cuslomer behaviors that def'er or avoid future plant
investment, or allowing customers the ability to control their bills.
The Fixed Cost Report advocates a particular rate design that the Company refers to as
"Cost of Service Infbrmed," often to the exclusion ofan objective and comprehensive analysis of
other rate designs proposed by Parties. As shown in Attachment A. the Company either did not
analyze, or did not adequately analyze, many of the rate designs proposcd by Parties. Staff
believes the Company should have conducted an objective and cornprehensive analysis ofall rate
designs discussed instead ofproviding a position paper advooating fbr its preferred Cost of
Service Informed rate design. Staff does not take a position on what, if any, changes should be
made to the Company's current rate design; however, Staffbelieves that some ratc designs
warrant a more detailed analysis than was presented by the Company. Had the Company's Fixed
Cost Report fully complied with the Commission's order, StafTbelieves that it could have served
as a toolbox which could be referenced by the Commission, Stafl', and other Parties when
discussing thc pros and cons olcurrenl rate designs, as well as rate designs that may be proposed
to the Commission fbr consideration.
Staffdisagrees that the Company's Cost of Service Inlbrmed rate designs are truly
informed by Cost of Service. Under the Company's proposed Cost of Service Informed rate
designs, the proportion ofrevenue collected through each rate componcnt (Customer, Demand,
Basic Load Charge, and Energy) is proportional to the Company's Class Cost olService
(*CCOS') allocators; however, the Company provided no evidence that its proposed billing
determinants correspond to the Company's CCOS allocators. Despite the similar names, the
conespondence between the Company's Dcmand charge and the Company's Demand CCOS
allocators is weak. Ol'particular concern is the Company's inability to show how its proposed
Basic Load Charge ("BLC") is related to factors that cause the Clompany to incur inoremental
fixed costs. Staff will discuss these concems. as r,''ell as general Cost olService principles, in its
Cost of Service discussion.
JANUARY 2I,2O2O4S]'AFF COMMENTS
Staff researched the experiences of other companies and jurisdictions with rate designs
similar to those studied in the Company's reporl. Some of these experiences are informative. In
the case of some rate designs, such as the Company's proposal to implemcnt demand charges for
Rcsidential and Small General Service ("R&SGS") customers, Staff confirmed that no other
investor-owned utility in the country has implemented a mandatory residential charge. Only one
investor-owned utility. Westar, has implemented mandatory demand charges lor solar customers.
Importantly, the experiences of other jurisdictions can alert the Commission to potential
unintended consequences ofeach rate design. StafThas summarized its research in the
subsection discussing each rate design.
Cost of Service
The Company's last general rate case used a Cost ofService study based on 2010
calendar year data. IPC-E-I 1-08, l,arkin di at4. In order to provide a more up-to-date basis for
its Fixed Cost Report, the Company developed an updated CCOS using calendar year 2017
information as its basis ("Straw Man CCOS'). The Straw Man CCOS was developed using the
IPC-E-11-08 methodology, updated to account for changes such as the creation of Rate
Schedules 6 and 8. Staff believes that the Straw Man CCOS is an appropriate basis for the
current discussion about rate designs, but also notes that the 2017 calendar year intbrmation used
to develop it has not been as thoroughly vetted as it would be in a lbrmal rate case.
The Straw Man CCOS classilles costs as either customer-related, demand-related, or
energy-related. Customer-classii'ied costs are those costs that vary with the number of customers
in the class, and include plant investments and expenses associated with meters, service drops,
billing, and customer service. Because they can usually be associated with particular customers,
the Company is able to directly allocate most of its customcr-classified costs to individual
classes. The Fixed Cost Report assumes all customer-related costs to be fixed. Fixed Cost
Report at 57.
Demand-classified costs are incurred to serve customers' maximum loads. Because each
piece ofplant must be designed to mect the peak load placed on it, demand-related costs are
closely related to measures ofpeak consumption such as Coincident Peak ("CP") and Non-
Coincident Peak ("NCP") allocators.
As noted earlier, some distribution plant. such as meters and sen'ice drops, can be
associated with particular customers and are classified as customer-related costs. Distribution
JANUARY 2I,2O2O5STAFF COMMLNTS
plant that cannot be directly assigned to particular classes are allocated using a class NCP
allocator. Fixed Cost Report at 64.
Because they must be designcd to mcet system-u'ide peak demand, the Company's
transmission and generation plant are allocated using a variety ofCP allocators.
In its Fixed Cost Report. ldaho Power assumes all Customer and Demand classified costs
to be fixed, and that Energy classilled costs are variable. Although this division is simple, Staff
notes that a considerable amount olgeneration plant is classificd as Energy, and thus, according
to the Company's model are variable, and not fixed costs. In fact, the Company's Strar.man
CCOS considers 55.4% oltixed base load generation to be a variable energy cost, rather than a
fixed cost. Fixed Cost Study at 22. In order to study the effects ofclassilying all generation
base load plant as Demand, and thus as Fixed Costs. the Company developed CCOS No. 3. This
scenario follows the same methodology as the Company's Straw Man CCOS but classifies all
generation plant as Demand. Had the Company used CCOS Scenario No. 3 as the basis for the
Fixed Cost Report. the reported tiaction offixed costs collected in the Company's energy charge
would have been even largcr than that reported by the Company. Fixed Cost Report at 23,
Figurc I3.
Staffnotes that the allocation of a portion offixed base load plant as an energy related
expense is consistent with the methodology used to develop the Company's j urisdictional load
tactor. It is also consistent with the methodology prescribed in Order No. 30722 (IPC-E-08-10).
Energy classified expenses typically include the costs offuel, energy purchases, and other
variable expenses associated with the production, transmission, and distribution ofenergy;
however, as noted previously, the Company's Strawman CCOS classifics a large fraction of its
fixed base load generation plant as a variable energy expense. In fact, approximately 50% of the
Energy-classified variable costs in thc Company's report represent the fixed cosls olbase load
generation plant. Fixed Cost Report at22. Energy classified costs are allocatcd to customer
classes using the normalized energy values for each class weighted by marginal energy costs.
