20110518Comments.pdf

DONALD L. HOWELL, II
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 3366
RECë.\VE.O
iO\\ t\~ 1 \ 1 l~ 4: 5\
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
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 1,2011
THROUGH MAY 31, 2012.
)
) CASE NO. IPC-E-11-06
)
)
) COMMENTS OF THE
) COMMISSION STAFF
)
COMES NOW the Staff of the Idaho Public Utilties Commission, by and through its
Attorney of Record, Donald L. Howell II, Deputy Attorney General, and submits the following
comments in response to Order No. 32227 issued on April 21, 2011.
BACKGROUND
Idaho Power Company fied its anual power cost adjustment (PCA) Application on April
15,2011 for rates to become effective June 1,2011 through May 31, 2012. The PCA is a
symmetrical rate adjustment mechanism that anually adjusts rates to recover a portion of above
normal power supply costs from customers, or refund a portion of below normal power supply
costs to customers. Idaho Power calculates the total PCA revenue reduction to be approximately
$40.4 milion which would result in an average rate decrease of approximately 4.78%. The total
PCA rate (Schedule No. 55) is combined with the Company's other base rates to determine a
customer's overall billng rate.
STAFF COMMENTS 1 MAY 17,2011
IDAHO POWER COMPANY'S FILING
The Power Cost Adjustment (PCA) Mechanism
The anual PCA mechanism is comprised of three components: 1) a "forecast" that
estimates the difference between normal power supply costs embedded in base rates and the
coming year's power supply costs; 2) a "true-up" that captures the difference between the previous
year's projection and actual power supply costs; and 3) a "reconciliation" of the previous year's
true-up to capture the unecovered or under-refuded amount. Each component is described in
more detail below.
1. The Forecast. Forecasted power supply costs for the coming year are based on the
Company's most recent Operating Plan. The difference between forecasted and actual power
supply cost is calculated. The power supply cost difference is converted to a cents per kilowatt-
hour (~/kWh) rate by dividing the power costs by energy sales. In this fiing the Company
calculates above normal power supply costs of $4.6 milion relative to power supply costs
contained in curent base rates. After the PCA 95/5 sharing, this produces rates to recover
projected above normal power supply costs of 0.0445 ~/kWh.
2. The True-up. The true-up amount is the difference between normal and actual power
supply costs during the previous year. The amount is offset with revenue from the forecast rate.
The previous year's PCA amount is not precisely recovered due to actual power supply costs being
different than forecasted power supply costs. The true-up amount is converted to a ~/kWh rate by
reducing the deferral balance by the SOz credit, and dividing by projected energy sales. Idaho
Power calculates the true-up amount and surcharge rate to be $3,689,374 and 0.0273 ~/kWh,
respectively.
3. The Reconcilation. The reconcilation of the true-up tracks the recovery of the previous
year's true-up amounts. It nets the actual revenue collected from the true-up rates against the
amounts set for recovery. Any difference is carried into the following year's tre-up reconcilation
along with the true-up difference. Idaho Power calculates the reconcilation of the true-up amount
and rate to be a credit of$18,152,666 and 0.1347 ~/kWh, respectively.
In summary, the total PCA rate for each class wil be the combination of the three PCA rate
components discussed above, and an Energy Effciency Rider Recovery rate. The combination of
the three traditional PCA components produces a 201112012 PCA rate credit (discussed below) of
0.0629 ~/kWh (0.0445 + 0.0273 -0.1347). The Energy Efficiency Rider rate component is not
spread on an equal ~/kWh basis and is different for each class (see Company Exhibit No.2).
STAFF COMMENTS 2 MAY 17,2011
Energy Effciency Rider Recovery
In Case No. IPC-E-1O-27, the Commission authorized recovery of$lO milion in the PCA
for DSM expenditures previously deemed prudent through 2009 and curently deferred in the
Energy Efficiency Tariff Rider account (Order No. 32217). When allocating the DSM
expenditures in the PCA, the Commission ordered the Company "to separate the DSM
expenditures and allocate them to each customer class based on the amount that would have been
recovered from each class through the Rider." Order No. 32217 at 6. Idaho Power allocated $10
milion among the customer classes based on forecasted base revenue for the PCA year (June 1,
2011 through May 31, 2012). The component surcharge rate for tariff customers ranges from a
low of 0.0391 ~/kWh to a high of 0.2084 ~/kWh (Company Exhibit No.2).
