20140220Comments.pdf

KARL T. KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-007 4
[phone]
IDAHO BAR NO. 5156
Street Address for Express Mail:
472W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR )
AUTHORITY TO ESTABLISH A NEW BASE )
LEVEL OF NET POWER SUPPLY EXPENSE. )
)
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CASE NO.IPC.E.I3.2O
COMMENTS OF THE
COMI\flSSION STAFF
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
The Staff of the Idaho Public Utilities Commission comments as follows on Idaho Power
Company's application to set a new base level of net power supply expense ("NPSE").
BACKGROUND
On November l,20l3,Idaho Power Company (the "Company") applied to the
Commission for an Order authorizing the Company to increase its total system "base level"
NPSE from $199,993,778 to $305,684,869.1 ^See Attachment A. The Company would use the
increased NPSE to: (1) update base rates on June 1,2014; and (2) as the basis for quantifying
2OL4l2Ol5 Power Cost Adjustment ("PCA") rates that also would take effect June 1, 2O14. The
Company says the proposed NPSE increase would be revenue neutral for all customer classes,
and would not increase customers' bills. See Application at l-2,3, and 5.
I On November 4,2013, the Company filed an Errata to Application that changed the proposed NPSE from
$304,684,869 to $305,684,869. This Order refers collectively to the application and errata as the "Application."
STAIIF COMMENTS FEBRUARY 2O,2OI4
The Company says it has filed this Application to corect future PCA rates, which the
Company says will be artificially high because the Company's base rates currently recover less
NPSE than the normalized base level NPSE. The PCA is a rate adjustment mechanism that
allows the Company to recover from or return to customers the annual difference between actual
NPSE and the normalized NPSE included in base rates, except for a sharing amount. The
difference is collected from or returned to customers through a rate change each June l. The
base level NPSE consists of Federal Energy Regulatory Commission ("FERC") Accounts: 501,
Fuel (Coal);536, Water for Power; 547, Fuel (gas); 555, Purchased Power; 565, Transmission of
Electricity by Others; and 447 , Sales for Resale. Base NPSE has not been fully reevaluated and
updated since 2010.
The Company proposes to increase base level NPSE to $305,684,869. The Company
says it needs this increase because the NPSE recovery level in base rates is approximately $100
million below the current normal NPSE level. The Company currently recovers these ongoing,
permanent costs through the PCA; but the PCA is designed to let the Company recover (or
return) fluctuating, annual power cost differences rather than long-term, permanent costs.
Therefore, the Company wants to switch recovery of these costs from the PCA to base rates. Id.
at3-4, citing Order No. 32821 (expressing concerns with using the PCA to recover long-term,
ongoing costs).
The Company says the base level NPSE has increased since 2010 for three main reasons.
First, the overall value of the Company's surplus power sales has decreased because lower
market prices have limited the Company's ability to economically dispatch its thermal generating
units. Second, the Hoku special contract ended in2012, and the 2013 base level NPSE thus
excludes Hoku revenue and load. Third, the Company's PURPA-related expenses have
increased by ll3%o since 2010. Id. at 5.
The Company asks the Commission to approve the proposed, base-level NPSE increase
by March 31,2014. The Company says on April 15,2014, it would apply to adjust the
20l4l2OI5 PCA using the updated NPSE, and to increase base rates by the same amount,
effective June l, 2014. The Company explains that its proposal is "revenue neutral" because the
base rate increase would generate the same revenue that the Company otherwise would have
recovered through the PCA. Id. at 6.
Using the PCA's 95.53Vo energy-based jurisdictional allocation, Idaho's share of the
$105.7 million difference in system-level base NPSE would be approximately $101 million.
STAI]F COMMENTS FEBRUARY 20,2014
Because the Company intends its proposal to be revenue neutral, it needs to adjust the $101
million difference to reflect the 95/5 customer-to-company PCA sharing that applies to a portion
of the amount. The total allowed PCA recovery would be $99.3 million. The proposal thus
would result in a $99.3 million base rate increase in Idaho jurisdictional base level NPSE after
$1.7 million in PCA sharing is subtracted. The Company says the "PCA sharing adjustment"
would continue to be reflected in base rates until the Company files its next general rate case or it
otherwise is adjusted by the Commission. Id. at7.