Fixed Cost Report at 64.
Usc of Cosl of Service in Rate Making
A Cost of Service study is an attenrpt to assign costs to cach class according to the
manner in which each class caused the Company to incur costs. The Cost of Service
methodology employs hundreds ofdillerent formulae that may either represent industry best
STAFF COMMEN'I'S 6 JANUARY 21.2020
practice, Commission order, or the Company's best attempt to formulate a reasonable
methodology. Each of the hundreds of fbrmulae embodied in a Cost of Service study are based
on assumptions that may only be approximately correct, or that may have changed since the
methodology was adopted. For example, since the Company's last ratc case (IPC-E-11-08),
distributed generation systems have prolif-erated, and two ne$,rate classes have been created;
however, the Company's last rate case methodology did not include methods tbr valuing the
contribution ofdistributed gencration resourccs. or for determining the costs to serve those
customers. In sho(, the Company's Cost of Service methodology is an evolving work-in-
progress that is neither static nor perl'ect. The Conrpany's Cost ofScrvice Study may be a uselul
starting point, but the Commission is fiee to deviatc from it when its application vvould lead to
unfair, unjust, or unreasonable results. Thus, the results ofa Cost of Service study do not
necessarily represent an allocation of the Company's revenue requirement that the Commission
believes to be fair, just. and reasonable.
The results ofCost ofService studies often are used to identify potential cost shifting
Ilom one class to another. For example, the Cost of Service model proposed by the Company in
its last rate case allocated $127,619,827 to the Schedule 24 Agricultural Irrigation Class
("lnigators"). IPC-E-1 1-08, Larkin di. Exhibit No. 38. However, the base revenue ultimately
allocated to this class was only $107,383.256, or about 84% ofthe Company's Cost ofService
Revenue Requirement. IPC-E-I l-08, Motion for Approval of Stipulation, Exhibit No. 3.
Viewed through the lens of the Company's Cost of Service model, there was a $20,236,571 cost
shift from Irrigators to other parties; however, use ofa difl'erent Cost of Service model could
have given a very dif'tercnt result.
Once each class's revenue requirement has been determined, base rates for each class are
determined in order to recover that class's revenue requirement. It is possible that the rate design
dcveloped for a particular class over-collecls or undcr-collects revenue from that class; howcver,
because revenue collection from one class has little or no bearing on the revenue collected t'rom
another class after each class' revenue requiremcnt has been set, it is incorrecl to say that this
process results in a cost shift from one class to another. We can only say that the revenue
collected from a partioular class is either greater than. or less than, that authorized by the
Commission.
Whereas thc Cost of Service process aims to allocate costs to individual classes, rate
design is intended to I'airly collect revenue liom individual customers in a way that is most
7STAFF COMMF,Nl'S JANUARY 2I,2O2O
beneficial to all customers. Cost of Service takes a retrospective look at how costs have been
incurred, while rate design can be used to incent luture behaviors that lou'er costs for all
customers. For examplc, large volumetric energy charges incent behaviors that decrease energy
consumption. In addition to incenting oonservation o1'ooal, natural gas, or hydro-resources,
these rate designs can lead to lower average energy costs when marginal energy costs are high.
Likewise, time differentiated demand charges that incent reductions in demand at system
CP or class NCP can help delay. or even avoid. future expenditures on generation, transmission,
or distribution plant. At present, Schedules 9, 19, and 24, charge customers fbr demand through
their Demand and/or Basic Load charges.
On page 28 ofthe Fixed Cost Report, the Company states "A demand charge sends an
efficiency signal----one that correlates with load lactor and encourages customers to reduce their
peak energy usage." Staffbelieves that this statement is only partially corrcct. Although a
demand charge does. indeed, signal customcrs to reduce their demand, it docs not necessarily
provide a signal that incents custonrers to reduoe demand during the critical periods that drive
Clompany investment in nen'capital. In order for a demand chargc to effectively signal
cuslomers to reduce consumption during coincident and non-coincident peak periods, the
demand charge would need to be time difl'erentiated so that demand costs more during the
Company's peaking periods.
For most classes, the correlation between the Demand charge and thc CP allocator is
weak. According to the Company, the Demand charge is intended to recover a portion of
capacity-related costs associated with the generation and transmission ofelectricity. Fixed Cost
Report at 7. A customer's demand charge is based on that customer's lS-minute peak
consumplion, regardless ofwhether that peak coincides with system coincident peak. or not, so
there can be a mismatch between the coincident peak time and the time at which the customer's
peak demand is assessed. This mismatch sends a poor economic signal to customers who could
reduce or eliminate consumption during time periods conesponding to system CP.
For example, Schedule 24 secondary service irrigation customers pay an in-season
demand charge of $6.98 per kW of demand. Most irigation customers pump water 24 hours per
day during much ofthe growing season, so even iliuigation customers were to reduce
consumption during the Company's summer peaking period of l:00 pm to 9:00 pm, they would
still bc assessed the same peak demand charge lbr using their pumps outside of the peaking
S-IAFF COMMEN'I'S JANUARY 2I,2O2O8
period. This alone does not provide an incentive to reduce system peak demand to defer
investment in resources to meet additional demand requirements.
The Basic Load Charge (*BLC') is another demand allocator that is intended to collect a
portion ofthe capacily-related fixed costs ol'distribution f'acilities. Fixed Cost Report at 7.
Depending on customer class, the BLC is calculated using either the customer's highest peak or
using an average ofthe customer's highest peaks over the preceding twelve months. Fixed Cost
Report at 7. As noted earlier, distribution costs are rypically allocated across customer classes
using an NCP allocator. Because the customer's peak consumption periods do not necessarily
coincide with class NCP, the BLC does not send an economic signal that is ellbctive at reducing
class NCP.
In order to incent customers to reduce consumption during Non-Coincident-Peak periods,
the BLC would need to be based on consumption that occurs during Non-Coincident-Peak
periods used to develop the NCP allocator; however, Stall'was unable to ascertain any
relationship between the BLC and the Company's NCP allocators. In Production Request No. 7,
Stafl'asked the Company to provide intbrmation that could correlate the timing of demands used
to calculate customer B[,Cs with class NCPs. In its response, the Company stated that "The
requested information is not available." The Company lurthermore stated that, "Comparison
between the dates and times of non-coincident peak and customer individuat peaks would be
based on different, unmatched data sets."