STAFF AUDIT AND ANALYSIS
A. The peA Forecast or Projection
The Operating Plan used to forecast power supply costs is based on the Company's most
current information available. It takes several factors into consideration such as water conditions,
gas hedges, market purchases, transmission availabilty, and the SOz and Renewable Energy Credit
markets. Throughout the year a Risk Management Committee (RMC) comprised of key
employees reviews the Company's risk management policy. An account by account breakdown of
the Company's power supply expense forecast is shown on Attachment A to these comments. The
char shows expenses included in Base Rates, Forecasted Expenses and the Difference. Account
555 - PURP A Purchase Expense is shown separately from other Account 555 Non-PURP A
Expenses because differences in PURP A Expenses are not shared and the entire difference is
passed on to customers.
Attchment B shows Staffs calculation of the PCA rate. Line 1 through 15 shows the
calculation of the Forecast Rate. Line 3, Column (e), shows the forecast offset due to expected
Hoku first block revenues. Line 4, Column (e), shows an expected reduction in power supply costs
associated with the sale of Renewable Energy Credits (REC) and SOz Emission Allowances. Line
6, Column (f), shows the 95% sharing percentage that is applied to all power supply cost
differences, except PURPA costs. Line 9, Column (g), shows the forecast rate excluding the
portion of the forecast rate associated with the expected PURP A cost difference. This forecast
component rate is negative 0.2167 ~/kWh. Lines 11 through 13 show the calculation of the portion
of the Forecast Rate associated with the expected difference in PURPA costs. This component rate
STAFF COMMENTS 3 MAY 17,2011
is 0.2612 ~/kWh. These two components combine to produce the power supply forecast rate of
0.0445~/kWh shown on line 15. Among other things, this rate reflects water conditions that are
expected to be well above normaL. While Idaho Power conducts its own water forecast, the
Northwest River Forecast Center confirms that the April through July Brownlee Reservoir inflow
is expected to be 144% of normaL. Although this year's forecasted rate is proposed to be
substantially lower than last year's forecasted rate, power supply costs are stil projected to be
approximately $4.6 milion above normaL. This is primarily because the Company expects its
PURPA Expenses to be $36.9 milion above the PURPA Expenses included in base rates ($62.8
milion).
B. Irrigation Peak Rewards Program
The Irrigation Peak Rewards Program is a voluntary load control program available to
irrigation customers. It is used to decrease the Company's system summer peak load by turning
off paricipating irrigation pumps during the period of June 15 through August 15 for a few hours
at a time. This demand response program is dispatchable, reliable, and less expensive than heavy
load hour market purchases.
The Staff monitors the Company's use of the Program because it directly impacts anual
power supply costs, and ultimately the PCA rates paid by customers. When the Company
purchases power durng heavy load hours instead of interrpting as allowed by the Program, power
supply expenses are higher than they otherwise would be. One of Staffs objectives is that the
"operational potential of the (Peak Rewards) Program be fully utilized." Case No. IPC-E-I0-46,
Staff Comments, p. 3. During the 2010 Program season, paricipants were interrpted for 12 hours
out of 60 potential hours, or 20% of potential hours. Consequently, Staff encourages the Company
to lower its power supply costs by using more curtailment hours in the Irrigation Peak Rewards
Program.
C. The peA True-Up
The PCA true-up captures the difference between actual and projected power supply costs
experienced in the past year. With some adjustments, this difference becomes the PCA true-up
deferral balance. This deferral balance divided by expected kWh sales is known as the PCA
true-up rate component.
