20171127Comments.pdf

STOP BzH Coalition
tdaho Public Utilities Commission'-- - otficeStJp,?'E'3t'o
Nov 2 7 2017
November 27,2017
Via Email
Boise,ldaho
Diane Hanian
Commission Secretary
Idatro Public Utilities Commission
472W. Washington St.
Boise,ID 83702-5983
[e-mail]. eov
Re: Case No.IPC-E-17-11: STOP B2H Coalition Comments
Please find attached the elechonic comments in pdf format for the STOP B2H Coalition. Hard
copies, if required, will be hand delivered later this week.
Please do not hesitate to contact me if you have any questions or need other materials. Thank
you.
Sincerely,
:5V^,}--
Jim Kreider for the
STOP B2H Coalition
60366 Marvin Rd
La Grande, OR 97850
[e-mail]
STOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 1 of 35
CERTIFICATE OF SERVICE
I hereby certiS that on this 27nd day of November 2017,I emailed copies of the formal
comments, in PDF format, from the STOP B2H Coalition to the following persons.
Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington St.
Boise,ID 83702-5983
[e-mail]. gov
Lisa D. Nordstrom (C)
Timothy E. Tatum
Michael J. Youngblood
Idatro Power Company
l22l West Idaho Street
PO Box 70
Boise,Idaho 83707
lnordstrom@ idahopower. com
ttatum@ idahopower. com
myoun eb lood@ idahopower. com
dockets@ i dahopower. com
Dr. Don Reading (C)
6070 Hill Road
Boise,ID 83703
dreadin e(d mindsprin e. com
Eric L. Olsen
Echo Hawk & Olsen PLLC
505 PershingAve., Suite 100
PO Box 6l 19
Pocatello, ID 83205
elo(dechohawk,qqm
Peter J. Richardson (C)
RichardsonAdams PLLC
PO Box 7218
515 N.27th Street
Boise. lD 83702
peter@ri chardsonadams. com
C. TomArkoosh (C)
DavidArkoosh (C)
Arkoosh Law Offices
Sean Costello
DeputyAttomey General
Idaho Public Utilities Commission
472W. Washington
Boise,lD 83702
sean.costello@puc. idaho. gov
ThorvaldA. Nelson (C)
Emanuel T. Cocian (C)
Kim Stanger
Holland &Hafi
6380 S. Fiddlers Green Circle, Suite 500
Greenwood Village, CO 80lI I
tnelson@hollandhart. com
etcocian@hollandhart. com
kcstan [e-mail]
khall@hol landhart.com
AnthonyYankel
12700 Lake Ave. Unit 2505
Lakewoo4 OH4/.l07
[e-mail]
Gregory M. Adams (C)
RichardsonAdams, PLLC
515 N. 27th Street
Boise,ID 83702
gre g@,richardsonadams. com
Pete Bennett (C)
Micron Technology, Inc
8000 S. Federal Way
Boise,ID 83707
[e-mail]
Gloria D. Smith
Managing Attorney Sierra Club Environmental
Law Program
SIOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 2 of 35
Idahydro
802 W. Bennock Steet. Suite 900
PO box 2900
Boise,ID 83701
Tom. arkoosh@ arkoosh. com
Erin. [e-mail]
2l0l Webster Street, Suite 1300
Oakland, CA946l2
(4ts)977-ss32
gloria. smith@),sierrac lub. org
STOP B2H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 3 of 35
2017
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
In the Maffer of
Idaho Power Company Case NO. IPC-E-I7-ll
Resource Plan
STOP B2IJ Coalition Comments
Submiued November 27, 2017
STOP 82H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 4 of 35
Table of Gontents
Section 1. ldaho Power has adequate firm Transmission 5
ldaho Power Has Already Acquired 350 MW of lncremental PNW lmport Capacity Without Building
B2H 8
ldaho Power's Assumed Levelized Cost of PNW Market Purchases ls Not Credib|e...........................10
PNW lmports Represent a Natural Gas Resource Strategy and Must be Evaluated As Such.............. 11
ldaho Power lgnores Certain Costs of lmporting PNW Power. ...................13
The Claimed Cost of B2H to ldaho Power Ratepayers is Significantly Understated Due to Phantom
Transmission Revenue Credits.........
Section 2. The cost of the B2H transmission line must be verified..
Section 3. Conservation, Energy Efficiency and Demand-side Management
ldaho Power: Conservation and Efficiency
ldaho Power: Residential Customer Outreach
ldaho Power: Agricultural and Commercial Conservation lnitiatives
ldaho Power: Discussion of Service Area Conservation & Efficiency
Citizen Alternative: Demand Response....
Section 4. Distributed Generation
Lack of Prudency....
Resistance Toward Distributed Generation..
Distributed Generation - lndustrial
Citizen Alternative: Distributed Generation..
Section 5. Conclusion .................
L4
16
t7
18
18
20
20
22
24
24
26
27
29
32
STOP 82H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 5 of 35
Stop B2H Coalition (STOP), a citizens'interest group, hereby submits its Opening Comments
related to Idaho Power's 2017 lntegrated Resource Plan. STOP presents its case that Idaho
Power has the resources available to meet future needs without building the Boardman to
Hemingway ffansmission line (B2H) and without building new thermal generating facilities.
The early decommissioning of coal plants planned in the 2017 IRP is supported by STOP. The
B2H which is at the core of the company's 2017 IRP preferred portfolio design is not supported
by STOP.
The evaluation of resources on a consistent and comparable basis, a reasonable test for prudency
and STOP's concern for the long-term burden on ratepayers, set the overall tone for most
arguments against the B2H. Specific concerns and challenges will be cited, as well as, citizen
alternatives offered within the following Sections and Appendices.
Idaho Power is over-estimating its demand load forecast, under-estimating its energy efficiency
and demand-side management capabilities, and it has the necessary transmission resources
currently available to meet its needs in the future. STOP also challenges the company's cost-
estimates for the B2H transmission line which create a dubious conclusion of the least-cost,
lowest risk portfolio scenario: "the best cost/risk portfolio."
Section 1. ldaho Power has adequate firm Transmission
Idaho Power has firm transmission rights for Pacific Northwest (PNW) energy imports which
the company is unwilling to use orfully disclose. This section demonstrates and documents
that the company has more than 350 MW offirm transmission which was not disclosed in its
IRP. This more than meets the energy import needs that ldaho Power claims it needs via
B2H.
Idaho Power's proposed action plan is centered on the construction of the Boardman to
Hemingway transmission line (B2H) as the key "resource" action in the proposed Action Plan.
Idaho Power is resolute in their request that the Idaho Commission approve ldaho Power's
request to construct B2H, despite a clear failure on the part of Idaho Power to establish the value
of the transmission line, and the inconvenient fact that electric transmission by itself is not a
resource. Specifically, the IRP is devoid of any analysis of the underlying power resource
actually represented by B2H in the IRP, which are short-term forward capacity purchases in the
PNW for import into Idaho.
Idaho Power describes the B2H transmission line as a "supply-side resource," a concept which is
absurd on its face. A transmission line does not supply any capacity or energy to meet loads. In
some circumstances, a new transmission investment can be considered to create an "option" to
acquire market priced power in the PNW for import into Idaho Power makes no attempt to
actually value B2H as an option using standard option pricing approaches. (This would entail
STOP 82H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 6 of 35
determining the option value of B2H to Idaho Power ratepayers first, and then comparing that
value to the cost of B2H.)
lnstead of analyzing the option value of B2H, ldaho Power identifies B2H as a resource. To
justiff their selection of B2H as a resource, Idaho Power has apparently created a single 20 year
point estimate forecast of power prices in the Pacific Northwest that is intended to support the
wisdom of Idaho Power spending over $250 million for a minority ownership share of B2H.l As
shown below, this point estimate approach suffers from serious analytic shortcomings and flawed
assumptions.
The Commission must refuse to approve the B2H action item in the IRP, as there is absolutely no
substantive analysis in the record to support IPC's B2H action item. Specifically, Idaho Power
has failed to present and support a credible forecast of PNW purchase power at delivered
costs/prices over the planning horizon. Furthermore, IPC has treated the cost of purchase power
imports from the PNW as a single point estimate for the entire IRP planning period, without
consideration of any risk or uncertainty around that estimate, as required by the IRP Guidelines.