Prior to implemcnting any new BLC charges, Stat'fbclicves the Company should study
the relationship between the BLC and the peaking evcnts that drive the Company to incur costs.
Fixed Cost Collection
Staff found no evidence, either in the Fixed Cost Report or the accompanying work
papers, that the Company is either over-collecting or undcr-collecting the fixed costs embedded
in its Commission authorized revenue requirement. Given that the Commission ordered the
Company to conduct a fixed cost analysis, Staff believes this to have bccn a serious omission.
Likewise, Stal'l'bclieves the report should have analyzcd the effect of the FCA and the
PCA on the collection offixed costs through proposed rate designs, as the parties agreed to
regarding the scope of the report.
Basic rates are designed, using pro-forma test year information from the Company's last
rate case, to recover all ofthe Company's fixed and variable costs. To the extent that customcr
9STAFF COMMENTS JANUARY 2I.2O2O
usage, customer count, and weather varies liom the pro-forma test year, the FCA is intended to
ensure that the Company collects its authorized fixed costs.
Because the prices of fuel and purchased power can vary substantially from pricing
assumed in the Company's pro-lbrma test year, thc Commission has authorized the Power Cost
Adjustment ('PCA') mechanism. The PCA allows the Company to properly recover its variable
costs, as well as some fixed costs.
As noted in Staff s discussion ofCost ofService, somc ofthe Company's tlxed costs are
classilled as variable Energy Costs. Recovery of energy classified fixed costs is achieved using
the Sales Based Adjustment Rate and is computed as part of the Company's PCA. The SBAR
calculation in the PCA adjusts for either the under-recovery or over-recovery of energy-classifled
production cost recovered through base rates due to the difference between the amount ofenergy
predicted to be consumed when base rates were set (total energy billing detcrminants) and the
actual amount ofenergy consumcd.
The Company's FCA and the SBAR component of the PCA exist to allow the Company
to fully recover tlxed costs not recovered in variable energy rates. As discussed below, it is
possible that the current FCA allows the Company to over-collect its fixed oosts; ho'\,t ever,
absent more complele information than was provided in the Company's Fixed Cost Report, it is
not possible for Stafl to determine whether the FCA is allowing the Company to over-collect or
under-collect the fixed costs embedded in the Commission authorized revenue requirement.
Staff notes that the Company's current Fixed Cost Ad.justment mechanism is intended to
be a true-up mechanism that "decouples," or separates, billed energy sales lrom revenue in order
to remove the finanoial disincentive that exists when the Company invests in Demand Side
Management C'DSM) resources and activities. It is calculated as thc difference betu,een the
level offixed cost recovery authorized by the Commission in the Company's last general rate
case, and the level offixed cost recovery that thc Company recovered through actual billed
energy sales during the calendar year. The FCA is calculated using a Fixed Cost per Customer
('FCC') and Fixed Cost per Energy ("FCE') that are calculated during each rate case.
In the most recent gencral rate case (IPC-E-l l-08), the residential FCC was calculated by
dividing the fixed costs embedded in the Commission authorized residential revenue requirement
($258,560,620) by the number ofresidential customers in the Company's test year (397,403).
The resulting FCC was $650.63 per customer. In its last FCA tiling, the Company reported
445.452 residential customers.
STAFF COMMEN'I'S l0 JNNUARY 21,2020
The F'CE represents the fixed costs embedded in the Company's volumetric rates. Irr the
most recent general rate case (IPC-E-11-08) this was lbund to be $0.051602 per kWh.
Each year. the l-CA is calculated by subtracting the product ofthe cunent year's billed
kWh sales and the FCE from the product ofthe current year's customer count and the FCC. In
2017, the customer count was 426,737 residential customers, 48,000 more than u'hen base rates
werc cstablished, and the Company billed those customers for 4.131,973,17 0 kWh, so the FCA
was $33,468,647.
Implicit in this calculation is the assumption that the fixed cost ofserving new customers
is the same as the fixed cost to serve the customers who existed at the time of the Company's last
rate case. Neither the Fixed Cost Report nor the work papers provided with it allowed Staff to
verif, this assumption.
Staffhad expected a more complete discussion ofthe need for and effects ofrevenue
stabilization mechanisms such as the FCA and PCA with its analysis of all rate designs
summarized in StafFs April 30,2019 report. Instead, the Company states, without supporting
evidence, that, "Many of'the cost ofservicc methodologies and rate designs in this report, il'
implementcd, would impact the level of reliance on existing FCA (either up or down) or warrant
consideration of a moditled fixed cost recovery mechanism." IPC-E- I 8- 16 Fixed Cost Report
page 2. The Company's report continues to restate this last assertion - that even with these rate
designs included in the Study, thc FCA, in one form or another, would still need to be
considered.
Staff has repeatedly expressed concems with the current FCA mechanism. Thc amount
the Company recovers fluctuates yearly as a f'unction ofthe kW sales and the number of
customers. The annual recovery amount for the FCA deferral is never "trued up" to the actual
yearly or current costs of the Company, and Staft'has not audited said fixed costs of thc
Company for comparison purposes to what the FCA is rccovering. Nor does the FCA currently
tie baok to the Company's DSM portfotio or savings.