The Company proposes allocating the $99.3 million base rate increase using the PCA
energy allocation method; that is, it would allocate the base rate increase to each customer class
in proportion to the class's annual energy consumption. See Attachment A. Each class would
thus contribute the same revenue to offset the NPSE as it would have contributed through the
PCA. Base rate revenues would increase by $99.3 million while PCA revenues would decrease
by $99.3 million. Id. at7-8.
The Company also proposes to increase the Load Change Adjustment Rate ("LCAR")
from $17.64 per megawatt-hour ("MWh") to $24.34 per MWh to reflect the change in base level
NPSE collected through base rates. The LCAR change would take effect June 1, 2014. Id. at 8.
The Company recounts that the Commission previously ordered it to include transmission
wheeling revenues along with transmission expenses in future PCA calculations. Id. at8, citing
Order No. 32821. The Company reiterates its view that the PCA should not include wheeling
revenues, and says it would be improper to set a base level for the PCA's wheeling revenue
component in this case. Id. at 8-10. In its Notice in this proceeding the Commission found "...
that the transmission wheeling revenue issue is beyond the scope of this NPSE case." (p. 4).
STAFF ANALYSIS
Base Net Power Supply Expense
Base NPSE consists of amounts from the following accounts:
Account 501, Fuel Expense (coal)
Account 536, Water for Power
Account 547,Fuel Expense (gas)
Account 555, Purchased Power (non-PURPA)
Account 565 Third-party Transmission Expense
Account 442,Hoktr First Block Revenue
STAFF COMMENTS FEBRUARY 2O,2OI4
Account 447, Surplus Sales Revenue
Account 555, Purchased Power (PURPA)
Account 555, Purchased Power (demand response incentives)
Fuel expenses, both for coal and gas, non-PURPA purchased power and surplus sales revenue
are derived using the AURORA model. AURORA is an hourly dispatch model that simulates
the operation of the WECC. The model satisfies forecasted loads by economically dispatching
generation resources in light of transmission and resource operational constraints. AURORA
tabulates the Company's costs to operate its resources and other costs and revenues associated
with serving its loads. AURORA considers 85 historic annual water conditions and calculates
annual system costs under each condition. The Company uses the average annual cost as the
"normal" cost when establishing the system base NPSE.
AURORA-Derived Expenses
In reviewing the Company's AURORA results, Staff first examined the Company's
changes to the model inputs since 2010 when base NPSE was last established. Some of the more
significant changes are listed below. [n summary, the Company:
Implemented a new version of AURORA and an updated database that
incorporates new generation resources and loads throughout the WECC;
Added the new, 300 MW Langley Gulch plant to its resource portfolio;
Added a new, non-PURPA power purchase agreement for the 22NNV Neal Hot
Springs project;
Added 490lVfW of new PURPA resources to its portfolio;
Updated heat rates, forced outage rates, plant capacities, O & M costs, and
maintenance schedules for its thermal generation resources consistent with
historic actuals;
Updated its load forecasts, including removing load associated with Hoku;
Modeled wind generation for PURPA facilities and the 101 NIW Elkhorn project
using hourly shapes instead of monthly blocks;
Dispatched the Bridger, Valmy and Boardman coal plants based on a location
within its service territory to better match true historic dispatch decisions;
Updated coal fuel prices consistent with current supply contracts; and
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4STAFF COMMENTS FEBRUARY 2O,2OI4
. Updated gas fuel prices to reflect actual 2013 gas prices through September, with
forecasted prices for the rest of 2013.
Staff agrees with all of the modeling changes and inputs adopted by the Company. Each
change either improves AURORA's accuracy or is too insignificant to materially affect the
results.