Even more duplicitous is IPC's failure to highlight to the Commission that in 2015, IPC actually
acquired over 350 MW of additional long-term firm import capacity which is approximately the
same amount of transmission originally sought via the proposed B2H transmission line.2
Specifically, IPC acquired more than 350 MW of incremental firm PNW import capacity through
a complex "asset swap" with PacifiCo.p3. The acquisition of this import capaciry via ownership
of transmission lines formerly owned by PacifiCorp, came at a large cost, resulting directly in an
over 4lYotransmission rate increase to Idaho Power ratepayers.a IPC has inexplicably failed to
highlight this expensive transmission acquisition in their IRP, and has further failed to address
why IPC still needs B2H after their 2015 acquisition of over 350 MW of incremental firm
transmission from the PNW to Idaho. As explained beloq by ldaho Power's own admission,
their IRP projects that in 2026,when B2H would come into service, Idaho Power will already be
relying on imports to meet lTYo of peak loads. Idaho Power has not addressed the price and
supply risks of relying on spot markets to serve lTYo of peak load, much less their desire to
further increase their reliance on spot market purchases to meet over 25o/o of their peak loads
with the addition of B2H.
1 See lRP Appendix C, Page 76.
'The 2011, 2013, and 2015 IRP's all said that IPC sought 350 MW of incremental summer peak import capability.
3 Joint Application for Authorization for Disposition of Jurisdictional Facilities, FERC Docket EC15-54, Exhibit C page
L46.
n tpC's ZOts PTP Transmission Rate was 522.48 kW-year and the rate today is 534.90 kW-year, a 55% increase in just
two years. See http://www.oatioasis.com/ipco/index.html.
STOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP PaBe 7 of 35
ldaho Power Has Already Acquired 350 MW of Incremental PNW lmport
Capacity Without Building B2H
Idaho Power appears to be obscuring the fact that they now hold considerably more long-term
firm import capability from the PNW than they held when they last produced their 2015 IRP.
Idaho Power correctly describes that the existing transmission system is rated to move up to
1200 MW of power from the PNW to Idaho (WECC Path 14) in a West to East direction and
further correctly states that this capacity was and is fully subscribed.5 What Idaho Power fails to
identifu in the IRP is that in 2015, there was a fundamental change in the allocation of those
1200 MW of transmission rights, effectively reallocating over 350 MW of the existing 1200 MW
of capacity from PacifiCorp to Idaho Power.6 The capacity reallocation was part of a larger
"Asset Swap" between Idaho Power and PacifiCorp.
This asset swap transaction came at an enormous cost to Idaho Power Ratepayers and other users
of the Idaho Power transmission system, requiring an approximate 47 percent increase in
transmission rates over 2 years.T The following table from the WECC Path Rating Catalogue
shows the allocation of Path 14 capacity before theAsset Swap transaction. It shows that the
existing 1200 MW West to East transfer capability was allocated between BPA, PacifiCorp and
Avista.
WECC 2017 Path Rating Catalog 34
The transfer capability of the path is allocated among the interconnections as
follows:. 2400 MW East-to-West:
1587 MW IPC - PAC interconnection
413 MW IPC - BPA interconnection
400 MW IPC - AVA interconnection
. 1200 MW West-to-East:
350 MW BPA - IPC interconnection
400-510 MW PAC - IPC interconnection
340-450 MW AVA - IPC interconnection
For the 1200-MW west-to-east, the sum of the PAC and AVA allocation cannot
be greater 850 MW (Seasonal Allocations: Spring - AVA 400 MW and PAC 450
MW, Summer - AVA 340 MW and PAC 510 MW, and Winter - AVA 450 MW and
PAC 400 MW).
Under terms of the asset swap and capacity reallocation, PacifiCorp received 1,090 MW of East
to West capacity across ldaho and in turn, Idaho Power received rights to PacifiCorp's west to
east capacity from the PNW to ldaho. The following table identifies the allocation of capacity
t zotz tnp page 58.
5 See FERC Dockets Ec15-54 and ER15-580.
7 See FERC Docket ERL5-2292.
STOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 8 of 35
Allocation
between parties after the asset swap transaction closed in December of 2015. It shows that after
the asset swap and capacity reassignment, IPC now holds approximately 82 percent of
PacifiCorp's former west-to-east capacity allocation, or over 400 MW.8 STOP is unable to find
an], evidence in the IRP that Idaho Power has disclosed. or otherwise considered this new
capacity in their IRP.
It is possible that Idaho Power has in fact acknowledged this new capacity starting in 2026 when
a mysterious jump in import capacity is identified that is unrelated to B2H. The following table
compares the stated amount of capacity available for imports from the PNW in the 2015 IRP to
the same line item in the 2017 IRP.
8 PacifiCorp and ldaho Power are allowed to schedule up to 550 MW over the Hemingway-Summer Lake line and
398 MW over the Walla-Wall-Hurricane line respectively, but the simultaneous schedule across the two lines
cannot exceed PacifiCorp's historical allocation of 510 MW as reflected in the WECC Path Rating Catalogue.
0
I
5v)
398
0
a
0
q
on of Jurisdictional FERC Docket EC15-54, Exhibit C t6
$m
398
1500
398
loint ication for Authorization for Di
Total
Directional Capacity Allocation BEFORE Di rectional Capacity Al location AFTER
4s0 lm
325 73
ldaho-Northwest Transmission (WECC Path 14)
Hemingway-Summer Lake 50O kV
Walla-Wal la-Hurricane
Asset
West to East
(MW)
East to West
IPC PAC Total IPC PAC TOTAL
1600 0 2557 0
Asset
West to East
IPC PAC Total
1600 0
(lvrw)
East to West
IPC PAC L
t467 LW
STOP B2H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 9 of 35
Calculation of ldaho Power's Proposed Reliance on Market Purchases (imports) to ttleet Peak Loads
July-17 July-18 July-19 July-20 !uly-21 luly-22 July-23 July-24 July-25 July-26 July-27 July-28 July-29 July-30
Firm lmport
Capability 2015
IRP 239 2U 230 227 224 273 270 26 26L 257 2v 249 245 242
Firm lmport
Capability 2017
IRP
lncrease over
2015 tRP
2017 Forecast
July Peak Load
(9s% W/DSM and
EE)
B2H in Service
2026
2017lRP Monthly
Surpl us/Deficit
Percent of peak
capacity needs
met with market
purchases
313 313 302 431 492 489 488 47 /186 616 51s 6L4 613 6L2
74 79 72 206 28 2L6 2t8 22t 225 361 365 368 374
3195
0
tl8)
3195
0
429
3310
0
362
3366
0
311
uL7
0
255
v72
0
195
3s28
0
1:t8
3s89
0
76
3640
0
23
369s
500
ffi
3753
5q)
ffi
xL2
500
UL
3870
500
103
3927
5m
42
-s.s% -3.6% -L.go 3.6% 6.9%o 8.5% g.yo LL.s% 12.7% L7.6r6 t8.9yo 20.3% 26.t% 27.2%
Source: 2015 IRP at page 134 and 2017 IRP at page 126
As can be seen in the table, by ldaho Power's own admission, in 2026 they will be relying on
over 600 MW of firm import capability to meet peak loads without B2H. This 600 MW of
imports represents almost l8% of forecasted peak load in2026 after DSM and EE. This is an
astounding level of reliance on imports and lacks credibility. But Idaho Power does not want to
stop there. Their preferred Portfolio 7 with B2H projects that market purchases will comprise
over 27yo ldaho Power's projected peak loads before the first generating resource (reciprocating
engines) are added to the system in 2031.
ldaho Power's Assumed Levelized Cost of PNW Market Purchases ls Not
Gredible
One of the fundamental requirements for any IRP is the identification of resource options and an
analysis ofthe cost ofeach resource considered; both stand-alone costs and the cost ofeach
resource when integrated into a utility's resource Portfolio. Inexplicably, the 2017 IRP contains
no analysis of the cost, availability, price and supply risk of relying on PNW spot market
purchases to meet firm peak load requirements. Furthermore, Idaho Power seems to believe that
incremental imports of PNW spot market power is the preferred new resource in the IRP,
whether already existing import capability represents only I percent of peak supply, or represents
more than 15 percent of peak supply as is the case for ldaho Power.