Since its inception in 2007, the FCA has collected S180,565,737 fiom R&SGS
customers. During the l2 years that the FCA (2007-2018) has been in effect, Residential
customers have received surcharges in all years except one. Small General Service customers
have received additional surcharges in every year since the FCA's inception. Between 2013, the
first ycar for which complete data is available, and 201 8, $137 ,964,362 has been colleoted fiom
customers taking service under R&SGS tariffs. Over the same 6 years, the average calculated
STAFF COMMENTS ll JANUARY 2I,2O2O
S'I'AI;II COMMENTS t2 JANT]ARY 21.2020
Fixed Cost Recovery amount (FCE x kW sales) was $275,720,994, compared to the
$258,560,620 level offixed costs authorized by the Commission in the last general rate case
(IPC-E-l l-08). The dift'erence bctween what the FCA methodology calculates and the
authorized level offixed costs authorized in the last general rate case has not been audited by
Staff, nor has the change in fixed costs been deemed prudent by the Commission, yet the
Company recovers the additional revenue each year through the FCA. Staff expected that the
influences ofthe FCA and the PCA on fixed costs collected by the Company would be studied in
the Company's report. Staff also notes that the Company has not been in for a general rate case
since IPC-E-l l-08 was closed. Ilthe Company were under-collecting its fixed costs, Stalf
surmises that the Company would have filed a ncw rate case. At minimum, the Company should
have explained how updating its rates through a rate case could have corected over-
recovery/under-recovery due to long term changes in customer counts or load.
Selected Rate Designs
Staffs April 20,2019 report to the Commission summarized the rate designs and
attributes that were being discussed by parties at that time. Few ofthese rate designs and
attributes were analyzed and discussed in the Company's report. [n this section, Staffwill
discuss selected rate designs and describe analyses that should havc been included in the
Company's Fixed Cost Report.
StatTu'ill begin with a discussion of thrcc rate designs that will serve as book-ends for
understanding more complicated rate designs: A rate desigrr with large volumetric rate, a rate
design with a large fixed charge, and a rate design with a large dcmand charge. Because the
Company's current R&SGS schedules already rely on large volumetric rates, Stalfs discussion of
large volumetric rate dcsigns also serves as a discussion of the Company's current R&SGS rate
designs. Stal-fs discussion ofthe other two end-points. a structure with a large fixed charge and
a structure with a large demand charge, will serve as reference points for discussions about the
pros and cons of more complicated, multi-part ratc designs.
Staffnotes that any rate dcsign that incents changes in customer behavior is likely to be
destabilizing and may lead to improper collection ol'the Company's fixed costs. For example,
we would expect the current R&SGS rate designs, with their large volumetric rate components,
to incent decreased electric consumption. Given thc 1.3% average annual declinc in residential
energy consumption reported by the Company. it appears that these rate designs are working as
expectedi however, in decreasing consumption, this rate design also results in decreased
collection of the fixed costs embedded in volumetric rates. Fixed Cost Report at 29. Similarly,
we would expect a rate design with a large demand component to incent reductions in demand,
which would lead to decreased collcction of the fixed charges enrbedded in the demand charge,
and lead to the same potcntial for under-recovery that exists fbr volumetric charges. As
discussed previously, the FCA is intended to ofl'set the potential for over/under-recovered
revenue in volumetric rates. If the Company were to introduce a demand chargc, it is quite
possible that the Company would need an FCA-like mechanism to offset the potential for under-
recovered revenue in its demand rates.
As discussed earlier, rate designs may be used to incent behaviors that benefit all
customers. When marginal energy costs are high, reduced consumption benefits all customers
by lowering the average cost ofenergy embedded in volumetric rates, and reductions in demand
benefit all customers by deferring or avoiding the costs ofnew production and transmission plant
needed to mcet demand. StafT cautions, however, that the number of goals that can be achieved
with rate design is zero-sum. For cxample. an increased demand charge will require a decreased
volumetric charge, thereby diluting the volumetric charge's ability to signal reduced volumctric
consumption.
Attributes oJ Large Volumetric Rate designs:
The Company's Residential and Small General Service rate schedules rely on large
volumetric rates. Using the Company's 201 7 Straw Man CCOS as a guide, Stal'l tbund that
94.1% ofthe revenue collected from thesc classes is collected through the volumetric component
olthese schedules'two part rate dcsigns. The remaining revenue is collected from a small, five
dollar monthly customer charge. Using information l'rom the 2017 Straw Man CCOS, Staff
determined that under the Company's current rate schedule, R&SGS customers paid an average
volumetric charge of $0.084 per kWh.
About 46% ol'Company sales are to the Company's R&SGS classes, so it is imponant to
understand how.well volumetric rates f'are in collccting the fixed costs allocated to these classes.
According to the Company's 2017 Straw Man CCOS, the revenue requirement allocated to the
R&SGS classes was $455,596,645; hotever. the revenue collected from these classes,
$47 5,435,592, exceeded this allocation by 4.4%. Company Response to Staffs Production
Request Nos. 2l -24. Bccause the revenue f-rom these classes exceeds the R&SGS revenue
STAFI: COMMENI'S l3 JANL]ARY 2I.2O2O
requirement, Staff notes that the Company fully recovered its lixed costs from these classes in
2017.
One drawback of using rate dcsigns with a large volumetric component is their sensitivity
to annual and seasonal variations in weather. A standard rate case practice is to adjust test year
revenue lbr the effects of weather ("Weather Normalization"). Without Weather Normalization,
it is not possible to determine whethcr the current R&SGS rate design systematically over-
collects fixed costs, or whether fixed-cost over-collection in 2017 was a one-time occurrence.
Staffbelieves that the Company should have conducted a more thorough analysis to determine
t'hether or not the Company's R&SGS rate designs consistently over-collect or under-collect
fixed costs.
As noted in Staffs discussion of the Company's Cost of'Service models, thc Straw Man
CCOS classifies more than halfolits base load plant as energy. Under this methodology, the
energy classilied cost per kWh fbr R&SGS customers is $0.030 per kWh. When all base load
plant is classified as demand (CCOS Scenario 3), the energy classified cost drops to $0.016 per
kWh. Depending on whether fixed costs are viewed through the lens of the Straw Man CCOS or
CCOS Scenario 3, the fixed costs embedded in the residential volumetric rate are either $0.054
per kWh, or $0.068 per kWh. Under either Cost of Service methodology, fixed costs account fbr
the majority of costs embedded in thc R&SGS volumetric rates.
