20080520Comments.pdf

DONALD L. HOWELL, II
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 3366
20BSPU Y 2 0 P~I~: 68
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR AUTHORITY )
TO IMPLEMENT POWER COST ADJUSTMENT)
(PCA) RATES FOR ELECTRIC SERVICE FROM)
JUNE 1, 2008 THROUGH MAY 31, 2009. )
)
)
CASE NO. IPC-E-08-7
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilties Commission, by and through its Attorney of record,
Donald L. Howell, II, Deputy Attorney General, respectfully submits the following comments in
response to Order No. 30540 issued on April 25, 2008.
THE PCA APPLICATION
1. Background
On April 15, 2008, Idaho Power Company filed its anual power cost adjustment (PCA)
Application. Since 1993, the PCA mechanism has permitted Idaho Power to adjust its PCA rates
upward or downward to reflect the Company's annual "power supply costs." In a normal year about
half of the Company's generation is from hydropower facilties. Idaho Power's actual cost of
providing electricity (its power supply cost) varies from year to year depending on changes in Snake
River streamflows, the market price of power, and other factors. The anual PCA surcharge or credit
is combined with the Company's "base rates" to produce a customer's overall energy rate.
STAFF COMMENTS 1 MAY 20, 2008
In this PCA Application Idaho Power requests recovery of$119.7 milion of above normal
power supply costs. This represents a 12.8 percent, $87.1 millon increase above existing PCA rates.
2. The Deviation
In its filing the Company proposes a "one-year deviation" from the Commission-approved
90/10 "sharing" of abnormal power supply costs. The Company proposes that the entire varation be
assigned to customers. For the remainder of this PCA year, the Company is requesting that all
deviations in net power supply and PURP A project expenses be recoverable "at 100 percent for both
forecast and tre-up puroses." Said Dir. at 6. Under the Company's proposed 100% alternative, the
forecast rate component would represent a decrease of 0.1314 Ø/kWh. Schwendiman Dir. at 9. The
traditional 90% amount would be a decrease of 0.1183 Ø/kWh. Application at ~ 7; Schwendiman Dir.
at 4-5. If approved, the Company's proposal to not share the forecast cost savings would result in a
one-time credit to customers of$I.8 milion more than the traditional 90/10 sharing. However,
neither the Staff nor the Company can determine the impact of not sharing next year's tre up because
the impact canot be completely known until the end of the tre-up period next March. The amount
deferred for next year's true up could either increase or decrease customer rates.
The prefied testimony of Company witness Greg Said recites several reasons to justify the
"one-year deviation from the standard 90% - 10% sharing of PC A costs." Said Dir. at 6. He asserts
that it would be appropriate for the Commission to allow 100% tracking of net power supply and
PURP A project expenses in this PCA year based upon the "persistent drought conditions (in recent
years), the lack of inclusion of prescriptive hedging activities in PCA forecast methodology, and the
failure ofa number ofPURPA projects to come on-line as envisioned in the last approved test year."
¡d. at 9.
3. S02 Credits
On April 14,2008, the Commission issued Order No. 30529 in the sulfu dioxide (S02) case,
No. IPC-E-07-18. In Order No. 30529 the Commission directed that the majority of S02 revenue that
Idaho Power received in 2007 from the sale ofS02 emission allowances be included in this year's
PCA case. The S02 proceeds of about $16.5 milion will reduce the PCA deferral balance. Given the
timing of the S02 Order, Idaho Power's PCA Application did not include the $16.5 milion PCA cost
reduction from S02 proceeds. Application at ~ 18.
If Idaho Power's PCA fiing is adjusted to include S02 proceeds, Idaho Power calculates that
its anual power costs remain above existing PCA rates. To recover the increased power costs, the
STAFF COMMENTS 2 MAY 20, 2008
Company estimates that the existing PCA rates must increase about $70.7 millon, or an average
increase in the existing PCA rates of approximately 10.36%.
4. Tariff Format
The Company also proposes an administrative change to its Tariff format. The Company
would no longer show the PCA rate on each schedule, but would reference all schedules, by schedule
number, that could adjust customer rates.
Attachment A to these comments is a chart that shows the magnitude of the PCA for each year
since its inception in 1993. For 2008 both the Company and Staff proposals are shown and both
include revenue from the sale of S02 allowances. Attachment B shows a history of Idaho Power's
residential energy rates and identifies the PCA components. The char also shows the Company and
Staff proposals with revenue included for S02 allowance sales.
STAFF AUDIT AND ANALYSIS
The PCA has three components: 1) a forecast component; 2) a true-up component that
corrects for the previous years forecast error; and 3) a tre up of the previous year's tre up that is a
final correction. Set out below are the Staff s comments on the three PCA components.
A. The PCA Forecast
The National Weather Service Northwest River Forecast Center in Portland, Oregon forecasts
the April through July Brownlee Reservoir inflow this year to be 5.40 milion acre-feet (mat). This is
slightly more than the 5.39 maf average (1928 - 2005). A regression equation developed from the
results of a power supply model ru is used to forecast "Net Power Supply Costs." See Order No.
