20151005Sierra Club Comments.pdf

RECEIVIN
z0lt ocT
UT
FOUNDED 1892
October 5,2015
Idaho Public Utilities Commission
472W Washington St
Boise, lD 83702
Comments on ldaho Power's 2OlS Integrated Resources Plan, Docket#
rPc-E-15-19
Dear Commissioners,
The Sierra Club thanks you for the time you will spend considering these comments
regarding Idaho Power's 2015 Integrated Resource Plan. Sierra Club is America's oldest and
largest grassroots environmental organization, with 1.4 million members and supporters,
including over 2,000 members in Idaho. We hope thatyou will find tlat our comments
suggest a positive solution for some of the difficulties and opportunities that new clean
energy alternatives present.
We recognize and applaud several substantive improvements Idaho Power has made in this
2015 Integrated Resource PIan (lRP). Nonetheless, we believe that changes are needed in
the way transmission and distribution (T&D) system costs are included in the IRP analyses.
Our expectation is that distributed solar generation and enhanced information system
enabled demand management opportunities can facilitate reductions in T&D expenditures.
Updating the IRP analysis to include T&D costs can reveal even more cost-effective resource
alternatives than the IRP currently considers.
WE APPLAUD MULTIPLE IMPROVEMENTS IN THIS IRP
In our estimation, Idaho Power's 2015 IRP is the latest step along a path of continuous
improvement in the Company's recent resource planning activities. The 2015 iteration is the
SIERRA
CLI.JB
Re:
October 5,2015
Page 2 of 13
best IRP yet.
We especially appreciate the personal participation of the Company President, Darrel
Anderson, in setting the goal of a broad and open IRPAC discussion during the development
of this IRP. Kudos also to Phil DeVol and his team for facilitating dialogue and including
feedback and ideas from various stakeholders into this planning process.
While the 2013 IRP attempted to integrate the results of a contemporaneous coal study, the
2015 IRP did a much better job of both integrating the studies and considering a broader
range of coal unit retirement alternatives.
Additionally, compared to previous IRPs, this iteration used vastly improved estimates for
the capacity value and cost of solar PV.3
We also think the feeder line voltage support and thermal energr storage pilot projects are
small but valuable steps into a much-needed closer examination of options at the distribution
system level.
While we greatly appreciate the aforementioned positives, we believe it is necessary to
improve how distributed solar generation is valued.
REDUCED COST OF SOLAR PV NECESITATES NEW ANATYSIS OF COSTS AND
POTENTIAT SAVINGS AT THE TRANSMISSION AND DISTRIBUTION LEVET
Our concerns related to distribution system costs can be summarized as follows:
. It costs a lot to transport electrons from where they are generated to where they are
used.
In the past those costs weren't controllable, but now newly cost-effective distributed
solar generation and demand management may be able to eliminate some T&D costs.
As it's used today, the Aurora cost model does not identify those potential T&D cost
savings.
We believe the IRP cost analysis process needs to be modified so that it reflects the
benefits of distributed solar generation and demand management more fairly.
3 See Idaho Power Company Integrated Resource Plan 2015, figures 7.7 & 7.8,p 90 & 9l respectively
October 5,2015
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GENERATION IS LESS THAN HAIF OF THE COST OF GETTING POWER TO THE
USER
IRPs look out twenty year in to the future. To get a sense of the magnitude of the potential
T&D savings, let's look back twenty years.
Over the last two decades the majority of Idaho Power capital expenditures have been on
transmission and distribution systems, not on generation assets. Of course we expect that
future to be different frorn the past But the figure below shows that during the decades
between 1993 and ?0L3,ldaho Power spent 50% more on maintaining and expandingtheir
T&D assets than they did building out all their natural gas, coal and hydro generation
combined. We believe that distributed solar generation and peak load control can potentially
eliminate some of the transmission and distribution system costs that traditional large-scale
generation couldnlt do without.