Because large volumetric rates provide an incentive to reduce consumption, it is not
surprising that monthly per-capita encrgy consumption is decreasing. Ifenergy conservation is a
goal, then the 1.370 annual decrease in per-customer residential energy use reported by the
Company is a f'eature, and not a defect of the R&SGS rate sohedules. Staff included a partial
analysis offixed cost recovery through the Company's current rate design in its Fixed Cost
Collection discussion: however, given the information provided in the Company's Fixed Cost
Report, Staff is unable to completely quantif)'the impact that decreased energy consumption has
on the Company's ability to collect its tixed costs in basic rates. StafTbelieves that the
Company's Fixed Cost Report should have quantified the impact ofdecreased volumetric sales
on fixed cost recovery,
A second benefit oflarge volumetric rates is their effect on peak demand. Because
measures undertaken by customers to reduce overall consumption usually reduce peak
consumption, reduction in energy consumption is often accompanied by concomitant rcductions
in system peak load. For example, air conditioning is a primary driver olsummer peak demand.
STAFF COMMENTS 14 JANUARY 2I,2O2O
Because it is likely that an air conditioning unit will be operating during summer coincident
pcaking events, use of more elllcient air conditioners reduces both total energy use and peak
demand. It is likely that much ofthe l% annual reduction in demand reported by the Company
is due to measures undertaken by customers whose primary aim was reducing their monthly
energy bill.
A rate design employing large volumetric rates may not fairly reflect the way that
individual customers cause the Company to incur costs. For example, the infiastructure required
to connect a single-family residence to the system is approximately lhe same. regardless ol'
whether that residence is heated using an electric fumace or a gas fumace. Because electrically
heated homes use much more energy during the winter months, they pay much higher energy
charges than their gas heated counterparts, and because fixed costs are embeddcd in volumetric
rates, customers with electrically heated homcs pay a larger share of the Company's
infrastructure costs, even though they requirc about the same amount of infrastructure as other
customers.
Currently, the residential schedule employs a tiered rate design: Monthly energy rates
increase with increasing consumption. One effect ofthis structure is to destabilize revenue
collection through volumetric rates and exaggerate the eff'ects olweather on revenue collection.
Another effect is to increase the tiaction ofthe Company's flxed costs paid by customers with
electrically heated homes. The Company brietly discusses this issue on pages 26-27 olits Fixed
Cost report.
Staff's investigation found that nearly all investor owned utilities use volumetric rates lbr
residential customers, though some commissions have approved time-based volumetric rates as a
method for reducing demand and potentially deferring the need to invest in new plant.
Attributes of Rate Schedules v'ith increose(l Fixed Charges
As noted in Staffs Cost of Service discussion, most ofthe costs that the Company incurs
serving its customers are fixed. Using the Company's Straw Man CCOS as a guide, Staff
determincd that of the total $987 annual cost of serving R&SGS customers, about $654 (66.3%)
represents fixed costs. Ifthe production plant costs are classified as demand (CCOS Scenario 3),
lixed costs represent $812 (82.3%) ofthe annual cosls olserving the Company's R&SGS
customers. Given the large fiaction of tlxcd costs embedded in customer bills, StalTbelieves that
rate designs with high fixed cost components deserve some consideration.
S'I'AI,'F COMMENTS l5 JANUARY 21,2020
The Company briefly discusses a rate design with a high fixed charge on page 27 ol'the
Fixed Cost Report but dismisses it because it does not promote other policy objectives.
Although a rate design with a large monthly fixed charge would not promote energy
conservation or demand reduction, it would stabilize and reduce bills for most customers who
rely on electricity to heat lheir homes. This could be particularly important for some [ou,incomc
or fixed income customers.
For the current discussion, Staff will use the Company's2017 Straw Man CCOS as the
basis for a 2-parl residential rate design with a $56 monthly customer charge reflecting the fixed
costs ofserving residential customers, and an energy charge of $0.030 per kWh ("Hypothetical
F'ixed Rate"). StatTnotes that thc average cost ofserving a residential customer is about $85 per
month. Given that average residential consumption is 957 kWh per month, the Company would
collect an average energy charge of$29 per month. enabling the Company to collcct thc cntire
$85 average monthly cost ol'serving its residential customers. Because the $0.030 per kWh
energy charge represents only variable energy costs incuned by the Company, the Company
should be able to collcct its fixcd costs regardless ofvariations in consumption due to variable
weather or changes in customer behavior.
In order to understand how adopting the Hypothetical Fixed Rate would impact its
customers, Statf examined the billing eft'ects on three hypothetical residential customers: An
average Idaho Power residential customer with consumption of I 1,485 kWh per year, a customer
w'ith elcctrical space heating and consumption of 22.270 kWh per year, and an apartment dweller
with gas heat, and electrical consumption of4,550 kWh per year.
Under the Hypothetical Fixed Rate, the average Idaho Power customer would see no
change in average monthly bills relative to the current volumetric rate design. Her average
monthly bill would remain at approximately $85 per month; horever, she would not see as much
seasonal variation in her bills under the Hypothetical Fixed Rate design as she does under the
Company's current volumetric rate design.
Residential customers with electrical space heating would see the largest changes to their
monthly bills. Under current rates. the typical residential customer with electrical space heating
pays an average bill of $ I 52.40 per month, with a January bill of $323.09 per month. Under
Staffs Hypothetical Fixed Rate, the same customer's average monthly bill would drop to $107.39
per month, with a January bitl ofjust $ 162.41.
STAFT I]OMMI]NTS l6 JnNtJnRY 2t.2020
The apartment dweller's average monthly bill would increase from $33.24 per month to
$66.50 per month under the Hypothetical Fixed Rate design.
Staff's invcstigation ofother investor-owned utilities lbund that none charged a monthly
fixed charge as high as the $56 Hypothetical Fixed Rate. Idaho Power's $5 service charge lbr
residential customers is relatively low compared to the residcntial service charges ol'most other
investor-owned utilities. Staffs review found thal in 2017, the fixed charges approvcd by
Commissions rangcd from $5 to $20 per month, with an average tixed charge of $ I L I 9.