24806 and Staff Attchment C. Using the forecasted 5.40 maf and the regression equation, Staff
calculates Net Power Supply Costs for April 2008 through March 2009, to be $16,255,624. As
authorized by Commission Order, Staff increased the calculated Net Power Supply Costs by expected
PURPA qualifying facility purchases of $93,080,63 i and reduced the amount by the expected net
benefit of cloud seeding $535,250 ($892,084-1,427,334) to generate an expected PCA expense of
$108,801,005. This is approximately $18.7 millon below normal power supply cost levels on a total
Company basis. Staff found that its calculation agreed with Idaho Power's calculation. The
calculation of the forecast rate component is shown on lines 1 through 7 of Attachment D. The
Company's forecast rate component calculation is shown on Line 6 to be -0.1 183 Ø/kWh. Staffs
calculation of the forecast rate component agrees with Idaho Power's calculation when the abnormal
costs are not shared but assigned 100% to ratepayers.
STAFF COMMENTS 3 MAY 20, 2008
However, Staff recommends that 90/1 0 sharing be continued. Sharing is an extremely
importt par of the PCA. It is a tye of Performance Based Ratemaking (PBR) that aligns the
interests of shareholders and ratepayers. It keeps the Company economically involved in power
supply decisions. As previously cited, Company witness Said points to drought, prescriptive risk
management policy and the failure of several PURP A projects to come on-line to support his no
sharing (100/0) proposaL. It is true that the Company has little control over drought, but the Company
has found a way to reduce drought impacts. The Company seeds clouds and to the extent that the
practice causes more water to be available to generate power the shareholders get to keep 10% of the
cost savings. Without an economic interest in cloud seeding results the Company may not have
worked through the process to obtain Commission approval for the program.
It is also true that the Company's Risk Management Program has made market purchases and
sales more prescriptive. The Risk Management Program was largely developed by the Company and
its consultant to address high power supply costs that were assigned to shareholders in the 2000 -
2003 timeframe as a direct result of PCA sharng. The Company had an economic interest in
addressing the concern and took the lead. The Company's curent risk management strategy is not set
in stone. It continues to evolve and improve. Improvements that economically benefit shareholders
continue to benefit ratepayers. If ratepayers were responsible for all abnormal power supply costs this
simply would not be true. Sharing keeps the Company actively engaged in the risk management
process.
Finally, it is also true that some of the PURPA projects included in the Company's last general
rate case (IPC- E-07 -8) that were expected to be online near the end of 2007 are not yet online or even
under construction. This causes two separate economic impacts in the PCA. First, base rates include
contract purchase costs that the Company is not paying. The curent PCA fairly addresses this by
returing these base costs that are not incured to ratepayers. All PURP A cost savings go 100% to
ratepayers. Second, the inclusion of PURP A energy in the base power supply cost calculations
reduces base purchased power costs, base fuel costs and increases base secondar sales revenues.
These power supply cost savings do not materialize when projects remain incomplete. In the PCA
true up, PURP A energy not delivered may be replaced by higher cost energy purchases. Therefore,
the tre up includes higher than normal power supply costs for which shareholders only receive 90%
reimbursement. The end result is that the Company refuds to ratepayers 100% of the PURP A
contract costs that the Company does not have to pay but does not get to pass 100% of the
replacement power costs on to customers. The Company's solution is to not share power supply costs
STAFF COMMENTS 4 MAY 20, 2008
so that shareholders are 100% reimbursed for these costs. However in Staffs opinion, the Company's
solution leaves it with no economic incentive to resolve what is becoming a very large problem of
PURP A developers with signed contracts not delivering.
It is interesting that the inequity that the Company is attempting to solve by eliminating
sharing is the mirror image of a customer inequity that also exists because sharing percentages are
different for PURP A power supply costs (100/0) than they are for other power supply costs (90/1 0).
The more common situation is for PURP A contracts to come online between rate cases when the
contracts are not included in base rates. When this occurs, 100% of the contract costs are passed on to
ratepayers but ratepayers only receive credit for 90% of the benefits. This is also not fair and is the
flp side of the problem the Company is trying to address. There is balance in keeping sharing
percentages the way they curently are. Under one scenaro customers benefit and under the other
scenario shareholders benefit.
In this case Staff continues to recommend that PURP A costs not be shared and that other
power supply costs be shared 90/1 0 between ratepayers and shareholders. Staff also recommends that
this aspect of sharing be discussed in workshops following this case. Once again sharng is important.
Sharing maintains the Company's economic interest in addressing the problem ofPURPA contracts
that do not even come close to meeting their online dates.
Staff recommends 90/10 sharng of all non-PURP A power supply costs. Sharing provides
economic incentive for the Company to address drought, to improve risk management policies and to
improve power supply contractor performance.