600lo of ldaho Power lnvestments during past
20 years have been In distrlbution and
transmission systems vs 4Oolo in generation
$3,0o0,oo0,00o
$2,500,00o,0oo
$2,0o0,o0o,0oo
$1,500,00o,00o
$1,O00,o0o,ooo
$500,000,oo0
$o 6lllfll\(nF{(rtlnNCrlF{6.lOTOTOTOTOOOOOF{Fl(r,rcrr(ncrroooooooF{FldF{NNNNNNN
assets
I Cumulatlve net distribution investment
I Cumulative net transmlsslon lnvestment
I Cumulative net gas lnvestment
ICumulative net hydro lnvestment
f Cumulative net coal investment
A recent Idaho Power publication shows the problem of ignoring opporhrnities to control
T&D expenditures even more sarkly. In the fuly 2015 issue of CONNECTIONS Magazine,
{So*"", tdaho Power Company FERC Form I reports, years 1993 through 2013
October 5,2015
Page 4 of 13
under the heading "We're all in this [Grid) Together" the Company states:
"Only part of your bill goes to pay ldaho Power for the electricity you use. The
majority -- about 70o/o -- actually pays for building operating and maintaining the grid
that reliably delivers your power"
The current IRP analysis method (the Aurora model) focuses on costs to generate enerry and
wheel it into the Idaho Power service territory. It ignores the cost of getting that enerry
transported within the service territory to where it is ultimately used. Updating the cost
analysis method ldaho Power uses to value distribution within its service territory is
essential to appropriately value distributed generation and load management alternatives.
NEW TECHNOLOGY WARRANTS DISTRIBUTION SYSTEM tEVEt REVIEW
An IRP analysis that overlooks the potential to control future expenditures for transmission
and distribution assets needed to serye growing loads ignores two substantial benefits that
new technologies provide:
1. It can't calculate the value of putting solar generation near load
2. It underestimates the potential savings from demand management.
Neither of these outcomes should be acceptable.
The traditional IRP analysis method has used a two-step process. Firs! future system loads
are forecast. Then analyses are performed to determine the best combination generation
and demand side resources to meet those loads. To date the vast majority of load has been
served from remote large-scale generating facilities.
In the past generation was linked to a specific location, often far from the load that
generation would serve. Large hydroelectric generating facilities were located in river
channels. Coal plants were sited at the mouths of coal mines or near rail lines. Gas fired
plants are sited near gas pipelines. Both forms of large thermal plants need to be near a
source of cooling water.
Even the small PURPA renewable generation facilities the Company has experience with
were site constrained [e.g. small hydro at canal drops, wind in energetic locations, combined
heat and power (CHP) at an industrial facility, and digesters near CAFOs).
October 5,2015
Page 5 of l3
We acknowledge that costs for adding new transmission lines have been analyzed for years.
But these new transmission alternatives have been valued primarily as a method to access
other remote generation sources and/or markets.
Back when almost all significant generation alternatives were very site specific, it was
completely understandable to think that expenditures to upgrade transmission and
distribution systems within the service area were not controllable. Those costs were just
required to serve growing loads.
Technological improvements that have dramatically reduced the cost of solar PV require a
change in the IRP cost analysis ground rules. PV can be installed close to load and in
increments sized to match load growth. Especially if combined with some form of demand
control to bring load and generation into tighter alignment, solar and demand management
can reduce the total costs ofgetting energy from source to load.
TO CONTROL T&D COSTS, IOAD GROWTH NEEDS A DIFFERENT ANALYSIS
Transmission and distribution systems are necessarily sized to serve the heaviest (system
peak) loads that are anticipated. On ldaho Power's system those loads occur in the early to
mid summer when extreme temperatures drive air-conditioning residential and commercial
customer loads up while the seasonal irrigation loads are still at their highest. Knowing
where those growing peak loads will occur is key to managing T&D cost growth.