Demand Based Rate designs
A properly structured demand charge can incent customer behaviors that allow thc
Company to reduce, defer, or avoid investment in new production, transmission. or distribution
plant; however, becausc demand classified plant-in-service represent costs that have already been
incurred by the Company, a reduction in customer demand does not result in an irnmediate
reduction in Company expenses. Furthermore. because properly structured demand charges can
be expected to result in demand reduction over time, they would not be expected to stabilize
Ilxed cost recovery. Currently, residential customers pay no demand charge, yet residential
demand is still decreasing at a rate of l0lo per year. This is only slightly less than the 1.3%
annual decrease in residential energy consumption. Ifthe Company were to implement a
residential demand charge, it is not unreasonable to expect that demand could decrease at a much
greater rate than it currently does. Staff believes the Fixed Cost Report should have included a
much more thorough analysis ofhow increasing demand charges could result in decreased
demand, and a concomitant reduction in fixed costs collected through demand charges.
Several of thc Company's rate schedules employ one or more demand charges. We will
use the Schedule 9 Primary Large General Service rate schedule to illustratc how demand
charges are used. In addition to a $285 monthly service charge and an average energy charge of
about $0.043 per kWh, Schedule 9 Primary customers pay three different demand-related
charges: A Demand Charge, an On-Peak Demand charge, and a Basic Load Charge.
The Demand Charge is based on the average kW power supplied during the l5-
consecutive minute period of maximum use, regardless ofthe time ofday that this peak occurs.
Currently, Schedule 9 Primary Service demand charges are $5.09 in the summer, and $4.46 in
the winter. This dcmand charge will incent customers to reduce their peak demand, but not the
time of day at which peak demand occurs. According to the Company's Fixed Cost Report, the
STAFF COMMENTS t7 JANIJARY 21,2020
Demand Charge is intended to recover a portion of capacity-related generation and transmission
costs; however, as noted in Staffs discussion on Cost ofService, transmission and generation
costs are driven by a need to meet system coincident peak demand. Given that the demand
charge is the same, without regard to whether or not the Customcr's peak consumption is
coincident with system peaking events, it is dillicult to see how the current demand charge is
related to the way in which customer classes cause the Company to incur costs, or how it fully
incenls customers to avoid consumption patterns that drive the need for investment in production
and transmission plant.
The Schedule 9 Primary Scrvice On-Peak Billing Demand Charge is a $0.95 per kW
charge assessed during the lS-minute period of maximurn use during the On-Peak time periodl.
This small charge provides a weak signal to Schedule 9 customers that inccnts reduced demand
during likely peaking hours.
Schedule 9 Primary Service customers also pay a $ 1.28 per kW Basic Load Charge
("BLC"). According to the Company. this chargc recovers a portion o I.capacity-related fixed
costs ofdistribution facilities, such as substations. primary lines, and transformers. Fixed Cost
Report at 7. For Schedule 9 customers, the charge is assessed monthly, and it is bascd on the
average of the two highest monthly billing demands over the past year. As noted in Stai'fs Cost-
of-Serwice discussion, distribution plant is typically allocatcd based on each class's non-
coincident peak. Because the peaks used to compute a customer's BLC do not generally
coincide with class non-coincident peak. Staffdocs not believe that the BLC provides a
particularly good signal to customers to engagc in consumption pattems that decrease the need
for distribution plant. In Production Request No. 7, Staff asked the Company to explain how the
peaks used to calculate the BLC coincide with the Class Non-Coincident Peak Period used in the
2017 Straw Man CCOS. In its response. the Company stated, "Comparison between the dates
and times of non-coincidcnt peak and customer individual pcaks would be based on different,
unmatched data sets."
There do not appear to be any investor-owned utilities in the country with mandatory
demand charges for non-solar residential customers. However, several investor-owned utilities
ofl'er pilot programs or other optional tariffs that include demand charges.
I The Company's On-Peak Billing Period occurs from l:00 pm to 9:00 pm, Monday through Friday (except
holidaysl ftom June through August.
STAFF COMMF,N I S l8 JANUARY 21.2020
Attributes of Time oJ Demand Based Rate Designs
As noted in the previous section, the Company's demand charges do not I'ully incent
reduced consumption during critical time periods such as system CP and class NCP. A time
dil'lerentiated demand charge sends a signal that encourages customers to both decrease peak
loads, and to shift the times at which their peak loads occur. The relatively small Schedule 9 On-
Peak Billing demand charge is a Tirne ol Demand charge. Olcourse, a larger On-Peak demand
charge could provide a larger incentive to reduce consumption during system CP,
The Company's Schedule 24 Inigation Tariff provides a good example for why such a
rate design might be desirable. During thc irrigation scason (May through September), Inigators
who receive power at secondary level voltage pay a $22.00 monthly service charge, an energy
charge olapproximately $0.0562 per kWh, and a $6.97 per kW demand charge. 'l'his demand
oharge is the same, regardless ofthe time ofday that the Inigator's peak occurs. Most lrrigators
can, and do, pump water 24 hours per day during the irrigation season. Without an appropriate
economic signal, there is no incentive for Irrigators to reduoe pumping during hours of likely
system coincident peak. Staflnotes that secondary level irrigation customers account for
approximately 2370 ol-summer peak dcmand, so any reduction in Irrigator's demand could help
defer the need for luture generation and transmission plant. Company's Straw Man CCOS.
Currently, Irrigators can sign-up tbr the Company's Optional Schedule 23, peak rewards
program. Under this program, Irrigators can receive a bill credit of $5.00 per kWh in exchangc
fbr allowing the Company to curtail their power during system peaking events. A timc
dill'erentiated demand charge could incent all Irrigators to reduce their demand during periods of
time corresponding to system coincident peak.
It is important that the peak period used to calculate the On-Peak billing charge
correspond with the time periods during which a system coincident peaking event is likely to
occur. Currently, the On-Peak billing period used in the Company's tariffs is defined as l:00 pm
to 9:00 pm, Monday ttrough Friday. In Appendix H, the Company presents the results ol'an
analysis showing that most peaks occur bctween 3:00 pm and 10:00 pm, rather than the l:00 pm
to 9:00 pm summer On-Peak period currently used in the Company's Taril1i.
There do not appear to be any investor-owned utility in the country with mandatory time-
of-demand charges.