Although the Staff calculates the same forecast rates, with and without sharing, that the
Company does, the Staff recommends that this years power supply cost forecast be assumed to be
normaL. This means that the forecast rate would be zero. Staff makes this recommendation for two
reasons. Forecast Brownlee inflow is very near normal Brownlee inflow at 5.40 mafversus 5.39 maf,
respectively. While Staff believes that the cost forecast is much improved over those of the recent
past, we recognize that actual costs wil deviate from the forecast for a variety of reasons. It is counter
productive to retur money to ratepayers based on a forecast that may prove to be inaccurate and then
have to put an increased true-up rate in place the following year that recovers the money previously
given back. The Company has suggested workshops following this case to discuss various elements
of the PCA. The Staff also recommends such workshops. The Staff believes that it is appropriate to
discuss whether or not relatively small rate decreases should be passed on to customers in a forecast
STAFF COMMENTS 5 MAY 20, 2008
rate or whether it is better to wait until power supply cost savings actually occur and captue those
savings in the true up.
B. The PCA True Up
The PCA true up captures the difference between the projected power supply costs from the
past PCA year and the actual power supply costs that the Company incurred during that same year.
Rates were set in the previous PCA period to collect or refud to customers the difference between the
projected power supply costs and those costs reflected in rates. The differences between projected
power supply costs and actual power supply costs is the PCA deferral balance. This deferral balance,
when surcharged or refunded to customers is known as the PCA true-up rate component.
Exhibit NO.3 to Idaho Power witness Schwendiman's testimony ilustrates the calculation of
the true-up deferral amount. To verify revenues and costs associated with Idaho Power's true-up
deferrals, Staff conducted an audit of all actual revenues and expenses that occured during the PCA
year. These revenues and costs included the cloud seeding program, fuel expenses for coal, fuel
expenses for natural gas, and power purchases and sales. Staff also examined the Emission
Allowance Sales Credit and the Risk Management operating plan.
Attchment E is Staffs calculation of the true-up deferral amount. Staffs true-up
recommendation differs from Idaho Power's in two areas, the distribution of base power supply costs
and the Emission Allowance Sales Credit. The following items are included in the PCA tre up.
1. Base Power Supply. Staff recommends a different distribution of the base power supply
costs in the PCA deferral and true-up calculations. This issue was identified due to its impact on
earings. The Staff recommendation has been discussed with the Company. The recommendation
impacts the March deferral in this PCA year and all months in the next PCA year. There are several
reasons for this recommended change. They include the following: The distribution changed
significantly in the 2007 test year underlying the settlement of base power supply costs in Case No.
IPC-E-07-8. This change wil result in a significant shift in Company earings between quarers and
in monthly PCA deferrals compared to historical levels. The distribution is importt in rate cases to
establish the anual power supply dollar cost using the AURORA model for base rates. Although the
anual total power supply cost remains the same, use of the more volatile distribution in the PCA
significantly shifts the level of deferrals between months beginning in March 2008 from that
experienced in prior PCA years. Staff recommends a flat distribution with the issue evaluated as one
STAFF COMMENTS 6 MAY 20, 2008
of the PCA agenda items in the proposed upcoming workshops. In this PCA year the impact will be a
lower PCA deferral for March 2008. Deferrals in the next PCA year will also differ with the spring
months continuing to reflect lower PCA deferrals and the summer months reflecting higher deferrals
but maintaining the same anual base power supply cost. The level distribution for the PCA deferral
reduces earnings volatilty and minimizes arguments to eliminate the 90/1 0 sharing.
2. S02 Proceeds. As shown on page 2 of Attachment E, line 63 in the "Totals" colum, the
true-up amount with interest is $117,637,863. The true-up amount used by the Company to calculate
the tre-up rate did not include the Emission Allowance sales credit of approximately $16.5 milion.
This amount is not included in Company Exhibit NO.3 or Staff Attachment E since they reflect PCA
items through March 2008 and Order No. 30529 on the Emission Allowance Sales Credit issued in
Case No. IPC-E-07-18 on April 14, 2008. Order No. 30529 reserves $500,000 for Commission
decision related to the Idaho Energy Education Project's request. The total Idaho jurisdictional sales
credit of$16,635,022 includes the Idaho Tax reserve of $6,503,462. These Idaho amounts reduced by
the $500,000 reserve and increased by interest through May 2008 of$390,859 results in $16,525,880
to be deducted from this PCA for the Emission Allowance sales credit.
In rounded numbers, the true-up amount is composed as shown below with the Emission
Allowance sales credit included as a separate line item.
Idaho Jurisdictional Items
Last Year's Forecast Revenue
90 % of Last Year's Above Normal Power Supply Costs
Last Year's Above Normal PURPA Facilities Costs
Interest
MILLIONS
$ (15.9)
$ 144.2
$ (14.1)
$ 3.4
True-up Expense (Deferral)$ 117.6
Emission Allowance Sales Credit $(16.5)
Total True-up Deferral with Emission Allowance Sales Credit $ 101.
3. Cloud Seeding Program. Cloud seeding expenses have been recorded in the PCA since
October 2006. In Case No. IPC-E-05-28, Order No. 30035, monthly cloud seeding expenses were
incorporated into base rates. In this PCA period, the cloud seeding expense in base rates is $899,385.