Remarkably, ldaho Power presents no analysis or material discussion of the "PNW imports"
resource contained rnthe 2017 IRP. There is no discussion or forecast of forward power price
curyes in the PNW that is internally consistent with Idaho Power's forecast of natural gas prices
(i.e., prevailing fuel prices). Idaho Power presents no analysis of the correlation between
STOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 10 of 35
summer spot market prices and prevailing natural gas prices in the PNW. There is no analysis of
the expected effect on spot market power prices when 1,300 MW of coal capacity is retired in the
PNW in 2O2O.e Imports from the PNW don't even appear in the IRP Table of Supply Side
Resources.l0 In short, Idaho Power apparently expects the Commission to take Idaho Power's
recommendation to build B2H on faith.ll The only relevant information on the cost of PNW
imports appears in a single page of Appendix C that summarizes the Levelized Cost of Supply
Side Resources.12 A cursory examination of the levelized cost of PNW imports contained in
Appendix C compared to actual market prices clearly indicates that Idaho Power has
significantly understated the expected cost of a B2H/PNW Import resource. While STOP does
not have the resources to independently perform the analysis the ldaho Power has failed to do,
the limited examination of Idaho Power's conclusions explained below highlights the flawed
assumptions underpinning Idaho Power's 2017 IRP.
PNW lmports Represent a Natural Gas Resource Strategy and Must be
Evaluated As Such
The choice of a resource Portfolio that relies primarily on expanded market purchases of power
to meet sunmer peak loads represents a natural gas based resource strategy. This is an empirical
fact. During periods of high demand in the PNW, the marginal cost of dispatching gas-fired
generation typically sets the market price of power. As stated in the Northwest Power Planning
Council's 7th Power Plan:
"Since natural gas-fired plants are often the marginal generating unit, gas prices play an
important role in determining the wholesale electricity prices. Variations in the future
price of gas could have a significant impact on electricity prices for the region."l3
Idaho Power's IRP fails to account for the relationship between daily natural gas prices and the
daily market price of power in the PNW. lnstead, Idaho Power appears to have selected a single
point estimate of monthly power prices to populate the Aurora model. This point estimate of
monthly power prices used by Idaho Power to calculate the levelized cost of purchase power is
already proving to be too low.
First, a simple comparison of actual on-peak PNW market prices in July and August of 2017 to
Idaho Power's unsupported forecast of market prices shows that Idaho Power has materially
underforecast the cost of purchase power in their Portfolio modeling. The following table shows
the actual volume weighted average monthly price at MIDC this past summer alongside the
actual monthly PNW gas price, and the implied market heat rate (i.e., the actual relationship
e Both the 7OO MW Centralia unit 1 and 600 MW Boardman coal plants are required to close by the end of 2020.
'o zotT lRP Appendix c, page73.tl See IRP Appendix C, page 73.
12 See Levelized Cost of Energy, IRP Appendix C, page76.t'Porr", Council 7th Power Plan, https://nwcouncil.orslmedia/682g30Twholesaleelectricitv.pdf page 11.
SIOP B2H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 11 of 35
between gas prices and power prices). The table also identifies the PNW power price that ldaho
Power selected when calculating their levelized cost of PNW market purchases. The table shows
that actual PNW market prices in July 2017 were 24o/ohigher than assumed by Idaho Power and
actual market prices in August of 2017 were 98% higher than assumed by Idaho Power in their
IRP.
More importantly, Idaho Power's whole treatment of the B2H resource option suffers from a
failure to reflect the inherent relationship between gas prices and market power prices, and the
risk and volatility represented by a significant increase in reliance on the market to meet firm
load commitments. For example, the implied market heat rate of July market power in the PNW
was 10,900 in2016 and ll,l00 in2017, or an average of 11,000 Btu/kWh. Based upon this
relationship, a $1.00 increase in gas price would result in an $11.00 per MWh increase in the
market price of power.
The correct way to incorporate B2H transmission and market purchases into resource planning
would be to treat B2H as an "option" to purchase market power based upon an implied market
heat rate (monthly differentiated) and a forecast of gas prices. ln this way, sensitivity analysis
and risk assessments that test the robustness of resource portfolios under fuel price uncertainty
would capture this relationship between market price risk and gas price risk. Idaho Power's IRP
fails in this regard.
This fundamental flaw in their IRP Portfolio analysis leads Idaho Power to erroneous and
unsupportable conclusions in support of buildingB2H to create an option to buy more power in
Jul-16 Aug-16 Jul-17 Aug-77
Forecast MIDC Power Price Used by ldaho Power in
Levelized Cost Calculation (SMWh)NA NA 5 24.27 S 28.18
Actual Weighted Ave. MIDC On-Peak Power Price
(Sruwnl s za.eg s 3s.62 s 3o.oo s ss.76
Actual as Percent of Forecast NA NA L24%
Actual Weighted Ave. Malin Gas Price 5 z.u S 2.56 S 2.5e S 2.5e
lmplied Heat Rate (Btu/kwh)70,923 13,392 Ll,L43 20,694
Source: US Energy lnformation Administration:
https ://www.e ia. gov/el ectri city/whol esal e/#h istory
and Attachment 5 to Res nse to Staff Data Re uest 55
STOP B2H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 12 of 35
B2H should be modeled by tdaho Power as an option to purchase peak summer market power at
a price based upon an empirically supported market heat rate (e.9., 11,000 Btu/kWh) and the cost
of gas. The Aurora model would then compare the cost of purchasing market power based upon
the gas price and an 11,000 heat rate, to dispatching the next resource in the alternative fossil fuel
portfolio. In the fossil fuel portfolio, the comparable option would be the reciprocating intemal
combustion engine (ICE) that would dispatch at a guaranteed heat rate of only 8,400 Btu per
kWh.l4 This means that if the price of gas rises by $1, the cost of market power would rise by
$11 MWh but the cost of power from the intemal combustion generating unit would only rise by
$8.40 MWh. By extension, a combined-cycle combustion turbine would dispatch at a
guaranteed heat rate of only 6,700 Btu/kwh and a $l rise in gas price would only increase the
cost of power by $6.70 MWh, compared to the $11 increase for purchased power.
ldaho Power lgnores Certain Gosts of lmporting PNW Power
Idaho Power's specification of the cost of PNW imports ignores the cost of wheeling PNW
power to the Idaho Power system. This is a significant and unacceptable oversight. PNW power
prices are based upon the cost of undelivered power. While a party can transact (purchase)
power at the PNW market price, that power still needs to incur wheeling costs to be delivered to
a scheduling point where the power can be exported from the PNW to the Idaho Power system.
Even with the construction of B2H, the B2H line will not access any power plants directly.
Idaho Power will still need to pay for a transmission wheel and losses, likely over the BPA
transmission system, to get the power from whatever the generating source in the PNW to the
Idaho Power System, including to B2H. If this transmission wheel is over the BPA transmission
system to B2H, then Idaho Power would pay BPA's hourly transmission rate plus 1.9% for
transmission losses. BPA s current transmission rate is $4.23 Mwhls and the cost associated
with real power losses would bring the cost of wheeling up to about $5 MWh. If the
transmission is instead provided over the PacifiCorp system, the costs would be about double
($10 MWh) as PacifiCorp's hourly transmission rate is $7.70 MWh and PacifiCorp assesses
losses at the rate of 4.45o/o. Based upon Idaho Power's representation of the levelized cost of
PNW market power, their failure to properly account for wheeling costs alone means ldaho
Power has understated the expected costs of imports by as much as 20 percent.
" 2oL7 IRP Appendix c, page 73.
15
httos://www.boa.eovlFinance/Ratelnformation/RateslnfoTransmission/FY18-192018%20Rate%20Schedule%2OSu
mmarv.pdf
SIOP B2H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 13 of 35
the PNW. Specifically, Idaho Power appears to penalize non-B2H portfolios in the high gas
price sensitivities based upon the higher cost of dispatching existing and new gas-fired resources,
but does not similarly penalize B2H Portfolios that rely on relatively higher cost market
purchases in this higher gas price environment.
The Claimed Cost of B2H to Idaho Power Ratepayers is Significantly
Understated Due to Phantom Transmission Revenue Credits
ln what appears to be a desperate attempt by Idaho Power to make the numbers for B2H work,
they introduce the theoretical concept of substantial secondary transmission sales revenues as an
offset to the cost of B2H. Without analytic support, they value these annual transmission sales
revenues at alevelized benefit of $9 MWh (i.e., credit against the annual fixed cost of B2H), and
perform no sensitivity analysis around this assumption. To put this in context, this projection
translates into over $9 million/year levelized.16 Idaho Power appears to have hardwired these
large and speculative revenues into the Aurora model.