S'l AFF C'OMN{EnNTS t9 JANI.JARY 21,2020
Time ol Use Rate Dcsigns
In its discussion of Volumetric Rate designs, Staffnoted that in addition to incenting
reductions in energy consumption, volumetric rates were probably responsible lbr some ofthe
l7o annual reduction in demand reported by the Company. The incentive for decreasing CP and
NCP demand can be increased by increasing volumetric rates at times coinciding with periods
during which system coincident peak. or class non-coincident peak are likely to occur. The
Company's discussion of Time of Use rate designs includes a discussion of two different rate
designs. The first is actually a hybrid rate design that includes both time differentiated energy
rates and a Basic Load Charge.
The second is a more traditional 'fime of Use ("TOU') rate design. 1-hc Company
criticizes the TOU rate design because it "does not reflect the cost to serve." Fixed Cost Report
at 34. Staff both disagrees w'ith this assessment and disagrees that it is necessary lbr a rate
design to be based on the Company's pref'erred collection mechanism in order to reflect a "cost to
serve." By increasing volumetric charges during potential peaking periods, TOU rate designs
signal customers to reduce consumption during times when cost to serve is the highest.
Furthermore, because the Company's Demand and BLC charges arc calculated rvithout regard for
timing ofthe Customer's peak, there is little relationship between these charges and the CP and
NCP allocators used to allocate Demand classilled costs, so it is dilficult to see how the
Company's proposed Demand and BLC charges are relevant to Cost of Service. In short, Staff
believes that a traditional Time of Use rate design is a more effective signal ofcost causation
than the Company's proposed Demand and BLC charges.
The Califomia Public Utilities Commission instituted mandatory Time of Use rates for all
commercial, industrial, and agricultural customers under its jurisdiction. Residential customers
have the option to enroll.
STAFF COMMENTS 20 JANI]ARY 2I.2O2O
The Company's Cost of Service InJbrmed Rate Designs
The Company proposes a number of rate design modifications that it claims to be Cost ol'
Service Informed. In order for a rale design to be truly Cost of Service intbrmed, it is necessary
for thc rate design's billing determinants to be corrclated with the allocators used to assign a
share ofthe Company's revenue requirement to each rate class. An example can be found on
page 45 of the Fixed Cost Report, where the Company proposes introduction ola tlasic Load
Charge for Irrigators. Cunently, Inigators pay a single demand charge each month. The
proposed Basic Load Charge would be calculated using the average olthe previous l2 months'
two highest monthly demands. Fixcd Cost Report at 42. Given that most Irrigators'load profiles
are relatively flat throughout the growing season, it is difficult to see how introducing a new
demand charge that is nothing more than an average obtained tiom the existing demand charge is
an improvement. For irrigation customers, the proposed BLC does nothing that can't be
accomplished by increasing the demand charge with a conesponding decrease in volumetric
rates. Given that the proposed new charge does not provide an incentive for customers to reduce
load at system peak, it is dillicult to understand the purposc ofthe proposed Basic Load Charge.
The Company also proposes what it calls a Three Part Demand Structure fbr rcsidential
customers. Stafl notes that the Company's Three Part Demand Structure actually uses four
components: A llxcd $17.28 Customer Charge that corresponds with customer-classified
charges; a $5.41 per kW on-peak demand charge corresponding with summer production related
costs: a $ 1.15 per kW Basic Load Charge corresponding with distribution-related costs, and a
tiered energy chargc that would include all energy costs, all transmission costs, and non-summer
production costs. F-ixed Cost Report at 28 - 31 and79.
As currently configured, the Company's residential AMI meters are not capable of
measuring peak demand during specilied time periodsl however, thc meters are capable of
recording each hour's oonsumption. As a proxy for on-pcak demand, the Company proposes
using the maximum hourly consumption during the Peak Billing Period (3:00 pm to l0:00 pm
during summer weekdays) as a proxy. Company's response to Stal ls Production Request No. 9.
StafTbelieves that this proposed demand charge can incent reduced coincident peak demand,
thereby deferring investment in production plant; howevcr, this reduction will also result in
reduced revenue collected through the Demand charge. Prior to considering the introduction ofa
demand charge into the Company's residential rates, Stall'believes it to be imperative that the
Company look at how customers might use both short and long-term measures to reduce
demand. Many customers will be able to achieve meaninglul sho(-term demand reductions by
assuring that certain appliances, such as air conditioners, clothes dryers, or hair dryers, are not
used during the on-peak period. Over the longer term, whcn opting to replace existing
appliances, customers may choose smaller appliances, such as smaller air condilioning units,
with reduced consumption and demand.
Staff is also concemed with the Company's proposed Basic Load Charge, primarily
because the Company was unable to demonstrate how it is correlated with either residential class
S'I'AFF COMMENTS 21 JANUARY 2I.2O2O
non-coincident peaking events or with customer behaviors that decrease the need Ibr f'uture
production plant. Company Response to Staffs Production Request No. 7. Staff believes that
the following quote from James Tong, and lbrmer FERC commissioner Jon Wellinghoff
encapsulates the problems ofusing demand charges to recover the sunk costs ofdistribution
plant:
Furthermore, the only things that utilities size according to demand from
individual residential customers are the final line transformers and connecting
secondary lines. These costs are small relative to those of generation and
transmission capacity. And most of these capacity costs are sunk. By
deflnition, sunk costs cannot be incremental. Using the cost-causation
principle to justifu demand charges to pay for sunk costs makes no sense;
future usage behavior does not cause costs that have been sunk.
Tong and Wellinghofl, Utilitics Dive, October 2016.
As previously stated. no other investor owned utility in the country has implemented a
mandatory three-part residential rate that includes a dcmand componenl tbr non-solar customers.
Rate Design for Net-Metering Customers
In Ordcr No. 34509, the Commission ordered the Company to conduct a credible and fair
study of the costs and benefits ofnet metering. In particular. the Commission specified several
ways in which the study must reflect publio input, including public u'orkshops and the ability lbr
customers to provide comments during the study design and study review phases. Stali-
recommends that rate design changcs fbr net metering customers be discussed in these public
workshops in order to hear and incorporate public tbedback.