Page 1, lines 4 through 78 of Company Exhibit No. 1 calculates the true-up deferral amount
of$4,181,114. Attachment C to these comments is Staffs verification of the Company's true-up
deferral calculations. In Order No. 30715 (Case No. IPC-E-08-19), the Commission authorized
STAFF COMMENTS 4 MAY 17,2011
Idaho Power to redistribute monthly base power supply costs in a specific maner to meet financial
reporting needs of the Company. The monthly redistribution was to leave annual base power
supply costs unchanged, which it has. Company Exhbit No.1, page 3, shows the deferral
calculation using base power supply costs before redistribution. The difference between the
deferral balance shown on page 1 of Exhibit No.1, and the balance shown on page 3 of Exhibit
No. 1 is due to the base power supply costs being updated beginnng June 2010 (Order No. 31042)
(Case No. IPC-E-lO-Ol). Had the base components been in place for the whole PCA year the two
deferral balances would be equal. Thus, Staff finds the Company's calculation as shown on page 1
of Exhibit No. 1 to be correct.
To verify revenues and costs associated with Idaho Power's true-up deferrals, Staff
conducted an audit of actual revenues and expenses that occured during the PCA year. These
revenues and costs included water lease expenses, fuel expenses for coal, fuel expenses for natural
gas, power sales and purchases, third-party transmission expenses, Hoku First Block Energy
revenues, green tag Sales Credit/RECs, and Qualifying Facilties expenses. Staff also examined
the sale of SOz Allowances passed onto customers. The Risk Management Operating Plans and
RMC minutes were also reviewed.
The following items are included in the PCA true-up:
1. Load Change Adjustment. This year's true-up calculation includes a negative Load
Change Adjustmentl of $19,469,566. Actual loads during the tre-up year were below normal
loads in 10 of 12 months. The total below normal load was 731,114 MWh. This represents a 4.7%
load decline. The load change adjustment is the product of the negative load growth and the load
change adjustment rate (LCAR) of $26.63/MWh. The LCAR is composed of the variable and
fixed costs of production embedded in base rates. When load grows the adjustment reduces power
supply costs to avoid double counting production costs. When load declines the adjustment
reimburses the Company for a portion of lost fixed production costs and makes the Company
whole with respect to variable production costs except for the PCA sharing amounts. The result is
that $19,469,566 milion (before Jurisdictional Allocation and PCA sharing) has been added to the
deferral balance for recovery from customers in this year's PCA. Staff notes that the Commission
modified the LCAR calculation in Order No. 32206 and its impact wil be considerably less in
future PCAs. The Staff reviewed the new LCAR proposed by the Company. The calculations
1 The Load Change Adjustment was formerly known as the "Load Growth Adjustment" and was intended to eliminate
recovery of load deviations due to weather, customer growth, or changing customer usage patterns. Larkin Direct 12-
13.
STAFF COMMENTS 5 MAY 17,2011
were revised in the response to a Staff Audit Request. The Staff recommends approval of the
revised LCAR of 19.67 $/MWh.
2. Water Leases. The Company leases water for the production of power from several
entities. The increase or decrease in the water lease expense from base rates is included in the
PCA for recovery from or credit to customers. This year's PCA deferral balance includes actual
water lease expenses of$2,055,185 and the amount included in base rates is $1,587,623, with the
difference of $467,562 included in the deferral balance. This increase in water lease expenses
from base expenses is a cost to customers and is subject to jurisdictional allocation and sharing.
3. Fuel Expense - CoaL. A large portion of Idaho Power's electricity comes 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 credit to customers. For the audit period of April 2010 to March 2011, the total
coal expense for the three plants is $138,868,030. The total coal expense included in base rates is
$163,327,463. This year's PCA deferral balance includes a difference between costs currently
included in rates and actual costs of $24,459,433. Thus, this reduction in coal costs from base
costs is a credit to customers and is subject to jurisdictional allocation and sharing.
4. Fuel Expense - Gas. Idaho Power currently owns and operates several gas-fired
combustion tubine generating plants at the Evander Andrews Power Complex (3 Danskin units)
and Bennett Mountain. These plants are located at Mountain Home and account for 100% of the
Company's natural gas usage.