Idaho Power does not provide any support for this rosy estimate of secondary transmission
revenues but a look at demand for existing capacity held by Idaho Power from the PNW to Idaho
is illustrative of a lack of value for the path in all but the late spring months when excess PNW
hydro drives PNW market prices low or even negative.
To test the credibility of Idaho Power's claim of lucrative revenues from secondary transmission
sales, STOP examined the secondary revenues earned by Idaho Power in 2016 on the PNW to
Idaho path after the capacity reallocation from PacifiCorp to IPC described above. The
following table shows all secondary revenues earned by Idaho Power in 2016 on their share of
the Northwest to ldaho path acquired from PacifiCorp. The table shows that in 2016 Idaho
Power eamed barely $l million in secondary revenues from third parties using Idaho Power's
allocation of transfer capability from the PNW to Idaho during times when Idaho Power is not
otherwise using their existing import capacity.
" 350 MW .Sg .33%Capacity Factor. 8760 = 59,106,020
STOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 14 of 35
Payrn€ntto IPC by
EnerEy Recd
Frcm EneryyDelTo Type FOR
NF
NF
NF
NF
NF
NF
NF
NF
ST Firm
NF
NF
POD
MWH
rcceived
MWH
Delhreied
Total
Revenue
2 lberdrola Renewables PAcw
3 lberdrola Renewables PACW
4 Morganstanley PACW
5 Morganstanley PACW
6 lvlorgan Stanley PACW
7 Morgan Stanley PACW
8 iiorgan Stanley PACW
9 Pacificorp PACW
10 Pacificorp PACW
11 Pacificorp PACW
12 Pacificorp PACW
Ul Pacificorp PACW
14 Pacificorp PACW
15 Powerex PACW
15 Powerex PACW
17 Powerex PACW
18 Powerex PACW
19 Powerex PACW
20 Powerex PACW
21 Shell Energy N. America PACW
22 Shell Energy N. America PACW
23 Shell Energy N. America PACW
24 Shell Energy N. America PACIW
25 Shell Energy N. America PACW
26 Shell Energy N. America PACW
27 Shell Energy N. America PACW
28 The EneEyAuthority PACW
29 The EnergyAuthority PACW
3O Transalta Energy Marketint PACW
31 Transalta Energy Marketint PACW
PACE
Sierra Pac Power
PACE
PACE
PACE
PACE
M345
PACE
PACE
PACE
PACE
PACE
PACE
PACE
PACE
Sierra Pac Power
PACE
PACE
PACE
PACE
PACE
PACE
Sierra Pac Power
Sierra Pac Power
PACE
Sierra Pac Power
PACE
PACE
PACE
Sierra Pac Power
SMtK
SMLK
SMLK
SMLK
Walla Walla
walla Walla
Walla Walla
SMLK
SMLX
SMLK
WallaWalla
5t4,229
s1s83
Y24
Scr
51,609
s219
S92s
s182,331
s133,782
S11e84
5224,49tt
5349,169
59s7
57s,637
57,610
Srqass
58,288
57,223
51,7t7
52,513
5s5,813
y,424
$72,3Ls
5L2"tsL
s10,842
s12,118
$r,ssz
52u
512314
NF
NF
NF
NF
NF
NF
NF
NF
NF
ST Firm
NF
ST Firm
NF
NF
NF
NF
NF
NF
WallaWalla
SMI.K
5MI.K
SMLK
WallaWalla
WallaWalla
WallaWalla
SMLK
SMLK
SMLK
SMLK
SMLK
wallawalla
WallaWalla
SMLK
SMLK
SMLK
SMLK
BORA
M345
BORA
BRDY
BORA
BRDY
M345
BORA
BORA
BRDY
BORA
BORA
BRDY
BORA
BRDY
M345
BORA
BRDY
M345
BORA
BRDY
BRDY
M345
M345
BRDY
M345
BORA
BRDY
BORA
M345
TOTAI.s
3L4L
79L
339
65
1285
L75
739
66.t07
48505
5070
81394
726597y7
17185
LTE
2359
1883
L64.l
390
7U
1s037
Lt92
19483
3274
2921
326s
449
50
4267
3141
79L
339
65
1285
175
739
66to7
48505
fi70
81394
126597
v7
17L85
t729
2359
1883
16/.l
390
7U
15037
Lr92
19483
3274
292t
326s
M9
50
4267
Sz.
Sz.
52.
52.
Sr.
53.
s3.
53.
s3.
53.
53.
50 50 s2o341o4ir4 4tm3/. ir\zfr,?fi
Source: ldaho Power2015 FERC FORM I
Basic economic realities would suggest that when existing transmission capacity across a certain
path in a certain direction has little demand for use on a non-firm basis, expanding the capacity
across the path as B2H would accomplish does nothing to increase demand for the path. Stated
another way, the expected level of secondary transmission revenues accruing to Idaho Power by
virtue of B2h is likely zero.
STOP asks that the Commission investigate the company's acquired 350 MW of Incremental
PNW Import Capacity which has not been disclosed.
STOP also asks the Commission to investigate the questionable costs and risks of relying on
purchasing market power to meet firm loads, and the unsupported projection of large secondary
transmission revenue credits that serve to artificially reduce the cost of B2H to ratepayers.
STOP 82H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 15 of 35
Section 2. The cost of the BzH transmission Iine must be
verified
The cost of the B2H has been stated as $1.2 billion for several years and more information
should be shared with the public so an informed and prudent decision can be made. The best-
cost/least risk portfolio choice is also dependent on a verified calculation.
Sectron _! above addresses the questionable costs of purchasing PNW power and transmission
revenues. ln fact, even simple cost calculations must be updated and submitted to a third party
competent to audit and report to the Commission. A number of additional calculations need to be
made (and updated) and the costs recalculated:
a) The assumed inflation rate of 2.lo/o per year should be recalculated for the life of the
project-not merely the 20 year planning period. The rate payers will burdened with the
cost of the B2H for 50-55 years-not 20.
b) The cost of financing should also be calculated and shown. Again, for the entire project
life and not for the planning period alone. For example, if Idaho Power's share is
approximately $286 million before financing here's what it looks like over 55 years using
a prime rate of l.5o/o:
otal
Item lnterest Years to
Pay
5!
Yearly
Pryment
Perlods I Payment
Year I Period
Payort Over lnterest Over
Llle ol Loan Llle ol Loan
Power Line $286 000 000
Rats
1 500/o ,12 s636 643 t7 639 7'16, $120 184 399: S134 184
The above is illustrative only, but if the financing is at a higher rate, this could easily lead
to a half-billion dollars in debt that Idaho Power customers will be responsible for.
c) Cost ovemrns for transmission lines are between 30-50oh.r7 Are they included? A prudent
planner would calculate costs based on at least some cost overruns.
d) A contingency cost, such as for litigation, needs to be to be added to the B2H, as
compared to over-run costs, which are different. The costs involved in burying the
approximate 1.5 miles of the transmission line in front of the National Historic Oregon
" Common Cost Overruns on Transmission lines:
o https://www.utilitvdive.com/news/cost-overruns-in-sop-transmission-oroiects-draw-ire-of-rtos-
leaders1402680l
o http://acadiacenter.orslwo-content/uploads20160dAC transmissionmemo spreads finalforweb.pdf
o htto ://www.scienced irect.com/science/article/oii/S22 146296 14000942
o http://www.brattle.com/rystem/publications/pdfsro0000484lorisinal/Summarv of Transmission Proiec
t Cost Control Mechanisms in Selected US Power Markets Pfeifenbereer Hou Oct 2011.pdf?137877
2134 (see C. Southwest Power Pool and E. California ISO)
SIOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 16 of 35
ment D,etailc Totals
Trail Interpretive Center, near Baker City, need to be added. The B2H violates protections
under the National Historic Trail Act and it is nearly certain to be litigated if burial of the
line is not included in the cost.
e) The added surplus sales of generation are included as a cost offset in theAURORA
portfolio modeling in Idaho Power's 2017 IRP. (discussed on a technical level in Sgqlreu
-t). The company admits that historically, additional transmission wheeling revenue has
not been quantified for a transmission capacity addition.l8 In the IRP modeling, the
estimated incremental transmission wheeling revenue from non-native load customers
was modeled as an annual revenue credit for B2H portfolios.
f) We understand there is a20o/o contingency fund. Is this fund included in the base cost or
is it on top of the $1.2 billion total? Are the above mentioned items included in this20o/o
contingency fund? Similarly, the rate of return on investment (ROI) or profit the
company will make should be calculated and shown. We understand it to be in the range
of 6.70/o.Is the profiUROI included or in addition to the Sl.2 billion? Separating these
would be more transparent to the public and the Commission.
g) An estimate of the cost increase to B2H ratepayer's energy bills should be calculated and
shown. [n Order No. l7-235, effective July l, 2017,the Oregon Public Utility
Commission approved a revenue requirement increase of $ I ,056,800, or I .9 I percent,
associated with a 2025 end-of-life for both Valmy units. Are we to assume that
approximately $1 million in investment equates to approximately a L9Yo increase to the
ratepayers?