The actual amount of expense for the Cloud Seeding Program for the PCA period from April 2007
through March 2008 is $798,817. Actual expenses are less than the expense in base rates by
STAFF COMMENTS 7 MAY 20, 2008
$100,568. This represents a benefit to customers and is subject to jurisdictional allocation and 90/10
sharing.
4. Fuel Expense - Coal. A large portion of Idaho Power's electricity comes from thermal
power produced from coal plants. The three coal plants that Idaho Power owns an interest in are
Bridger, Valmy, and Boardman. The increase or decrease in the coal expense from base rates is
included in the PCA for recovery from or refud to customers. For the audit period of April 2007 to
March 2008, the total coal expense for all plants in operation is $119,443,355. The total coal expense
included in base rates is $93,724,743. This year's PCA deferral balance includes a difference between
costs curently included in rates and actual costs of$25,718,612. This cost to customers is subject to
jurisdictional allocation and 90/10 sharing.
5. Fuel Expense - Gas. Idaho Power curently owns and operates two gas-fired combustion
turbine generating plants at the Evander Andrews Power Complex (Danskin units) and Bennett
Mountain. These plants are both located at Mountain Home and account for 100% of gas usage.
Actual generation from natural gas is up by 198% over the previous PCA period (roughly three times
the amount of power was generated in this PCA period versus the last PCA period), while the increase
in the actual amount spent for natural gas is up by 155% over the previous PCA period. Last year's
low water may be one reason why the production at these two plants almost tripled during this PCA
period versus the last PCA period. However, there are other factors, such as increased electricity
demand and ruing the plants not only for peak usage, but for off-system sales to the extent the
plants are "in the money", which would also help explain the increased usage of these gas fired units.
For the audit period of April 2007 to March 2008 the total varable gas and gas transporttion
expense for both plants was $20,823,773; up from $8,181,907 during the last PCA period. The total
gas and gas transportation expense included in base rates is $4,707,578. The increase or decrease in
gas expense from base rates is included in the PCA for recovery from or refud to customers. In this
year's PCA deferral balance, the gas expense that is included for future recovery from customers is
$16,116,195 and is subject to jursdictional allocation and 90/1 0 sharing.
The recommendations in Case No. IPC-E-08-1, the addition of the new 170-MW Danskin 1
unit at the Evander Andrews Power Complex in Mountain Home, increases the gas fuel costs in the
base rates. This update of power supply costs should reduce the true-up amount for gas in the next
PCA.
STAFF COMMENTS 8 MAY 20, 2008
6. Power Purchases and Sales. During the PCA year ending March 31, 2008, the Company
sold surlus power totaling $123,157,730. The total surlus sales included in base rates is
$60,273,647. The increase or decrease in the power sales from base rates is included in the PCA for
recovery from or refud to customers and is subject to jurisdictional allocation and 90/10 sharing.
Actual surlus sales exceeded base amounts by $62,884,083. This difference is a benefit to customers
and is subject to jurisdictional allocation and 90/10 sharing.
During the PCA year ending March 31, 2008, the Company made total power purchases,
excluding PURPA contracts, of$233,485,572. The total power purchases included in base rates is
$12,420,544. Actual purchased power amounts exceed base amounts by $221,065,028. This
difference becomes a cost to customers and is subject to jurisdictional allocation and 90/10 sharing.
Staff reviewed the power purchases and sales in conjunction with the Company's Risk
Management Operating Plans. Our analysis did not find any transaction that was not reasonable or
did not follow the Risk Management Committee's recommendations. These transactions were made
with an assortment of credit-worthy parners on a timely basis, and there were no transactions
conducted with an Idaho Power affiliate.
7. Telocaset Wind Power Parters. Beginning in November 2007, Idaho Power began
receiving power from this wind project. Because the project came online durng the middle of the
PCA period, the Company stated it separately as a line item in the PCA deferral calculation. This
wind project was included in base rates in the last general rate case, IPC-E-07-8, Order No. 30508.
The new base rates from this case are included in the base rates for the month of March 2008. The
amount included in this year's PCA deferral is $3,676,418. The costs for this project are subject to
jurisdictional allocation and 90/10 sharing.
8. Actual Qualifying Facilties Purchases including Net Metering. A Qualifying Facilty
(QF) is a generating facilty which meets the requirements for QF status under the Public Utilty
Regulatory Policies Act of 1978 (PURPA) and part 292 of the Federal Energy Regulatory
Commission's Regulations (18 C.F.R. Par 292), and which has obtained certification of its QF status.
There are two types of QFs: cogeneration facilties and small power production facilities. Qualifying
Facilities are sometimes referred to as cogeneration/small power producers or by the acronym CSPP.
A Cogeneration Facility is a generating facilty that sequentially produces electrcity and
another form of useful thermal energy (such as heat or steam) used for industrial, commercial,
residential or institutional puroses, and otherwse meets the requirements of 18 C.F.R. §§ 292.203(b)
and 292.205 for operation, efficiency and use of energy output.