For the audit period of April 2010 to March 2011, the total variable gas and gas
transportation expense for all the gas plants was $12,921,516. The total gas and gas transportation
expense included in base rates is $6,084,896. This increase in gas expense from base rates is
included in the PCA. In this year's PCA deferral balance, the additional gas expense that is
included for future recovery from customers is $6,836,620 and is subject to jurisdictional
allocation and sharing.
5. Power Sales and Purchases. Staff reviewed the power purchases and sales in
conjunction with the Company's Operating Plan. Staff 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 affliate.
STAFF COMMENTS 6 MAY 17,2011
a. Power Sales. During the PCA year ending March 31, 2011, the Company sold off-
system surplus power totaling $70,077,566. The total surplus sales included in base rates is
$96,181,927. This decrease in the power sales from base rates is included in the PCA. Actual
surlus sales were less than base amounts by $26,104,361. This reduction of revenues is a cost to
customers and is subject to jurisdictional allocation and sharing.
b. Power Purchases. During the PCA year ending March 31, 2011, the Company made
market power purchases, excluding its PURP A contracts. The total amount of power purchases is
$77,085,070. The amount of power purchases included in base rates is $65,523,728. Actual
purchased power amounts exceed base amounts by $11,561,342. This difference is a cost to
customers and is subject to jurisdictional allocation and sharing.
6. Third-Pary Transmission. In Order No. 30715 (Case No. IPC-E-08-19), the
Commission found that third-pary transmission costs that are incurred in conjunction with market
purchases and off-system sales should be tracked through the PCA like other variable power
supply costs. Including transmission expenses in the PCA is a straightforward treatment of power
supply costs that fluctuate with power purchases and sales.
For the audit period of April 2010 to March 2011, the actual third-pary transmission
expense is $5,812,011. The third-pary transmission expense included in base rates is $8,587,977.
Thus, this year's PCA deferral balance includes the difference between actual costs and base rate
costs of $2,775,966. Because the actual costs are less than the amount included in base rates, this
amount represents a benefit to customers. This benefit to customers is subject to jurisdictional
allocation and sharing.
7. Hokuz First Block Energy. In Order No. 31042 (Case No. IPC-E-I0-0l), the
Commission re-established the level of power supply costs included in base rates beginning June 1,
2010. In that Order, the Commission accepted the Staffs recommendation that Hoku loads and
First Block revenues be excluded from net power supply costs included in base rates. This
treatment causes all Hoku actual power supply costs and offsetting First Block Revenues to be
captured in the PCA true-up deferral calculation. The deferred First Block Revenue of $26,961
shown on line 22 of Attachment C is a benefit to customers and is subject to jursdictional
allocation and sharing.
8. Renewable Energy Credit Sales. In Order No. 30818 (Case No. IPC-E-08-24), the
Commission ordered that revenues from the sale of renewable energy credits (RECs or green tags)
2 Hoku Materials is a special contract customer with a poly silcon production facilty in Pocatello.
STAFF COMMENTS 7 MAY 17,2011
benefit customers, subject to jurisdictional allocations and sharing. The amount included in the
deferral balance is $5,649,119 and is a benefit to customers.
9. Actual PURP A Purchases Including Net Metering and Raft River. A Qualifying
Facility (QF) is a generating facilty which meets the requirements for QF status under the Public
Utilty Regulatory Policies Act of 1978 (PURPA) and Par 292 of the Federal Energy Regulatory
Commission's Regulations (18 C.F.R. Par 292), and has obtained certification of its QF status.
There are two types of QFs - cogeneration facilties and small power production facilties.
For the audit period of April 2010 through March 2011, the actual PURP A expense is
$64,792,474. The PURPA expense included in base rates is $63,051,665. The difference in the
PURP A expense from base rates is included in the PCA for recovery from or credit to customers.