STOP asks the Commission to investigate and verifu the cost estimates provided by the
company. Specifically, STOP contends that the cost estimates do not reflect the entire cost of the
B2H project over the life of the project. Rather, they only include some of the costs for the 20
year planning period. This lacks truthfulness and integrity and does not seem to be a prudent
refection of the true cost and risk that the ratepayers will be assuming.
STOP also asks the Commission to investigate the legitimacy and prudency of the utility adding
potential revenues to off-set costs in their calculations. Future revenues, given the rapidly
changing energy industry, seem suspect at best. STOP would like to see revenue assumptions
separated from the cost calculations to better compare the cosVrisk to other portfolios in the IRP.
Section 3. Conservation, Energy Efficiency and Demand-side
Management
What follows is referenced from Idaho Power's 2017 IRP ("ldaho Power 2017 lntegrated Resource
18 See 2017 ldaho Power IRB p 54.
STOP B2H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 17 of 35
Plan" 2oL7) Appendix B: DSM Annual Report, with the page or section numbers from that
document included where relevant.
Idaho Power has achieved much less in relative energy efficiency savings when compared to
other utilities. Conservation and efficiency are widely acknowledged to be the area where the
greatest savings can be achieved at the least cost and risk to the utility.le
ldaho Power: Gonservation and Efficiency
Idaho Power's residential efficiency efforts have focused on the same funding sources that have
been on-going utility initiatives for decades. These include education and energy efficient
lighting programs.
The only initiative which remotely touches on demand response is the A/C Cool program. A
device attached to the air conditioning unit automates on/offcycling at preset intervals, helping
moderate peak demand during the hottest summer days.
DarrelAnderson, Idaho Power's CEO, has stated that:
"it is easier to develop incentives when people are paying 30 cents a kilowatt hour. "
(Fisher 2016)
The reality is that hundreds of thousands of kilowatt hours have been saved by utilities whose
average base charge is less than 12 cents kWh. While Idaho Power describes customer
satisfaction with its outreach efforts at length in their 2017 IRP, there is little evidence of
increased energy savings outcomes since 201l.
ldaho Power: Residential Customer Outreach
Idaho Power's efforts to persuade rate payers to conserve energy are insufficient and largely
ineffective and those efforts appear to have flagged over time.
ln20l6, residentialcustomers'bills included an invitation to "Take the Smart-saver Pledge."
Residents were asked to pledge an "energy saving behavior change" for three weeks, but to
change their behavior for only one day each of those weeks. They were asked to choose from
activities that included turning thermostats down one to three degrees, washing a full load of
laundry in cold water and hang dryrng it, or using the crock pot or BBQ instead of the oven.
"Pledges" were sent to 367,221customers. Those responding were eligible to win an Energy
" Delmarra Power & Light, P.S.C. Del No 8 - Electric, March 31, 2017 approximately 11 cents kWh; Public Service
Company of New Mexico, 20th Revised Rate No. 1A, effective October L,20L6 approximately 9 cents a kWh; NV
Energy nvenergy.com /rates, w/o TOD savings, approximately 11 cents a kWh. The details are in Footnote b.
STOP B2H Coalition Comments on LC 68 ldaho Powers 20L7 IRP Page 18 of 35
Star appliance. 937 pledges were received, and by responding to a follow up-survey customers
were eligible to win one $100 prize. 408 customers responded with all but one reported plans to
continue with the energy saving changes. The utility rated the follow-up effiort at 97o/o positive
response but only achieved a miniscule .0011 % behavior change in its customer base. lpp.2l-
22.1
Idaho Power's residential energy savings programs saw increases in the 2009-2011 time period,
but energy savings have been static or declining since then. [pp. 177-185]
Only two new energy programs have been added since 2009, with Easy Savings Kits and
Educational Distributions added in2015. It's unclear how kWh energy savings are measured for
these efforts. [p. 178]
The A/C Cool Credit program mentioned previously has a total of 28,000 participants across the
service area, just .063 % of residential customers. That program "was not actively marketed in
2016" although efforts were made to retain participants. [p. 34]
Idaho Power initiated successful TOD pricing with 1300 customers in 2013 (approximately
.003% of residential customers). Idaho Power has not expanded the program in the intervening
years.
Fifty percent of ldaho Power's overall residential energy efficiency savings are the result of the
Energy Efficient Lighting program which distributes LED lights to its customers. [p. 175]
ln 2016, Idaho Power saved 42,208 MWh through residential energy effrciency. As mentioned in
the overview, other utilities have been more aggressive and much more successful in their
efforts.20
While the IRP forecasts growth of .09% per year for average energy demand, and l.4Yo per year
for peak-hour demand 12017 IRP, p.l], these forecasts fail to reflect the flat demand and
declining average customer use the utility has seen from 2007 to 2016. This trend is true despite
20 Examples include:
r Delmarva Electric with 73 the number of residential customers saved 77,781 MWh
o PNM with 500,000 customers combines renewables: solar (505,640 MWh); wind (924, 518 MWh); and
geo-thermal 15L9,742 MWh), to produce clean power for 154,000 homes (12.57 MWh per home or
1,950,000 MWh of total savings)
o NV Energy with 1 million customers, approximately twice the number for ldaho Power, saved 235,000
MWho Ameren Missouri with 1.2 million residential and business customers plans over the next 3 years to add
energy savings of 570,000 MWh.
STOP 82H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 19 of 35
the fact that Idaho Power has not shown consistency in its efforts to meet peak demand by
pursuing peak demand savings. Much more is possible.
ldaho Power: Agricultural and Commercial Conservation lnitiatives
The utility has had more success with its agricultural and commercial customers, much of which
reflects the time and staffthese organizations are willing to spend on what is often the largest
expense many of them have. The result has been ever-increasing efficiency for those customers
and a significant drop in demand. As a result, the effectiveness of those programs seems to have
peaked.
Irrigation, which represents the majority of Idaho Power's DSM savings, achieved 303 MW peak
demand savings in2016, slightly less than its 2011 and2012 savings of 340 and 320 M[
constituting only 213 of potential DSM savings in this sector. [p. 175]
Commercial peak demand savings reached 1.2 MW for new construction in2014, with no
savings in 2015 or 2016. Retrofits reached 7.8 MW in 2010 with zero subsequent savings in the
following 6 years. I p. 186]
Custom Projects, the largest Industrial sector achieved 9.5 MW in 2010, with marked declines in
the following years, andzero savings in 2015 and 2016. [ibid. p. 187]
ldaho Power: Discussion of Service Area Conservation & Efficiency
In the context of IRP planning, STOP notes that Idaho Power consistently under-targets and
therefore under-plans the savings available through energy efficiency. This skews the planning
effort through an over-inflated statement of need. It does, however, work in the company's
interest as a rationalization of the need for additional infrastructure. This type of planning is not
in the best interest ofthe ratepayers.
A clear example of this is demonstrated in the following slide produced by Idaho Power for its
2017 IRP Advisory Council meetings. Some data has been superimposed for comparison
purposes. The slide below (Program Performance - lncremental IRP Targets) demonstrates how
Idaho Power continuously underestimates its demand side savings. Since 2010,Idaho Power has
significantly underestimated those resources by a rounded 37o/o-the difference between the IRP
targets for energy efficiency and the actual energy efficiency savings2l. If these energy efficiency
and conservation savings were accurately reflected in the 2017 IRP planning and the company's
"need" calculation, there would be a significant reduction in ldaho Power's demand projection22.
" These savings were achieved in conjunction with the Northwest Energy Efficiency Alliance (NEEA).
22 lt is worth noting that as of 2013, there was no demand-side management program implemented by the
company.
STOP B2H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 20 of 35
Idaho Power can obtain much more in the way of energy savings through a more focused effort
around conservation and efficiency. Given the decline in average demand, these untapped
resources combined with the rise of distributed generation (Section 4. Distributed Generation)
would go a long way towards reducing the need to import energy from outside the service area
with all of the expense and risk that involves.