Within the IRP, load is projected by customer classes. The 70tr percentile eners/ sales values
used for planning purposes projects a 3,750,000MWh increase in annual billed sales. The
majority of that increase will come from growth in residential and commercial load.
October 5,2015
Page 6 of 13
classes
Almost 2l3s of load growth over next 2O years to
come from Residential and Commercial customer
I Residential
I Commercial
ffi Irrigation
I Industrial
IAdditional Firm
Not only will residential and commercial customer loads account for most of the growth
expected during the next 20 years, those two classes show the highest inter-day load rises,
which, in turn, drive peak loads.
r Source: Integrated Resource Plan 2015 Appendix C, 70e percentile Load Forecast Annual Summary, pages27 &28
October 5,2015
Page 7 of 13
I i lndustrial Loadj ; trrgatlon Load
I i commerrld Load
i i neslderrtlsl Load
d6f69FO-!EtE*rr*r*I
6
The figure above shows how different customer class loads varied over the twenty-four hour
period (fuly 2, 20L3) when ldaho Power experienced what was at that time its all time
system peak load. Note that while both the Industrial and Irrigation customer loads were
relatively constant over the twenty-four hour period, residential customer load rose more
than 1400/o during the course of the day (from a low of about 580MWs @ Sam to about
1,420MWs @ 7pm). Commercial showed a smaller, but still substantial650/o rise over the
day ffrom about 440MWs @ 5am to about 720MWs @ 3pm).
During the next 20 years the majority of the load growth is expected to come from the two
customer classes that use the most air conditioning and exhibit the largest diurnal load rise
during times of system peak loads. As has been the case for the past decade, peak loads are
projected in the 20LS IRP to continue to grow faster than average load. Since T&D system
size grows to meet peak load, T&D requirements will likely exceed generation growth
between now and 2034. An analysis method that fails to evaluate opportunities to control
T&D cost growth will become even more problematic over time.
9=!9t33=19a-i8!8aE=tI-=|E*=tE*-t-=
u Source: August 7,2OL4IRPAC Advisory Council Meeting Presentation, p 19
October 5,2015
Page 8 of 13
LINKING LOAD GROWTH TO TOCATION
Idaho Power recognizes the role that air conditioning plays in driving system peak loads. We
applaud their decision to run a thermal enerry storage pilot to investigate opportunities to
shift some of the air conditioning load off of the late afternoon/early evening peak load
period. Linking time of use with location of use could make the analysis even more powerful.
As was mentioned above, most of the load growth expected in the next 20 years is forecast to
come from new residential and commercial customers. U.S. Census data forecast most of the
residential growth will be concentrated in urban/suburban areas. Their data suggests that
well over half of all the residential growth in the Idaho Power service area will be in Ada and
Canyon counties.
Existing transmission capacity into the Treasure Valley is constrained in the summer. Use on
the ldaho-Northwestwest-to-east path is limited in the summer by BPA and IPCo loads. The
Brownlee Eastwest-to-east path is similarly constrained in the summer by flows from the
Hells Canyon Complex as well as other BPA and IPCo on ldaho-Northwest path. The ldaho-
Montana north-to-south path is summer constrained by BPA, PAC and IPCo loads and the
Borah West east-to-west path is also full in the summer.T
In preparing their load forecasts the Company uses economic projections scaled at the
county and metropolitan statistical area level (MSe1.e Since they are basing their forecasts
on data collected at the MSA and county level, it should be relatively easy to break out load
growth by region.
Ada and Canyon counties have excellent summer solar resources. With much of the future
Ioad growth expected in the Treasure Valley, it should be possible to compare the cost of
building new solar generation at keys locations within the Valley with the potenfial saving
from avoiding expenditures on new transmission and distribution system assets to serve that
growing load with the total cost of power generated remotely.