STAFF COMMENTS 9 MAY 20, 2008
A Small Power Production Facilty is a generating facilty whose primar energy source is
renewable (hydro, wind, solar, etc.), biomass, waste, or geothermal resources, and that otherwse
meets the requirements of 18 C.F.R. §§ 292.203(a), 292.203(c) and 292.204. Small power production
facilties are limited in size to 80 MW, with the exception of certain types of facilties certified prior to
1995 and designated as "eligible" under section 3(17)(E) of the Federal Power Act (FPA) (15 U.S.C. §
796(17)(E), which have no size limitation.
Idaho Power has many contracts with qualifying facilities. For the audit period of April 2007
through March 2008 the actual QF expense is $45,143,614. The QF expense included in base rates is
$60,081,272. The increase or decrease in the QF expense from base rates is included in the PCA for
recovery from or refud to customers. In this year's PCA deferral balance, the actual QF expense was
less than the base QF by $14,937,659. This amount is a benefit to customers and reduces the PCA
deferral balance. PURP A contracts are not currently subject to the 90/10 sharing. They are subject to
jurisdictional allocation.
Co The PCA True Up ofthe True Up
The PCA true up of the true-up amount is the difference between what was anticipated to be
collected or refunded when the PCA rate for the true up was set and what was actually collected or
refuded. When special adjustments are not caried into the true up of the true-up calculation, the
amount represents the under or over recovery of the tre-up amount from the previous year due to a
different amount of kWh being sold than was anticipated in the rate design. The tre up of the true up
is a benefit to both the Company and customers because any true up over collection is retued to
customers, and any true up under collection is recovered by the Company.
The true-up amount set for recovery in last year's PCA case (IPC-E-07-10) was $15,090,267
and the rate calculated to retur that amount to customers was 0.1 120 Ø/kWh. With other adjustments
and interest considerations, the approved rate under collected the tre-up amount by $4,862,487. As
shown on Attchment D, line 15, this amount is used to calculate the true up of the true-up PCA rate
component of 0.0361 Ø/kWh. This is the same rate the Company calculated.
PCARATES
The Staffs calculated PCA rate of 0.7864 Ø/kWh is the sum of the three components listed
above (0.0000 + 0.7504 + 0.0361 = 0.7864). This rate is shown on Attachment D, line 18. As
previously discussed, Staff assumes normal power supply costs for the coming year and, therefore,
includes 0.0000 for the forecast rate. The true-up rate, 0.7504, is based on the true-up amounts
STAFF COMMENTS 10 MAY 20, 2008
included in the Company's filing with the additional adjustments of a credit for the sale of S02
allowances and the levelization of March base power supply costs as previously discussed. The true
up of the true-up rate, 0.0361, is the same rate included in the Company's filing. Staff Attachment F
sumarizes all PCA rate components and their associated expense amounts. It also shows amounts
allocated to other jurisdictions and amounts shared with shareholders.
Attachment G shows the proposed average increase above base rates by class and Attachment
H shows the proposed average increase above existing rates by class (last year's PCA rates to this
year's PCA rates). Staff proposes that existing rates be increased by $73.3 milion which produces
and average increase to Idaho Power's customers of 10.7%. This compares to the Company's filed
proposal to increase rates $87.1 milion, 12.8% without the S02 credits.
In both of these attachments the percentage increase to larger customers is substantially more
than the average percentage increase. When power supply costs increase rates, larger customers
receive larger than average percentage increases. This results because large customers have lower
base rates than smaller customers and an equal cents-per-kWh increase makes a larger percentage
difference to them than it does to smaller customers whose base rates are higher.
TARIFF MODIFICATION
The Company also proposes an administrative change to its taiff format. The change would
remove the PCA rate currently shown on each schedule where it applies, but then reference Schedule
55 where the PCA rate is shown along with any other schedules that may also impact the rates
customers on that schedule pay. Some of these other schedules would be the BPA Residential
Exchange Schedule, the Energy Effciency Rider and the Municipal Franchise Fee Schedule. One
advantage of the proposed change is that the Company would not have to refie all schedules every
time the PCA rates change. The Staff supports the tarff change proposed by the Company.
CONSUMER ISSUES
Idaho Power's PCA Application, filed on April 15, 2008, contained both the customer notice
and press release. Staff reviewed them and determined that they complied with the notice
requirements ofIDAPA 31.21.02.102. The customer notice was mailed with Idaho Power's cyclical
billngs beginning April 25, 2008 and ending May 23, 2008. Customers had until May 20, 2008 to
file comments.
STAFF COMMENTS 11 MAY 20, 2008
Informational customer workshops were scheduled in Pocatello, Twin Falls and Boise. Three
customers attended in Pocatello; there were no customers who attended the Twin Falls and Boise
meetings.
PCA RECOMMENDATIONS
Staffhas the following PCA recommendations:
. Staff recommends that 90/1 0 sharng of non-PURP A power supply costs be
continued through the curent PCA year.
. Staff recommends that normal conditions be assumed for the purpose of the PCA
forecast. This results in a 0.0000 forecast rate component to this year's PCA.
. Staff recommends an adjustment to levelize and redistribute base power supply
costs that affect true-up amounts for March 2008. This adjustment reduces the
true-up amount by approximately $15.0 milion.