Program Performance -
lncremental IRP Targets
30:--
HIPC Srvlnga (wlth NEEA|
-lRP
TrrgGt3
25t
=6
a
s
GF
EoaED't
ov,
GfEc
"]
trl
s.l
0 T
2002 2003 2004 2005 2006 2007 2008 2009 20't0 2011 2012 2013 2011 2015
33
Idaho Power can obtain much more in the way of energy savings through a more focused effort
around conservation and efficiency. Given the decline in average demand, these untapped
resources along with the rise of distributed generation (Section 4) would go a long way towards
reducing the need to import energy from outside the service area with all of the expense and risk
that involves.
STOP encourages the Commission to review Idaho Power's tepid attempts at conservation and
energy effrciency over the years and to not acknowledge the 2017 IRP until theirAction Plan
reflects improvements.
STOP also asks the Commission to investigate Idaho Power's cost comparisons of demand-side
management versus B2H.
Furthermore, STOP offers the following"CitizenAlternative for Demand Response."
STOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 21 of 35
Gitizen Alternative: Demand Response
Overview
There is little about demand response in the Idaho Power IRP ("ldaho Power 2017 lntegrated
Resource Plan" 20771separate from rate programs, and no broad discussion of an advanced
metering infrastructure or AMI ("The NETL Modern Grid Strategy Powering Our 2lst-Century
Economy: Advanced Metering lnfrastructure" 2008). Most disturbing is the confusion evident in the
one section of the IRP [Appendix B: DSM Annual Report] where initiatives are discussed as
part of the Irrigation Peak Rewards progmm [p. la0]:
Tb participate in the Automatic Dispatch Option, either an advanced metering
infrastructure (AMI) or a cellular control device is attqched to the customer b electrical
panel that allows ldaho Power to remotely control the pumps.
A metering infrastructure is just that, an infrastructure. The advancement comes with the addition
of a backend server hosting a database, virtual private network communications between the
utility and its customers, and digital control surfaces that facilitate those communications at the
service endpoint where the metering is done.
Idaho Power: Demand Response Capability
Idaho Power has installed approximately 500,000 smart meters on residential sites. Advanced
metering has saved countless miles of vehicular travel and the labor of reading meters for billing,
connection and cancellations, as well as providing valuable information about power outages.
The deployment of those meters is, however, only the first step in what is required to
significantly enhance residential demand response savings.
The failure to build-out its AMI puts Idaho Power at ever-increasing risk. It also costs its
customers the savings they would receive from having digitally mediated demand response in
place. As one example, research has shown that smart meters combined with time-of-use pricing
can accomplish peak hour energy savings ofover l0% (Jessoe and Rapson 2015).
STOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 22 of 35
No one is going to attach that framework to a customer's electric panel. Only the node
components and the associated software will reside on customer premises. The utility should get
clear definitions in place so that it can better communicate with its producer-consumers. To do
that, it must train its staffin an understanding of those terms, and consistency in their use.
Idaho Power: Demand Response Needed Upgrades
While ldaho Power often describes its future energy savings plans by saying that 'l...the
landscape has been prepared..."23 the utility must take those next steps. That means build-out of
the required information technology (IT), budgeting for the management of that technology, and
the associated project management costs involved with full integration. That project management
must include obtaining the commitment required of its producer-consumers. While those
elements require a high level of coordination and planning, the benefits can be very significant.2a
Idaho Power: Demand Response Potential Benefits
Many utilities emphasize the research they have conducted into demand response, and their
partnerships in nationally funded pilot programs for solar energy, smart grids and smart meters.2s
Responding to criticism that Idaho Power has been slow to embrace alternative energy sources,
however, the CEO responded at the Boise City Club that even though making large scale
investments would eam the utility a return, they were unlikely to do so "'given that [the utility]
continues to be long on energy" - or have more regular power generation than it usually needs.'
Leaving aside the fact that this hedge brings into question the need for 25Yo more power in20
years, it also suggests that the utility lacks any organized effort to research and employ new
energy saving technologies. Reinforcing this sentiment is the fact that the utility has openly
stated that their research while "not organized or managed as a specific project, ...actively
monitors smart grid-related technology advancements, articles, research, reports, demonstration
projects, and demonstration results as applicable." That sounds like an academic exercise not a
planning effort.
What they have made clear is that "As energy generation, consumption, and management
technologies continue to improve, additional opportunities for the deployment of smart grid-
enabled devices/appliances will become available... []t may be possible to create new products
and services to help Idaho Power manage and optimize its system and help its customers manage
their energy use, consumption, and distributed generation preferences. The areas currently being
" With at least ten years of published research and results of pilot programs already available with details of
substantial savings, Darrel Anderson, addressing the Boise City Club, nonetheless said that the utility is still
"preparing the landscape for future studies of renewables."
'o NV Ene.gy lL,Og6,2L3 residential customers) has initiated dramatic voluntary time-of-use rates. One option
available to their customers is a summer rate of 50 cents on-peak hour, vs. .05 cents off-peak hour for residential
charges. At the end of the year, customers' bills are compared with the charge for regular (non time-of-use) rate
and if time-of-use proves more expensive, the difference in charges is credited to their bills and they may choose to
withdraw from the program.
" Delma.va of Delaware refers to California smart meter pilot studies and Maryland's success with AMI; Florida's
federal grants expanded Florida's smart meterinB system in2012 with dramatic results which PNM (New Mexico)
refers to as catalyst for their successful residential energy savings program. Additionally PNM participated 10 years
ago as one of 15 successful nationally funded pilot programs combining solar with battery storage.
STOP 82H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 23 of 35
monitored include the management and integration of EVs, distributed resources, and
microgrids." 12017 Draft Smart Grid report.l
In other words, the utility is looking for the very business model that is rapidly being adopted by
producer-consumers as they defect from the grid and build partnerships that short-circuit
traditional utilities. That's what the future holds for Idaho Power if it persists in its goal of
absolute control over the production and distribution of electricity. The utility needs to build
parbrerships with its customers, and quickly.
Idaho Power: Demand Response Future
With the electric utility industry in near turmoil, Idaho Power's tentative position in regard to the
rapid and accelerating changes is risky at best and it has the potential to put the future of the
utility in jeopardy. The time for action is now before events over-run their business model.
Regulators must insist that Idaho Power conduct an in-depth analysis of energy efficiency and
actual demand response projects, those that go well beyond Idaho Power's narrow one-size-fits-
all definition of demand management. There is simply too much risk and significant cost
associated with the status quo.
Section 4. Distributed Generation
Lack of Prudency
As detailed in Section 3 above, where tepid attempts have been made at energy conservation and
effrciency, the company seems resistant to emerging models of distributed generation to the point
of forgoing a prudent approach, as reflected in a number of cases before the Oregon PUC.
ln the words of that Commission:
"Prudence is determined by the reasonableness of the actions "based on informotion that
was available (or could reasonably hove been available) at the time."26
Prudent information about this emerging business model is available to ldaho Power. However,
they have not developed a coherent vision of how they can move in this new business world.
They have actively sought to unravel PURPA contracts, while disrupting opportunities to add
solar and battery storage, neglecting distributed generation, failing to renew power purchase
agreements, and destabilizing rooftop solar in their service territory.
25 "Prudence is determined by the reosonobleness of the actions 'bosed on informotion thot wos avoiloble (or could
reosonobly hove been ovoiloble) ot the time."' (ln re PGE, UE 702, Order No. 99-033 ot 36-37.) See olso ln re
Northwest Noturol Gos, UG 732, Order No. 99-697 ot 52: ("ln this review, therefore, we must determine whether the
NW Noturol's octions ond decisions, based on what it knew or should hove known ot the time, were prudent in light
of exi sti n g ci rcu m sto n ces." )
STOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 24 of 35
STOP believes that Idaho Power is not making prudent decisions, in light of a recent BPA
decision which involved the cancellation ofthe I-5 Cotidor Reinforcement Prcject, a 500KV
hansmission line. In his decision letter, the BPA administrator stated that:
"Bonneville is committing to taking aforwardJooking appruachwith its irrestment
decisions, and the region can be certain that BPA will seekfirst to use effciencies and
build at the smallest scale possible to meet our customers'needs, ensuring Bonneville
remains a reliable engine of economic prosperity and environmental sustainability in the
Northwest."