7 Source: Idatro Power Company tntegrated Resource Plan 2015, p 64 & 65
t Source: Idaho Power Company Integrated Resource Plan 2015, p 73
October 5,2015
Page 9 of 13
CURRENT ANATYSIS VASTTY UNDER.ESTIMATES COST TO SERVE PEAK
TOADS
In the third chapter of the 2015 IRP the Company provides an indication of how expensive it
is just to provide the generation to serye each of the 9,800 new residential customers they
expect to gain per year over the next twenty years.
"...each new residential customer requires over $1,700 of capital investment for
1.5kW of base load generation, plus an additional $4,400 for the 5 to 6 kW of peak-
hour capacity...(not including)...(o)ther capital expenditures for transmission,
distribution, customer service, and other administrative costs"e
The current analysis also fails to consider the extensive costs in the T&D system (which is
sized to serve system peaks that only occur every fewyears) when valuing demand
management opportunities. In tables and text the Company values energy efficienry (and
presumably demand management) programs based on the
"benefit(s) of the (efficienry and demand side management) program is avoided
energy, which is calculated by valuing the energy savings against the avoided
generation costs of Idaho Powerrs existing marginal resource."lo
Reducing the size of system peak loads saves more than just avoided operation of existing
generation. Growing Peak loads will require more transmission, distribution and peak hour
generating capacity. Solar generation installed at beneficial locations near the areas of future
load growth, combined with demand management programs (like the TES pilot), can reduce
future expenditures on generation, transmission and distribution assets.
o
e Source: Idaho Power Company Integrated Resource Plan 2015, p 25
'o Source: Idaho Power Company tntegrated Resource Plan 2015, p 45
October 5,2015
Page l0 of 13
POSSIBLE IMPLICATIONS: IOWERING BOTH COST AND RISK :
The 2015 tRP is written and we are not trying to change its contents. The examples shown
below are iust meant to be illustrative.
The preferred pordolio
shifu IPCo from a net
seller into net purchaser of
market enerry. The chart
below shows how overthe
course of the Z0-year IRP
horizon Idaho Power shifts
from a net seller in the
market place in 2016 and
202L to a net purchaser in
2026 and 2031. This rising
reliance on market
purchases presents
multiple potential
problems thatwould not
arise had distributed solar
generation been
appropriately valued.
At the highest level "buying" off market, rather than "making" utility owned generation is
inconsistent with the statement made in Chapter 10 of the IRP that
"in the long run Idaho Power believes asset ownership results in lower costs to
customers"l2
At a less theoretical level making more of the energy needed in the Idaho Power service area
rather than buying it offthe marketwould reduce customer exposure to both risks of both
ll Sour"", IdahoPowerCompanylnrcgratedResource Plan2015-Appondix C,p27 &28
12 So*".r Idaho Power Company Integated Resourcs Plan 2015, p 143
11
Rellance on ]ularket Purchasec rlces over IRP
plannlng horlzon
600
500
otr.vI*oooo- 3OO
ooob 200
o
100
o
I Market Sales
I Market Purchases
October 5,2015
Page ll of13
price level and supply adequary.
In the chapter on modeling analysis, the Company notes that in a recent study the Northwest
Resource Adequacy Advisory Committee (MAC) projects a Loss of Load Probability (LOLP)
in the Mid-Columbia market area that rises to an unacceptable level of Bo/oin202t due to
closure of coal capacity at Boardman and Centralia (unless 1,150 MWs of dispatchable
generation is added). |anuary, February and to a lesser extent August are most critical
months for these reliability problems in the Pacific NW region.ta
The question tJrat occurs to us is if capacity NW wide is critical in August why do we believe
that increased access to the Mid-C market will serve as a reliable capacity resource for Idaho
Power?