. Staffhas included the $16.5 milion S02 allowance sales credit that the Company's
initial filing did not include.
. Staff recommends that the Commission accept the administrative tariff
changes proposed by the Company.
. Staff recommends that the Commission convene workshops to discuss various
elements of the PCA.
. Finally, Staff recommends that the Commission accept the proposed PCA effective
date of June 1,2008.
Respectfully submitted this Z iï~ day of May 2008.
Donald L. H ell, II
Deputy Attorney General
Technical Staff: Kathy Stockton
Keith Hessing
Marilyn Parker
Terri Carlock
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STAFF COMMENTS 12 MAY 20, 2008
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Case No. IPC-E-08-7
K. Hessing, Staff
5/20/08
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1
TRUE-UP CALCULATIONS FOR 2007 - 200S
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC.E-ÐS-07
Staff Case
1 2007 2007 2007 2007 2007 2007 2007
2 DESCRIPTION Units APR MAY JUN JUL AUG SEPT OCT
3 PCA Revenue
4 Normalized Idaho Jurisd. Sales MWh 897,400 954,886 1,074,252 1,273,977 1,295,480 1,168,367 996,812
5 Forecast Rate mlKWh -2.507 -2.507 1.888 1.888 1.888 1.888 1.888
6 Revenue $(2,249,782)(2,393,899)2,028,188 2,405,269 2,445,866 2,205,877 1,881,981
7
8 Load Change Adjustment
9 Actal System Firm Load - Adjusted MWh 1,084,842 1,362,862 1,529.771 1,816.224 1.601,848 1,235.732 1,110,759
10 Normalized Firm Load MWh 1,058,845 1,214,518 1,395,617 1,567.783 1,482,896 1,185.594 1,080,868
11 Load Change MWh 25,997 148,344 134,154 248,441 118,952 50.138 29,891
12 Expense Adjustment (~16.84)$(764,572)(4,362,797)(3,945,469)(7,306,650)(3,498.378)(1,474.559)(879,094)
13
14 Non.QF PCA
15 ACTUAL:
16 Water Lease Purchases $0 0 0 0 0 0 0
17 Cloud Seeding Program $38,151 134,410 14,404 20,821 36,610 35,614 32,816
18 Fuel Expense - Coal $7,054,816 6,864,119 9,993,704 10,070,154 10.923,868 10,044,287 10,335,306
19 Fuel Expense - Danskin $218,076 86,161 317,499 1,339,292 1,182,463 107,999 327,875
20 Fuel Expense - Bennett Mountain $476,410 1,030,447 1,546,947 3.628,106 3,913,614 1,507,932 330,946
21 Non-Firm Purchases $16,406,594 18,771,590 30,645,120 37,490,579 34,713,027 19,361,423 12,716,799
22 Telocaset Wind Power Partners $
23 Surplus Sales $(11,789,134)(6,491,031)(17,002,829)(8,336,80)(10,788,903)(14,133,137)(13,708,709)
24 Expense Adjustment (~16.84)$(764,572)(4,362,797)(3.945,469)(7,306,650)(3,98.378)(1,474,559)(879.094)
25 Sub-Total $11,640,341 16,032,898 21,569,376 36,905,822 36,482,302 15,449,559 9,155,939
26
27 BASE:
28 Fuel Expense - Coal $7,095,536 6,786,200 6,342,000 8,714,200 8,720,308 8,448,908 8,726,408
29 Fuel Expense - Danskin $264,800 276,900 275,700 279,600 280,800 264.700 272,300
30 Fuel Expense - Bennett Mountain $32,200 257,100 406,100 253,200 256,700 20,900 22,400
31 Non-Firm Purchases $26,700 586,700 2,715,400 3,166,600 2,765,200 479,300 35.800
32 Surplus Sales $(9,234,000)(6,792,900)(4,831,500)(2,542,200)(3.601.100)(5,736,200)(5,012,200)
33 Cloud Seeding Expense $0 0 0 0 0 0 167,423
34 Cloud Seeding Benefi $0 0 0 0 0 0 (316,667)
35 Sub-Total $(1,814.764)1,114,000 4,907,700 9,871,400 8,421.908 3,477.608 3,895,464
36
37 Change From Base $13,455,105 14,918.898 16,661,676 27,034,422 28,060,394 11,971,951 5,260,475
38 Emission Allowance Sales Credit $0 0 0 0 0 0 0
39 Sub-Total $13,455,105 14,918,898 16,661,676 27,034,422 28,060,394 11,971,951 5,260,475
40
41 Deferrl (Shared and Allocated)$11,395,129 12.634,815 14.110,774 22,895,452 23.764,347 10,139,045 4,455,096
42
43 QF Deferral
44 Actal (includes Net Metering)$3,113,321 4,334,632 6,206,673 6,508,807 6,037,646 4,729.092 3,069,894
45 Base $3,011,503 4,537,814 7,292,829 7,540,664 7,158.661 5,503,768 4,561,853
46
47 Change From Base $101,818 (203,182)(1,086,156)(1,031,858)(1,121,015)(774,676)(1,491,959)