In another development, the Washington State Utilities and Transportation Commission recently
issued a Draft Report and Policy Statement on Treatment of Energy Storage Technologies in
Integrated Planning and Resource Acquisition2T. ln that report, the Commission discussed a
framework for the future:
This requires us to look not just at the bulk power system that is the subject of
integrated resource plans, but at the distribution grid, where state policies and
declining technology costs are likely to both create challenges and offer solutions
over time. Customer-sited generationfacilities and growing demand to charge
electric vehicles, while limited in Washington at present, have the potential to
alter customer usage patterns dramatically and require distribution system
upgrades to provide theJlexibility needed to meet those changing demands.
Where distribution system upgrades were once a relatively simple question of
building additional wires, poles, and transformers, distributed eneg resources
now allow utilities to apply the resource portfulio approach historically used in
integrated resource planning to distribution planning. Despite that point of
commonality, howeveri resource planning on the distribution system remains a
fundamentally different process than integrated resource planning. Where an IRP
considers the costs and benefits of resources at a system or portfulio level, more
granular distribution planning analyzes the costs and bene/its of resources on a
locational basis, with the potentialfor hundreds offinite locations with different
characteristics. IRP models are not designed to do the type of locational analysis
that distribution planning requires, and attempting to incorporate the myriad
additional variables associated with various locations on the distribution system
into an IRP model is simply infeasible.
" oocxets ue-tstosg aruo u-tstoza:
httos://www.utc.wa.eovldocs/Lists/Commission%20Calendar/Attachments205UU-151024%20U8-
15 1059%20DRAFT%20Enerev%2OStorase%20Pol icv%20Statement. pdf
tfOP B2H Coalition Comment on LC 68 ldaho Powers 2017 IRP Page 25 of 35
We therefore intend to address the question of energt storage modeltng on two
levels. In this policy statement, we identify IRP modeling refinements and
competitive procurement practices to ensure that energy storage is fairly
evaluated and procured alongside other resources at the system level. In the IRP
rulemaking, we intend to develop rule language to ensure that energy storage is
fairly evaluated and procured alongside other resources - such as demand
response, energy eficiency, distributed generation and infrastructure upgrades -
at the distribution level.
STOP believes these first 2 points lay out a new prudency where utilities should:
1. Seek first to use efficiencies and build at the smallest scale possible to meet customers'
needs while ensuring utilities remain a reliable engine of economic prosperity and
environmental sustainability.
2. Apply the resource portfolio approach historically used in integrated resource planning to
distribution planning which incorporates distributed energy resources.
Resistance Toward Distributed Generation
Battery storage gets minimal attention since the company only considers it as a "storage
resource." The company refused to include detailed battery storage analysis in any of the
portfolios the 2017 resource plan after being asked several times by Integrated Resource Plan
Advisory Council (IRPAC) members. This is despite the fact that batteries can offer many
important anciltary services28 and will be a significant asset in supporting peak loads in carefully
chosen localities. These ancillary services would provide stability to the grid, particularly given
the volume of expected renewable resources being added to an increasingly decentralized base of
producer-consumers.
Even if batteries do not currently yield the "least-cost" alternative, prices are dropping rapidly.
To exclude a detailed analysis of these resources in the IRP at this time is not in keeping with the
need to identify and estimate the costs of all supply-side and demand-side resource options given
rapid advances in technology.
Distributed generation was a topic at a work session held at an IRPAC meeting. The only
mention of distributed generation is in the IRP portfolios deals with Solar PVA.{atural Gas and
any implementation is beyond the immediate action plan. The soonest any distributed generation
would be put in place is reflected portfolio I l. In that portfolio, solar would be combined with a
reciprocating engine in 2023.
28 http://enersvstoraee.orslsvstem/files/attachments/irp primer 002 0.pdf
SIOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 26 of 35
The ongoing price declines and technological advances in energy generation and distribution
could mean a reduced need for big investments, a better & more prudent strategy. Yet, the 2017
IRP pays minimal attention to distributed generation.
Finally, the company in its 2017 IRP mentions on p 95, that it will not be renewing many of its
power planning agreements within this planning period, even as it seeks to import more power
resources from outside the service area with the line losses that entails.
STOP believes that Idaho Power is not providing a prudent analysis of the future of its industry,
including the valuation of battery storage, ancillary services, solar and Combined Heat and
Power - CHP, and other potential sources of distributed generation in the 2017 IRP. The company
is ignoring the benefits of PURPA, and attempting to significantly alter how net metering works
thus creating disincentives to customers for energy efficiency, while canceling many of its PPA's.
Distributed Generation - lndustrial
As mentioned above, combined heat and power (CHP) systems2eare scantly considered in the
IRP. A measly 35 MW CHP project is discussed in table 6.3 Transmission assumptions and
requirements on p 69 but no implementation schedule is found. The company needs to do more
to look to local producers to meet load where no backbone upgrades are needed for distributed
energy to meet load.
Combined heat and power (CHP) systems, also known as cogeneration, generate
electricity and useful thermal energy in a single, integrated system. CHP is not a
technologt, but an approach to applying technologies. Heat that is normally wasted in
conventional power generation is recovered as useful eneg, which avoids the losses that
would other"wise be incurredfrom separate generation of heat and power Wile the
conventional method of producing usable heat and power sepdrately has a typical
combined fficiency of 45 percent, CHP systems can operate at levels as high as 80
percent.
Idaho Power does not seek to work with industrial customers/users who would like to take
advantage of combined heat and power cogeneration partnerships, helping the utility meet some
of its demand.
Major Customers with Thermal Loads Such as a Potato Plants use Natural Gas to Fire Boilers
and Produce Steam. If Idaho Power were to incorporate CHP at the major customer locations the
natural gas service load to the major customer would shifted to the CHP plant. The CHP plant
would provide the utilities to the major customer, Idaho Power would benefit by freeing up
2e htto://aceee.orgltooics/combined-heat-and-oower-chp
SrOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 27 of 35
resources on the transmission and distribution system serving the major customer. The
environment benefits from the improved effrciency and cleaner burning turbines vs. old boilers
What follows is a list that illustrates elements of a potential partnership:
Idaho Power provides and maintains infrastructure to serve each major customer, therefore, CHP does
not require additional distribution or infrastructure if sized to the major customer load. This is a
1:l energy offset with very little cost to Idaho Power.
Idaho Power could offer a favorable CHP energy rate and Steam / Utility Supply agreement with
Major Customers as an incentive to partner or build CHP. This would mitigate investrnent risk
and provide additional revenue streams for Idaho Power.
Idaho Power could petition the PUC to include a measure similar to the custom efficiency tariffwhich
would collect funds to deploy CHP through the rate classes intended. This is a widely accepted
practice endorsed by the major customer already.
Idaho Power is not at any greater risk of load loss as there are no guarantees any major customer even
without CHP continue to operate or require load. Idaho Power is still obligated to maintain and
provide the resources to supply power to the major customer.
If the CHP customer were to terminate operations ldaho Power would still have an operational Gas
Turbine Facility no different than the current facilities they operate. Additionally, Idaho Power
could use a CHP plant and its thermal capacity to provide storage capacity for other technologies,
Solar Thermal and Wind can be coupled with a CIIP plant and provide export energy out of the
distribution beyond the served load.
Example: Major Food Processor consumes 1OMW of Power and Idaho Power Builds or Contracts for
a l0MW CHP plant to serve the Food Processor electricity and steam. When operating, l0MW of
Distribution capacity is freed up due to the Food Processor being parasitic to the CHP plant.
There would be capacity to allow solar or wind to export out of that distribution point up to the
1OMW parasitic.
Additionally, Solar Thermal and Solar PV could help peak the efficiency of the CHP plant through
generation, preheating and storage which would allow the CHP plant to export energy out of the
substation serving the major customer load. This could represent a free l0MW export potential.
CHP aftached to major thermal loads provides a low cost mechanism for Idaho Power to relieve near
or at capacity distribution and transmission by distributing generation into areas with the greatest
impact.
An additional benefit of CHP is almost always a siguificant reduction in real power losses due to
lighter loadings on the distribution system. Moreover, the cost to deploy CHP is far less than the
cost to build stand alone generation as there are multiple synergies and available assets at major
customer locations already in place.
While Idaho Power, in the 2017 IRP on p 4l asserts some of the advantages, disadvantages, and
costs. It also states:
"Tofind ways to make CHP more economical, Idaho Power is committed to
working with individual customers to design operating schemes that allow power
STOP B2H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 28 of 35
to be produced when it is most valuable, while still meeting the needs of the steam
hostb production process. This would be dfficult to modelfor the IRP because
each potential CHP opportunity could be substantially dffirent."