Effect of Gas Price on Net Power Supply Expense
Gas price is one of the biggest drivers of NPSE, second only to water conditions. Natural
gas prices affect the Company's NPSE for several reasons. Most obviously, gas prices impact
fuel costs for the Company's gas-fired generation units (Langley Gulch, Danskin, and Bennett
Mountain). Gas prices also affect the cost of gas-fired generation throughout the WECC, thereby
affecting market prices for electricity. Market prices for electricity are critical to the Company
because it buys and sells in the market. High market prices increase the Company's cost to buy
power. But more importantly, high market prices allow the Company to earn more when it sells
surplus power. The reverse is true at lower gas prices. Because the Company sells much more
energy than it buys, higher gas prices yield a benefit to the Company that is passed on to
customers. Stated differently, higher electric market prices benefit the Company because it is a
net seller in the higher-priced market. The benefit of high gas prices compounds because the
Company's coal plants and generators like Langley Gulch are more often economic to operate at
high gas prices; thus, the Company has more power to sell.
Because gas prices are critical to establishing NPSE but can be highly variable and
difficult to predict, Staff analyzed a broad range of natural gas prices ranging from $2.50 to
$6.00 per MMBtu.2 The following graph depicts the results of Staff's analysis. Each major
component of NPSE from AURORA is shown separately. The graph shows that changes in gas
price significantly affect two primary NPSE components - coal-plant costs and market-sales
revenue. The total cost for the Company's coal plants increases as gas prices increase because
the coal plants are dispatched more. The revenue associated with market sales (shown as a
negative expense in the graph below) increases as gas prices increase because market prices
increase with gas price.
2 Staff considered gas prices in southern Idaho near the Company's gas-fired plants. A basis differential (premium)
to Henry Hub of $0.06 per MMBtu was maintained throughout Staff's analysis, consistent with the basis differential
assumed by the Company.
STAFF COMMENTS FEBRUARY 20,201,4
Expense (SOOO1
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s200,000
s150.000
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s2.50 S3.oo s3.50 s4.oo sr.3o s5.oo s5.50
Gas Prke(5/MMBtu)
Adding the NPSE components produces the results shown below. NPSE is highest at gas
prices close to $3.50 per MMBtu, and decreases at either higher or lower gas prices. At low gas
prices, NPSE decreases because market sales revenue is low and coal-plant costs decrease faster
than market sales revenue. Coal-plant costs decrease at low gas prices because coal plants are
dispatched less. At high gas prices, NPSE decreases because revenue from market sales
increases faster than coal-plant costs. Coal plants are usually in-the-money and provide more
generation for market sales. The large dot near the peak of the following graph marks the
Company's proposed gas price and NPSE.
6STAFF COMMENTS FEBRUARY 2O,2OI4
Net Power Supply Expense ($OOO1
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154,000
152,000
150,000
148,000
146,000
14{,000
142,000
140,000
138,000
136.000
134,000
132,000
130,00030,000
S2 s4.00 s4.50 s5.oo s5.50
Gas Prke(9/MMBtul
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Athlgh ges prlccs, ilPSE decrerer
becluse revcnue hom mrrtet
seles donrinetes end hscaser
festcr than coel plent costs. Coal
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thc timc, thus providing nrore
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At low grs prices, IPSE decreases
beceure market sales revenue ls
lorv rnd corl plant o(pcnses
decrcrse fastcr than mrrkct srles
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decrease at low gar prices becruse
coal plents erc disprtdted less.
The current era of very low natural gas prices has created an interesting phenomenon that
the Company probably has not experienced before. Now, any significant change in gas price,
either up or down, decreases the NPSE. ln the past, with gas prices much higher than they are
now, an increase in gas price always decreased the NPSE.
When Idaho Power filed this case, average annual gas prices for 2013 were estimated to
be $3.68 per MMBtu for southern Idaho. Since the Company's filing, wholesale gas prices have
increased sharply due to exceptionally cold weather throughout the country. Forecasts of future
annual prices, however, remain close to earlier estimates. Because future gas prices are not
expected to differ substantially from the estimates in the Company's analysis, and because minor
changes in gas price will have only minimal impact on the Company's NPSE, Staff accepts the
gas price assumption in the Company's analysis.