48 Deferral (Allocated)$95,810 (191,194)(1,022,073)(970.978)(1,054,875)(728,971)(1,403,934)
49
50 Total Deferral (-6+41+48)$13,740,721 14.837,520 11,060,513 19,519,205 20,263,606 7,204,198 1,169,181
51
52 Principal Balances
53 Beginning Balance $0 13,740,721 28,578,241 39,638,754 59,157,959 79.421,565 86,625,763
54 Amount Deferred $13,740,721 14,837,520 11,060,513 19,519,205 20,263,606 7,204,198 1,169,181
55 Ending Balance $13,740,721 28,578,241 39,638,754 59,157,959 79,421,565 86,625,763 87,794,944
56
57 Interest Balances
58 Accrual thru Prior Month $0 (3)57,252 176,323 340,150 586,641 917,576
59 Interest ~ 5% per Year $0 57.253 119,076 165,161 246,491 330,923 360,941
60 Prior Month's Interest Adj.$(3)2 (5)(1,334)(1)12 (113)
61 Total Current Month Interest $(3)57,255 119,071 163,827 246,490 330,935 360,827
62 Interest Accrued to Date $(3)57,252 176,323 340,150 586,641 917,576 1,278,403
63 Balance (True-Up & Interest)$13,740,717 28,635,492 39,815,076 59,498,109 80,008,206 87,543,339 89.073,348
64
65 True-Up of the True-Up
66 True-Up Revenues (Collections)$(1,080,306)(1,090,943)(920,299)1,081,301 782,018 692,205 538,019
67
68 Beginning Balance $(7,941,094 )35,396,884 36,635,314 10,570,643 9,533,386 8,791.090 8,135,515
69 Adjustments:
70 2006-07 PCA Transfer (ON 30047)$42,115,280 0 0 0 0 0 0
71 Tax Settlement True-Up (ON 30041:$0 0 (27,025,012)0 0 0 0
72 $0 0 0 0 0 0 0
73 Sub-Total $34,174.186 35.396,884 9,610,301 10,570,643 9,533,386-8,791.090 8.135,515
74 Interest ~ 5% per Year $142,392 147,487 40,043 44.044 39,722 36.630 33,898
75 Revenue Applied to Interest $142,392 147,487 40,03 44.044 39.722 36.63 33,898
76 Revenue Applied to Balance $(1,222,698)(1,238,430)(960,341)1,037,257 742,296 655,575 504,121
77 True-Up of the True-Up Balance $35,396,884 36,635.314 10,570.643 9,533,386 8,791,090 8.135,515 7,631,394
78 Attachment E79Note: Negative amounts indicate benefrt to ratepayers
Case No. IPC-E-08-7
K. Hessing, Staff
U:\khen\ipc087\aff Case\TRUE UP 51151008 KDH 5/20/08 Page 1 of2
TRUE-UP CALCULATIONS FOR 2007 - 200S
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC-E-OS-07
Staff Case
1 2007 2007 2008 2008 2008
2 DESCRIPTION Units NOV DEC JAN FEB MAR TOTALS
3 PCA Revenue
4 Nonnalized Idaho Jurisd. Sales MWh 912,336 1,021,056 1,096,401 1,032,663 1,030,393 12,754,023
5 Forecast Rate mlKWh 1.888 1.888 1.888 1.888 1.888
6 Revenue $1,722,490 1,927,754 2,070,005 1,949,668 1.945,382 15,938,798
7
8 Load Change Adjustment
9 Actual System Firm Load - Adjusted MWh 1,171,433 1,367,764 1,409,978 1,211,697 1,166,380 16,069,290
10 Normalized Firm Load MWh 1,122,464 1,274,108 1,265,091 1.092,645 1,141.512 14,881,941
11 Load Change MWh 48,969 93,656 144,887 119,052 24,868 1,187,349
12 Expense Adjustment (tI16.84)$(1,440,178)(2,754,423)(4.261,127)(3,501,319)(780,731)(34,969,297)
13
14 Non-QF PCA
15 ACTUAL:
16 Water Lease Purchases $0 0 0 0 0 0
17 Cloud Seeding Program $62,605 172,245 32,340 99,952 118,849 798,817
18 Fuel Expense - Coal $10,266,582 10,008,605 11,330.411 11,507,696 11.043.805 119,443,355
19 Fuel Expense - Danskin $65,829 72,176 287,686 28,086 411.179 4,444.320
20 Fuel Expense - Bennett Mountain $275,503 802,330 1,893,792 704,891 268,535 16,379,453
21 Non-Firm Purchases $15,620,132 10,927,735 15,938,927 7,080,919 13,812.727 233,485,572
Telocaset Wind Power Partners $3,540 737,892 1,254,886 991,420 688.679 3,676,418
23 Surplus Sales $(8,439,918)(891,111)(10.334,789)(5,317,445)(15,924.244)(123.157,730)
24 Expense Adjustment ((Q16.84)$(1,440,178)(2,754,423)(4,261,127)(3,501,319)(780,731)(34,969,297)
25 Sub-Total $16,414,095 19,075,450 16.142,127 11,594,201 9,638,800 220.100,910
26
27 BASE:
28 Fuel Expense - Coal $8,442,408 8,726,608 8,453,508 7,372,808 5,895.851 93,724.743