In this year's PCA deferral balance, the actual PURP A expense was more than the PURP A expense
included in base rates by $1,740,809. This amount is a cost to customers and increases the PCA
deferral balance. PURP A contracts are not currently subject to sharing, but they are subject to
jurisdictional allocation.
10. SOi Credits. In Order No. 32162 (Case No. IPC-E-1O-20), the Commission ordered
that $490,498 in jurisdictional SOz funds be used to offset the Company's PCA deferral balance in
this PCA year. SOz Credits are subject to jurisdictional allocations and sharing. After including
interest, the SOz revenues included in the deferral balance this year are $491,740.
STAFF COMMENTS 8 MAY 17,2011
The true-up Deferral Balance is composed of the following Components:
Load Change Adjustment $19,469,566
Water Leases $467,562
Fuel Expense - Coal $(24,459,433)
Fuel Expense - Gas $6,836,620
Surlus Sales $26,104,361
Non-Firm Purchases $11,561,342
Third Pary Transmission $(2,775,966)Hoku Energy $(26,961)
Subtotal- Change from Base $37,177,090
Renewable Energy Credit Sales $(5,649,119)
Subtotal - Subject to Jurisdictional Allocations & Sharing $31,527,971
Subtotal- After Jurisdictional Allocations and Sharing $28,447,098
Qualifying Facilties - After Jurisdictional Allocations $1,655,493
Total all Expense Items $30,102,591
Less Jurisdictional Forecast Revenue $25,952,179
Deferral Balance $4,150,412
Interest on the Deferral Balance $30,702
Sale of SOz Credits $(491, 7 40)
Deferral Balance (True-Up) $3,689,374
The Company-proposed true-up rate surcharge is 0.0273 ~/kWh. The Staff calculates the
same rate as shown on Staff Attachment B, line 22.
D. The Reconcilation of the True-Up
The reconcilation of the true-up3 amount is the difference between what was approved to
be collected or refuded when the PCA rate for last year's true-up was set and what was actually
collected or refunded. The reconcilation of the true-up is a benefit to both the Company and
customers because any true-up over-collection is returned to customers, and any true-up under-
collection is recovered by the Company.
3 The reconcilation of
the tre-up is also commonly referred to as the "tre-up of the tre-up."
STAFF COMMENTS 9 MAY 17,2011
Last year's reconciliation of the true-up included $12.0 milion from the forecast true-up
and $11.3 milion that was under recovered in the reconcilation of the true-up. The two true-up
rates in place last year to recover these amounts actually recovered $41.2 milion including
interest at $0.3 milion. The amounts set for recovery were over recovered by $18.2 milion
(12.0 + 11.3 - 41.2 - 0.3). This is the amount recommended for refund by the Company and Staff.
When divided by expected sales it produces the reconciliation of the true-up rate credit of negative
0.1347 ~/kWh.
E. 2010 Idaho Jurisdictional Return on Equity
In Order No. 30978, the Commission approved a Stipulation between the Company, Staff,
and other paries in Case No: IPC-E-09-30. In the Stipulation, it was agreed that if the Company's
actual return on year-end equity for the Idaho jurisdiction during 2009, 2010 or 2011 exceeded
10.5 %, then the amounts in excess of a 10.5% retur would be shared equally between the
Company's Idaho customers and the Company. Order No. 30978 at 2. If the return on equity fell
below 9.5% percent, the Stipulation allows the Company to accelerate amortization of
accumulated deferred investment tax credits.
In this PCA case, the Company calculated that the jurisdictional return on equity (ROE)
was 10.37%, thus the sharing mechanism of the Stipulation was not triggered. Larkin Dir. at 15.
However, the Staff proposes an adjustment to the Company's ROE calculation.
1. Background. A brief review of several cases is helpful in explaining Staff s adjustment to
the ROE calculation. In October 2009, Idaho Power fied its 09-29 Application "seeking authority
to implement a tracking mechanism to recover its defined benefit pension expense." Application
at 2, Case No. IPC-E-1O-08. The 09-29 Application noted that the Company's actuary informed
the Company that a contribution to the Company's pension was required for the tax year beginning
January 1,2009 in the amount of $5,418,622 ifpaid by October 15,2009. If not paid by October
15,2009, then interest on that amount shall accrue until the extended due date for Idaho Power's
federal income tax retur of September 15,2010. The Company did not make an October 15,
2009 contribution. Order No. 31003 at 2.