Buying off the market rather than using fuel-risk free solar generation effectively shifts
additional price risk on to Idaho Power's customers. The benefits of shielding customers
from year to year price adiustments were shown in the risk assessment of year-to-year price
variability in Figure 9.2.14 That analysis clearly shows that Idaho Power customers would be
much better protected from year to year price adjustments if the Company were to build out
more solar (as modeled in Portfolio 3) rather than rely so much on market purchases as in
the preferred Portfolio 6b.
Part of the explanation for why Portfolio 6b was preferred over the more solar reliant
Portfolio 3 was due to Portfolio 3 being evaluated as about $26 million more expensive over
the 20-year periodrs. Using the tipping point analysis shown in Figure 9.316 shows that if
solar PV capital costs were approximately 150/o lower the total portfolio costs would be
reduced by about $25 million.
In other words, if solar capital costs were overstated by t50/o in the 2015 IRP, that
overstatement would account for the entire cost difference between Portfolio 3 and the
Company's preferred Portfolio 6b.
l3 sour""t
t4 sour"",
15 so*""t
'6 so*""t
Idatro Power Company Integrated Resource Plan 2015, p 129
Idaho Power Company Integrated Resource Plan 2015, p 124
Idaho Power Company Integrated Resource Plan 2015, p I l7
Idaho Power Company Integrated Resource Plan 2015, p 125
October 5,2015
Page 12 of 13
Ironically, as explained below, aLSo/o overstatement of solar PV capital cost is almost the
precise amount by which potentially distributed solar was overcharged for "transmission
capital".
Both reciprocating engine powered generators and solar PV can be installed in quantities
that allow interconnection to the distribution system. But the way they were charged for
T&D interconnection in the 2015 IRP does not reflect this equivalence.
Table 6.3 in the tRP shows each utility scale unit of 10MW worth of PV solar is charged with
needing a new 138kv line and substation. The same table shows a larger generator (18MW
of reciprocating engine powered generation) requires no new transmissionlT. Checking the
IRP Technical Report - Appendix C we find that in estimating the cost of 18MW of
reciprocating engine powered generators, they are assessed a transmission capital cost at
$75/kW. The comparable transmission capital cost assessment for 10MWs of utility scale
solar PV is $305/kW18 or an additional $230/kW. As the "plant'' capital costs of solar PV
installed after 20L7 was estimated at $1,250/kW, the extra $230/kW interconnection
assessment represents a capital cost overstatement of L4.Bo/o,te or effectively at50/o
overstatement of solar PV capital costs.
If assessed appropriately for estimated interconnection costs, solar is already as cost
effective and lower risk than the preferred portfolio. If the IRP analysis were updated to
recognize the value of distributed generation's (both PV solar and natural gas fired
reciprocating generators) ability to defer T&D expenditures, solar would likely be viewed
much more favorably. The?}LT lRP needs to eliminate these valuation problems.
Request
In addressing the opening IRPAC meeting Company President Darrel Anderson stated that
one of the Company's goals is to provide power to its customers at fair prices and to do so in
a way that would promote regional growth.
17 Sor."", Idafro Power Company Integrated Resource Plu,r20l5,p72
" source: Idaho Power Company Integrated Resource Plan 2015 - Appendix C, p 85
" $230 / ($1,250 + $305) = t4.Bo/o
October 5, 2015
Page 13 of 13
We take him at his word and ask that you direct the Company to improve the 20L7 IRP in the
following fashion.
First, expand the scope of future IRP alternatives cost analyses to consider all
relevant T&D expenditures, not just generation costs.
Second, make a concerted effort to insure that in the20t7 IRP solar PV costs are
more fairly estimated.
If those two changes were implemented, we believe that the Company will find that investing
in solar generation distributed close to the growing Treasure Valley load is superior to other
alternatives. A shift in Company capital expenditures away from wires and transformers and
redirecting those funds to capital intensive but free fuel solar generation could help meet
both of Mr. Anderson's stated goals.
Zack Waterman
1.
2.
rt*cAlt/br.*
/
Director
Idaho Sierra Club
Mike Heckler