29 Fuel Expense - Danskin $264,400 273,100 272,200 257,500 201,811 3,183,811
30 Fuel Expense - Bennett Mountain $6,100 99,700 51.100 26.300 91,967 1,523,767
31 Non-Firm Purchases $603,000 841,100 387,500 84,000 729,244 12,420.544
32 Surplus Sales $(1,419,600)(3,443,800)(5,889,800)(7,776.100)(3,994,247)(60,273,647)
33 Cloud Seeding Expense $167,423 167,423 167,423 167,423 62,270 899,385
34 Cloud Seeding Benefit $(316,667)(316,667)(316,667)(316,667)(117,779)(1,701,114)
35 Sub-Total $7,747,064 6,347,464 3,125,264 (184,736)2,869,118 49,777,490
36
37 Change From Base $8,667,031 12,727,986 13,016,863 11,778,937 6,769,682 170,323.420
38 Emission Allowance Sales Credit $0 0 0 0 0 0
39 Sub-Total 8,667,031 12,727,986 13,016,863 11,778,937 6,769,682 170,323,420
40
41 Deferral (Shared and Allocated)$7,340,109 10,779,331 11,023,981 9,975,582 5,769,800 144,283,461
42
43 QF Deferral
44 Actual (includes Net Metering)$2,263,447 2,603,216 2,242,484 2,143,913 1,890,490 45,143,614
45 Base $3,239,593 3,483,863 3,036,410 2,957,595 7,756,719 60,081,272
46
47 Change From Base $(976,146)(880.647)(793,926)(813,682)(5.866,230)(14,937.659)
48 Deferral (Allocated)$(918,554)(828,689)(747,084)(765,675)(5.555,320)(14,091.534)
49
50 Total Deferral (-6+41+48)$4,699,065 8,022,889 8,206,892 7.260.239 (1.730,902)114,253,128
51
52 Principal Balances
53 Beginning Balance $87,794,944 92,494,009 100,516,898 108,723,790 115,984,030
54 Amount Deferred $4,699,065 8,022.889 8.206,892 7,260,239 (1,730,902)114,253,128
55 Ending Balance $92,494,009 100,516,898 108,723,790 115,984,030 114,253,128
56
57 Interest Balances
58 Accrual thru Prior Month $1,278,403 1,644,230 2,029,641 2,448,452 2,901,468
59 Interest tI 5% per Year $365,812 385,392 418,820 453,016 483,267 3.386,153
60 Prior Month's Interest Adj.$14 20 (10)(0)0 (1,418)
61 Total Current Month Interest $365,827 385,412 418,811 453,015 483,267 3,384,734
62 I nterest Accrued to Date $1,644,230 2,029,641 2,448,452 2,901,468 3,384,734
63 Balance (True-Up & Interest)$94,138,239 102,546,539 111,172,243 118.885,497 117 ,637,863 117.637.863
64
65 True-Up of the True-Up
66 True-Up Revenues (Collections)$687,700 414,019 642,705 614,877 545,264 2,906,562
67
68 Beginning Balance $7,631,394 6,975,491 6,590,537 5,975,292 5,385,312 (7,941,094)
69 Adjustments:
70 2006-07 PCA Transfer (ON 30047)$0 0 0 0 0 42.115,280
71 Tax SettlementTrue-Up (ON 30041)$0 0 0 0 0 (27,025,012)
72 0 $0 0 0 0 0 0
73 Sub-Total $7,631,394 6,975,491 6,590,537 5,975,292 5,385,312 7.149,173
74 Interest tI 5% per Year $31,797 29,065 27,461 24,897 22.439
75 Revenue Applied to Interest $31,797 29,065 27,461 24,897 22,439 619.875
76 Revenue Applied to Balance $655,903 384,955 615,245 589,980 522,825 2,286,687
77 True-Up ofthe True-Up Balance $6,975,491 6,590,537 5.975.292 5,385,312 4,862,487 4.862,487
78 Attachment E79Note: Negative amounts indicate benefit to ratepayers
Case No. IPC-E-08-7
K. Hessing, Staff
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5
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24
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3
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i
00i..
1
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 20TH DAY OF MAY 2008,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-08-7, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
BARTON L KLINE
DONOV AN E WALKER
IDAHO POWER COMPANY
POBOX 70
BOISE ID 83707-0070
E-MAIL: bkline(fidahopower.com
dwalkeraYidahopower,com
JOHN R GALE
GREGORY W SAID
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: rgale(fidahopower.com
gsaid(fidahopower ,com
PETER J RICHARDSON
RICHARDSON & O'LEARY
515 N 27TH STREET
PO BOX 7218
BOISE ID 83702
E-MAIL: peter(frichardsonandoleary.com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: dreadingaYmindspring.com
\SdLJt.~
SECRETARY
CERTIFICATE OF SERVICE