Effect of PURPA Wind on NPSE
Much of the cost that the Company proposes to shift from the PCA to base rates is
attributable to PURPA payments, and the vast majority of that amount is due to wind projects.
As a result, Staff analyzed how PURPA wind projects impact the Company's portfolio.
STAFF COMMENTS FEBRUARY 2O,2OI4
Using AURORA, Staff determined that including PURPA wind projects in the
Company's portfolio lowers NPSE by $33.9 million. But the Company pays about $85.5 million
annually to buy power from PURPA wind projects. The net cost of PURPA wind to the
Company is about $51.6 million. In other words, the Company could reduce its overall NPSE by
about $51.6 million if it could buy an equal amount of energy from the market or produce that
energy using its own resources.
Shifting PURPA costs from the PCA to base rates will relieve upward pressure on the
PCA due to PURPA. But most PURPA contracts signed since about 2002 - the vast majority
of which are wind contracts - include non-levelized rates. Non-levelized rates escalate during
the life of the contract. Consequently, the amount shifted from the PCA to base rates will
initially zero-out but then immediately resume growing as the nonlevelized rates in the PURPA
contracts escalate. Upward pressure on the PCA due to PURPA will resume even without new
PURPA contracts. Therefore, shifting current PURPA costs from the PCA to base rates will
provide only temporary relief.
Water for Power Expenses
"Water for Power" expense consists of the Company's payments for water stored in
reservoirs that the Company uses to supplement generation at its hydroelectric generating
facilities. The Company proposes to include $2.4 million for Water for Power expense in its
NPSE. Water for Power expense has been maintained at $1.8 million in the last three NPSE
Base Rate Filings.3 This year's $2.4 million Water for Power expense is based on actual water-
lease expenses from January 20 12 through Decemb er 2012. The Company exclude d 20L3 actual
expenses in computing the amount to be included in base NPSE due to poor water conditions and
the lack of available 2013 water leases.
Staff reviewed the 2012 year-end balance for Account No. 536, Water for Power, as well
as the actual expenses for 2OI2 recorded in the 2013 PCA true-up.a Staff also reviewed the 2Ol3
actual expenses for water leases and agrees with the Company that the 2013 expenses should be
3 See Final Orders 31042,32426, and 32585 for NPSE filing for 2OlO-2012.
a See Case No IPC-E-13-10 Comments of the Commission Staff page 7 Final Order 32821.
STAFF COMMENTS FEBRUARY 20,2OT4
excluded in computing a normalized amount. Staff thus agrees with the Company's proposal to
include $2.4 million of Water for Power expenses in the base NPSE.
Purchased Power (Non-PURPA)
Non-PURPA purchased power consists of market energy purchases and power purchase
agreements ("PPAs"). The Company proposes to include $62.6 million in purchased power
costs in the base NPSE, up from $45.5 million in the 2012 base.s The cost of short-term market
purchases is quantified within AURORA, and longer-term PPA costs are quantified outside of
AURORA. Staff has reviewed the Company's reported expenses for 2013 and agrees with the
Company's inclusion of $62.6 million as reasonable.
Third-Party Transmission Expenses
Transmission expenses consist of the Company's payments to other utilities for using
their transmission systems to import power to serve the Company's native load customers and
export power for surplus sales. The Company proposes to include $5.4 million in this year's
NPSE base, down from the $8.2 million in the current base. The Company bases this amount on
actual third-party transmission expenses for January 2013 through August 2013, forecasted
amounts for September 2013 through December 2013, and estimates of purchased power and
surplus sales. The Company averages its transmission estimate with the last six years of actual
third-party transmission expense to provide a normalized value.6
Staff reviewed the Company's 2013 expenses and agrees that the Company's proposal to
include $5.4 million of transmission expenses in the system base NPSE is reasonable.