SUMMARY AND RECOMMENDATIONS
Summary
The Company's Fixed Cost Report is incomplete and cannot be relied upon as a basis to
reasonably change rate structures. In particular:
o The evidence presented by the Company is insufficient to determine whether
current ratemaking methods allow the Company to over-recover or under-recover
all of the flxed costs authorized by the Commission;
o The Company did not provide sut'licient evidence to support a change in rate
design;
22 JANUARY 2I.2O2OS'I'N F'I- CoIVI \,I ENTS
a
a
Rather than providing the Commission with a toolbox that it could use when
assessing various rate designs, the Company provided the Commission a position
paper advocating its preferred rate design; and
The Company did not adequately consider input from parties regarding the scope
ofthe report. The Company should have heeded Parties'input and provided a
much more comprehensive and quantitative analysis of rates design options.
Recommendations
Prior to any proceeding that contemplates a change in rate design, the Company should
perform an objective and comprehensive study of all rate designs under consideration. The study
should consider the pros and cons ofeach rate design, including:
o A quantitative analysis ofeach rate design's ability to collect fixed costs
embedded in the Commission's authorized revenue requirement;
. A quantitative analysis ofthe rate design's stability under conditions ofchanging
weather, increased customer counts, or changes in oustomer behavior;
o A quantitative analysis ofthe impacts ofrevenue stabilization mechanisms (e.g.
FCA, PCA, and SBAR) on the rate design's abitity to collect fixed costs; and
r A quantitative and qualitative analysis that changes in rate design may have on
disparate groups within the affected classes.
Respectfully submitted this 1l dav of .Ianuarv 2020
:t
L(
Ed J ll
Deputy A rn General
Technical Staff: Mike Morrison
Stacey Donohue
Kathy Stockton
Rachelle Famsworth
Michael Eldred
Joe Terry
Johan Kalala-Kasanda
i:umisc/comments/ipce I 8. I 6ejmmklsdcmcrfiid conlments
STAFF COMMENTS 23 JANUARY 21,2020
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Attachment A
Clase No. IPC-ll-18-16
Stat'f Comments
01121120 Page I of2
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Attachment A
Case No. IPC-E-18-16
Staff Comments
0ll2l120 Page 2 of 2
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 2IS' DAY OF JANUARY 2020,
SERVED THE FORIGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC.E-I8-16, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOI,LOWINC:
LISA D NORDSTROM
IDAHO POWERCOMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: [e-mail]
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
710 N 6TH STREET
BOISE ID 83702
E-MAIL: bottolaltidahoconscrvation.ors
ELECTRONIC ONLY
.loc IVI i ller
ioe.rniller(a)a vrsUtcorD.com
ERIC L OLSEN
ECHO HAWK & OLSEN PLLC
PO BOX 6r l9
POCATEI,LO ID 83205
E-MAIL: [e-mail]
C TOM ARKOOSH
ARKOOSH LAW OFFICES
PO BOX 2900
BOISE ID 83701
E-MAIL: tom.arkoosh koosh.corr.r
erin.ceci I koo sh.cor.n
TIM TATUM
CONNIE ASCFIENBRENNER
IDAIIO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: tlatumari)idahopo\\'er.co1rl
F. DIEGO RIVAS
NWENERGY COAT,ITON
I1O1 8I'H AVE
HELENA MT5960I
E-MAIL: diego(a)nwencrgy.com
ANTHONY YANKEL
I27OO LAKE AVE
UNIT 2505
LAKEWOOD OH44IO7
E-MAIL: tonyfayankel.net
TED WL,SI'ON
ROCKY MOIJN'I'AIN POWER
1407 WN TEMPI,F] S]'E 330
SALT LAKE CITY UT 84I I 6
E-MAIL: tcd.r.v 0t'l ilic c ol11
CERIII:ICATE OF SERVICE
DAVID J MEYER ESQ
VP AND CHIEF COTINSEL
AVISTA CORP
PO BOX 3727
SPoKANE WA99220-3727
E-MAIL: [e-mail]
caschenbrcnncr(alt idahopou,er.com
ELECTRONIC ONLY
dock etsilr)i dahorrorvcr.conr
PATRICK D EHRBAR
DIR OF REG AFFAIRS
AVISTA CORP
POBOX3727
SPOKANE WA.99220-3727
E-MAIL : patrick.ehrbar(@avistacoro.com
ABIGAIL RGERMAINE
BOISE CITY ATTORNEY'S OFFFICE
PO BOX 500
BOISE ID 83701-0500
E-MAIL: [e-mail]
KELSEY JAE NTINEZ
IDAHO SIERRA CLUB
920 CLOVER DR
BOISE ID 83703
E-MAIL: [e-mail]
RUSSELL SCHIERMEIER
29393 DAVIS ROAD
BRUNEAU ID 83604
E-MAIL: [e-mail]
BRIANA KOBOR
VOTE SOLAR
358 S 7OO E STE 8206
SALT LAKE CITY U]'84I02
E-MAIL: briana@.votesolar.ors
NICK THORPI,
E-MAIL: nthorpelr0eanhi ustice.ors
PRESTON N CARTER
GIVENS PURSLEY LLP
601 W BANNOCK STREET
BOISE ID 83702
E.MAIL:
[e-mail]
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: dreadin [e-mail]
YSECRET
CERTIFICATE OF SERVICE
YVONNE R HOGLE
ROCKY MOUNTAIN POWER
I4O7 WN TEMPLE STE 320
SALT LAKE CITY UT 84116
E-MAIL: [e-mail]
DAVID BENDER
EARTHJUSTICE
39l6NAKOMA RD
MADISONWI 537II
E-MAIL: [e-mail]
PETER J RICHARDSON
RICHARDSON ADAMS PLLC
5I5N2TTIISTREET
PO BOX 7218
BOISE ID 83702
E-MAIL: [e-mail]
ELECTRONIC ONLY
AL LL]NA
E-MAIL : aluna(?earthjustice.org
ZACK WATERMAN
MIKE HECKLER
IDAHO SIERRA CLUB
503 W FRANKLIN ST
BOISE ID 83702
E-MAIL: [e-mail]
[e-mail]