A promising technology is CHP wrapped around an above-ground compressed air energy storage
installation. This has never been done before, that we know of, but the technology is off-the-
shelf and the economics could probably work given the right host.
STOP asks the Commission to query the individual customers the company has worked with to
evaluate their satisfaction and outcome(s) of this cooperation as we are unaware of any CHP
contracts currently in place.
STOP asks the Commission not to acknowledge this IRP and direct Idaho Power to analyze the
full benefits and valuation of all distributed generation; and, the cost-benefit of these services.
STOP asks the IPUC to encourage Idaho Power to partner with its residential and industrial
customers as a prudent way forward before building new expensive infrastructures.
Furthermore, STOP offers the following Citizen's Alternative.
Gitizen Alternative: Distributed Generation.
Overview
To take advantage of rapidly emerging distributed generation (DG) provided by business and
residential customers within its service area, Idaho Power should re-focus its business model,
provisioning its grid resources to partner with this new class of producer-consumers. The cost of
providing service to those users must be balanced by a thorough valuation of the ancillary
services they provide, including those from storage (Burwen 2016). As part of this process, the
utility has to disaggregate its customer charge into its constituent components in order to
model future services from DG and include the value of those components provided by those
resources. This should be a key part of all future 2O-year integrated resource plans.
Trends
Over the last ten years Idaho Power's electric load has been flat, mirroring the trend at the
national level (Fickling2Dl7) [Figure l]:
STOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 29 of 35
Arcrage Load
10 Year Period
600
500
400
=
3oo
o
200
100
0
2W7 2008 2009 2010 2011 2012
Year
2013 2014 2015 2016
Figure 1 - Idaho Power ryerage load from 2007-1016
Population growth has been matched, step-by-step, by a decline in the average customer load
[Figure 2]:
Residential Custorner Load
Average Use
o
Eo
laEB!z liil llll llllllill
'q, 'qb ?b, %" 2% %> % btt ?ob ?06
Year
Figure 2 - Idaho Power residential customer load 1997-2015
That downward trend is also evident in the utility's additional load from its industrial and
regional customers as they implement conservation and build efficiency [Figure 3]:
STOP 82H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page !10 of 35
Customer Load forn
Micmn, Simplot, lNL, Hoku, Weiser, Raft Riwr
Billed Sales
1,2N
1,m0
800
600
400
m
0 %> "% % ?zo ?ob eo1? eob 4r, 4r" 4r,
Year
Figure 3 - Idaho Power additional customer load2007-2016
This downward pressure is expected to accelerate. Residential and commercial solar arrays with
storage enabled micro-grids will surface a constellation of standalone power resources, as will
battery equipped industrial co-generation facilities. The excess capacity from these resources can
provide utility peaking power on a near instantaneous basis. They should be tapped by the
development of an advanced metering infrastructure (AMI) ("The NETL Modern Grid Strategy
Powering Our 2lst-Century Economy: Advanced Metering Infrastructure" 2008), and by the
strategic placement of additional battery storage to supplement and moderate those coming on-
line from the producer-consumer class.
Business Models for Distributed Generation
Attached storage will lead to a re-working on both the supply and demand sides. The utility
should adapt to these changes over the next two years by developing a new line-of-business, one
that has them acting as the broker for excess DG resources. This will require continuously
recording power production and storage, and modeling their diurnal and seasonal availability. tn
order to facilitate this effort to the greatest extent possible, Idaho Power should leverage an AMI
as the primary vehicle for collectingand analyzing information about grid-attached distributed
generation.
Control surfaces3o at the endpoints of digital networks running in parallel to power flows are
transforming the utility business (Cardwell 2017). Most of the Idaho Power service area has
excellent solar potential and while the utility will see a drop in power demand, it will also see an
'o These are network-attached digital devices including software-enabled smart meters and smart inverters.
STOP B2H Coalition Comments on LC 68 ldaho Powers 2017 IRP Page 31 of 35
E
increase in power available from producer-consumers via those endpoints. Adapting to this
transformation, Idaho Power should plan to increase its purchases of needed power and services
from producer-consumers. The company should also leverage its electric grid in the brokering of
excess power resources as part of this business model.
Valuation of Distributed Generation
First, storage resources offer many benefits that must be included in future IRP calculations.
Once surfaced, the ancillary services provided by storage can be valued using a model developed
by Portland General Electric.3r
Second, the response from strategically placed battery storage mediated by networked
intelligence is for all practical purposes instantaneous with no delay at all. This greatly simplifies
the management of grid power flows, while reducing costly line losses. Mining the data about
these management transactions can surface that value.
Third, a properly provisioned digital grid will enable electricity produced in the service area to
propagate quickly and efficiently, allowing real-time markets for that power to develop and
thrive. That's another benefit that can be quantified by mining the data from Idaho Power's AMI
Lastly, though they are more difficult to quantifii, the most important benefits of DG are
resilience and grid security (Wellinghotr2015). The growth of distributed generation in the Idaho
Power service area can benefit all users through increased operational stability. This should be a
future target for valuation by mining data over the longer term.
Idaho Power must invest in the digital assets necessary to identiff, analyze, and value these
benefits. It short, it needs to build a very different relationship with its customers going forward,
one that builds partnerships with producer-consumers.
Section 5. Conclusion
STOP reiterates one last point:32
"...the plon must be consistent with the long-run public intercst as expressed in Oregon
and federal energt policies. "
31 Flexibility benefits from storage resources are combined with the value of the online capacity from those
resources for a complete accounting of storage and ancillary services:
Net cost of capacity = Total installed cost - Operational benefits (flexibility operations & avoided costs)
32 See Substantive Requirements of Oregon PuC Guidetine 7d
STOP B2H Coalition Comments on LC 58 ldaho Powers 2017 IRP Page 32 of 35
The lack of security from the existing centralized transmission system is not in the long-term
public interest. There is real potential for grid collapse from both natural and human caused
disruption which would leave entire cities without power and very vulnerable. By contrast,
distributed generation installed in vitally important portions of the public and private sector
would still provide those services with power. This is especially important for hospitals, local
governmental units, emergency responders, military bases and military preparedness in general
Distributed generation has other advantages including reliability which is one of Idaho Power's
values in its Vision, Values and Mission statement. A large transmission line like B2H sited
directly next to the current 230KV corridor, would not offer additional reliability given a
catastophic event and the cascading effects that would collapse both lines.
Idaho Power's dubious interest in avoiding the federal transmission corridor and the lack of full
disclosure about its currently available capacity, seemingly to create a new corridor, is out of step
with the current trends in transmission. The cancellation of the I-5 Corridor Reinforcement
Project referenced above is an example.
BPA has not committed any resources to the B2H project other than the initial environmental and
permitting studies, and the agency appears more in step with the long-term public interests of
citizens of the Northwest. By comparison, Idaho Power appears to be taking on a large amount
of risk. If that risk leads to an un-needed transmission line and the debt it carries in the near
future, a likely scenario, the utility's customers will be stuck with the bill. B2H will be a shanded
asset and ratepayers will be on the hook for a long time.
STOP encourages the IPUC to order Idaho Power to re-consider its out-dated, centralized gid
planning at rutepay er expense.
The IPUC should not acknowledge the 2017 IRP until all reasonable alternatives to long distance
transmission have been investigated, including (but not least) Idaho Power's existing
transmission resources and capacities.
In the 2017 IRR ldaho Power maintains a traditional utility model for building new and having a
high rate of return on investment, over 60/o, on a 2IYo share of a $ 1 .2 billion plus transmission
line at the expense of rate payers. Emerging utility business models embrace important new
technologies, including renewable resources, battery storage and the ancillary services they
provide, microgrids and distributed generation, and gteater energy effrciencies.
We do not feel that Idaho Power and its corporate culture are in step with today's rapidly
developing electric industry business models. By contrast STOP has offered up "citizen
alternatives" rooted in innovation and entrepreneurship. Idaho Power should get in tune with
these developments and facilitate the changeover as a producer-consumer oriented company.
Idaho Power can do a better job at developing residential and commercial conservation programs
including smart metering. It can do that while investing in company owned renewable energy
and battery storage, and it can partner with industrial customers before building new
transmission lines. New jobs and careers can be created rather than the temporary employment
Page 33 of 35STOP 82H Coalition Comments on LC 68 ldaho Powers 2017 IRP