Hoku First-Block Revenue
Pursuant to Order No. 32585, revenue associated with first-block energy sales to Hoku
have been included as part of the existing NPSE. Because Hoku never started operating its plant
and is now bankrupt, the Company proposes to remove $23.9 million in previously expected
Hoku anticipated revenues from the NPSE.
s See Final Order 32585.
6 See Case No. IPC-E-13-20 Direct Testimony of Scott Wright page 12.
STAFF COMMENTS FEBRUARY 20,2OI4
Staff agrees with the Company that the previously expected Hoku revenues should be
removed from the NPSE. Staff has verified that anticipated Hoku-related load has appropriately
been removed from the Company's AURORA modeling. Therefore, neither the costs nor the
revenues associated with Hoku have been considered in computing the Company's proposed
NPSE.
PURPA Expenses
PURPA expenss consists of the Company's payments to owners of independent power
projects for power under firm energy sales agreements. In accordance with PURPA, the
Company must buy all energy offered for sale by the projects at contractual rates approved by
the Commission. The Company proposes to include $133.9 million of system power supply
costs in the base NPSE. The proposed amount includes $71.0 million paid in 2013 system costs
that have not already been included in the base. Because this amount depends on 2013 costs,
actual PURPA costs in later years may be more or less than the Company's proposed amount.
When future amounts differ, deviations will be captured in future PCAs.
The Company proposes that the base NPSE include only PURPA expenses from existing
projects. As future PURPA contracts are executed, payments associated with those new
contracts will initially be captured in PCAs and eventually in base rates. As Staff previously
discussed, the Company's total PURPA expenses will increase in the future even without new
PURPA contracts as non-levelized rates escalate over the life of the existing contracts. Thus,
shifting current PURPA costs from the PCA to base rates will only provide temporary relief, and
both existing and new PURPA projects will continue to put upward pressure on rates.
Demand Response Incentive Payments
Demand response incentive payments consist of the Company's payments to participants
in its lrigation Peak Rewards, A/C Cool Credit, and Flex Peak demand response programs. The
Company proposes to include $ 1 1.3 million of demand response incentive payments in the
NPSE, which is the same amount that is currently in the NPSE and embedded in base rates. Staff
has reviewed the amount the Company proposes to include and agrees that the amount should
continue to be included in NPSE.
STAFF COMMENTS 10 FEBRUARY 2O,2OI4
Base Rate Revenue Allocation and Rate Design
As previously discussed, Staff accepts a total system normalized base level of NPSE of
$305,684,869. On a total system basis, this amount is $105,691,091 more than the amount last
accepted for ratemaking purposes in Idaho. Based on this amount, Idaho customers will
experience a $99,309,369 increase after jurisdictional allocation and PCA sharing. The amounts
that make up this total are shown in Attachment A.
The example provided as Company Exhibit No. 2 demonstrates that the PCA revenue-
allocation method and the allocation method proposed here (moving the increased NPSE into
base rates) produce the same result. They produce the same result because the increase is
allocated to customer classes on an equal p/kWh basis whether the increase is a base rate amount
or a PCA amount. Staff thus agrees with the Company that moving additional normal NPSE into
base rates is revenue neutral.
There has been some discussion that this case presents an opportunity to move customer
classes toward cost-of-service. Staff disagrees and believes that a cost-of-service move in this
case is inappropriate. A full cosrof-service case cannot be processed before the Company's
mid-April PCA filing, or even before new rates take effect in June. The only cost-of-service
information provided in this case shows how the proposed NPSE difference would flow to the
customer classes in a cost-of-service study. (Idaho Power Company's Response to the First
Production Request of the Industrial Customers of Idaho Power Request No. 1.) It ignores cost-
of-service differences that exist due to amounts in all other accounts. Cost-of-service differences
that existed in the Company's last general rate case (Case No. IPC-E-11-08) generally indicated
high-load factor customer groups are paying less than they would at full cost-of-service. This
was one reason Staff decided to settle that case with large amounts of normal PURPA costs not
included in base rates. Staff recognized that the PCA would pick up these costs and allocate
them to customers based entirely on energy. This result provided balance by allocating more
costs to highJoad factor customers to offset the fact that no other move was being made toward
cost-of-service. Staff does not know what the results of a full cost-of-service study would be
today. Staff believes any cost-of-service move at this point in time is inappropriate.
PCA Calculations
The Company also proposes to update the PCA base to include all normal NPSEs
beginning June 2014. Staff agrees with the proposal. The PCA is designed to capture the
t1STAFF COMMENTS FEBRUARY 20,2OI4
difference between base and actual NPSE. In this specific case, the PCA sharing amount that is
assigned to the Company is excluded from base rates but included in the PCA base. This is
necessary to accomplish the revenue-neutral rate change the Company is proposing. It prevents
the Company from recovering its PCA sharing amount associated with the proposed increase
until that amount is allowed by the Commission.
Finally, the Company proposes to update the LCAR (i.e., the load change adjustment
rate) from 17 .64 $A,IWh to 24.34 $/IvIWh. The LCAR is composed of a numerator that is
measured in dollars and a denominator that is energy. The dollar amount in the numerator has
two components: (1) the average NPSE embedded in base rates, and (2) the average energy
classified fixed production cost embedded in base rates. When these amounts are divided by
average load assumed in the ratemaking process, the resulting rate describes how the two
amounts vary when load changes. The higher LCAR proposed in this case removes more costs
from PCA deferral when loads grow to prevent over recovery of NPSE and fixed production
costs. When loads decline the higher LCAR adds more dollars to the PCA deferral balance to
compensate for under-recovered NPSE and some lost fixed production costs. In this filing, the
Company proposes to update the LCAR numerator to include the proposed base level of NPSE.
Staff supports the update. The PCA mechanism does not work as designed if the proposed
change in NPSE is not tracked through to all of the affected PCA elements.
The Company correctly states that the base rate increase will offset the proposed June 1,
2Ol4PCA decrease. This does not mean that PCA rates will go to zero. There will be a20l3-
2OI4 deferral balance that impacts PCA rates in June and a forecast of abnormal PCA amounts in
the2014-2015 PCA year that will also impact PCA amounts that go into rates on June 1, 2014.
What the Company's proposal does mean is that PCA rates will be $99.3 million dollars less
than they would be without its implementation.
STAFF RECOMMENDATIONS
Staff recommends that the Commission accept the Company's proposal to move normal
NPSE that is now captured in each year's PCA filing into base rates. Staff further recommends
that the full normal NPSE developed by Idaho Power be included in the PCA base and that the
LCAR be set at24.34 $A4Wh. Staff agrees with the Company that these changes should take
effect on June 1,2014.
STAFF COMMENTS T2 FEBRUARY 2O,2OI4
Respectfully submitted this 7d!day of February 2014.
Technical Staff: Keith Hessing
Rick Sterling
Sandra Walker
i:umisc/commentVipcel 3.2Okkkhsw comments
Karl T. Klein
STAFF COMMENTS 13 FEBRUARY 2O,2OI4
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Attachment A
Case No. IPC-E-13-20
StaffComments
02/20/t4
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 2OTH DAY OF FEBRUARY 2014,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-13-20, BY E-MAILING AND MAILING A COPY THEREOF, POSTAGE
PREPAID, TO THE FOLLOWING:
LISA D NORDSTROM
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707
E-MAIL: [e-mail]
[e-mail]
PETER J RICHARDSON
GREGORY M ADAMS
RICHARDSON ADAMS PLLC
515 N 27TH STREET
BOISE ID 83702
E-MAIL: [e-mail]
gre g@richardsonadams. com
TIM TATUM
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707
E-MAIL: [e-mail]
DR. DON READING
6070 HILL ROAD
BOISE,IDAHO 83703
E-MAIL: [e-mail]
CERTIFICATE OF SERVICE