The Commission declined to implement a tracking mechanism and instead allowed the
Company to establish a "regulatory asset balancing account" for the purose of tracking the
difference between cumulative cash contributions to the pension plan and the amounts recovered in
rates. Id at 10. The Commission also noted that the contribution to the balancing account "in
STAFF COMMENTS 10 MAY 17,2011
excess of the ERISA minimum. ..wil not be disallowed solely because they are made sooner than
they are legally required to be paid...." Id
In March 2010, the Company fied another Application (Case No. IPC-E-I0-08) seeking
approval to contribute $5,416,796 to its pension plan on September 15,2010. Order No. 31055
at 1. In addition, the Company proposed to recover this 2010 contribution by increasing customer
rates by .77% for each customer class. Id In final Order No. 31091, the Commission approved
the proposed rate increase and the contribution to fud the pension plan in the amount of
$5,416,796 as of September 15,2010. Order No. 31091 at 3.
On March 15,2011, Idaho Power fied Case No. IPC-E-II-04 seeking authority to increase
rates to recover in par a $60 milion contribution the Company made to its pension plan in
September 2010. Although the Company's actuar had previously determined that the 2010
minimum contribution required by ERISA was approximately $5.8 milion, the Company decided
that it was appropriate to make a $60 milion contribution instead. Application at 3. As stated in
the Company's Application, ifit had only contributed the minimum amount, its funding level at
December 31, 2010 "would have been below 80%." Id at 3-4. The Company claims that this
would have "triggered certain plan restrictions, notice requirements to paricipants, and limitations
on future fuding alternatives." Id at 4. After reviewing several alternatives, the Company
determined that making the $60 milion contribution would: (1) maintain an 80% funding level;
(2) reduce the premiums owed to the Pension Benefit Guarantee Corporation (PBGC); and (3)
"approximate the required minimum fuding through 2011." Id The Company noted that the $60
milion contribution would save the Company approximately $11 millon over a 10-year period
and save approximately $1 milion in PBGC premium through 2012. Id at 4. However, even with
the $60 milion contribution, the Company disclosed that its actuar determined that the Company
wil stil be required to make a minimum contribution of$3 milion by October 15,2011, and an
additional contribution of$5.7 millon by Januar 15,2012. Id
2. The Staffs ROE Adjustment. In this PCA fiing, the Company included a calculation of
the Idaho Jursdictional Return on Equity (ROE) for 2010 of 10.37%. Commission Staff verified
the components in the calculation performed by the Company. Staff notes that the earings on
common stock and the common equity at year end used in the calculation agree with the amounts
reported in the Company's 2010 lO-K report to the Securities and Exchange Commission and
Anual Report to Stockholders.
STAFF COMMENTS 11 MAY 17,2011
Comments by all paries (including Staff) in Case No. IPC-E-II-04 recommend accepting
the $60 milion pension contribution. However, for this PCA case, Staff believes the Company
had more flexibilty in timing when and how much of the $60 milion contribution it made during
2010. This flexibility is important when discussing the ROE earings test in this case pursuant to
the Settlement Stipulation approved in Order No. 30978 (Case No. IPC-E-09-30).
In Order No. 31081 the Commission approved the Company's request to make a minimum
$5.8 milion contribution in September 2010. However, Staff believes the remainder of the $60
milion payment ($54.2 milion) might have been paid in the first quarter of2011 and stil avoid
the negative effects mentioned above. Rather than reflect the $54.2 milion as a 2011 obligation,
Staff proposes, for the ROE test only, to amortize the $60 milion payment over two years, for the
years ended 2010 and 2011.
Staff notes that, had the Company only made the required ERISA payment, net income
would have been $33 milion more than the net income reported by the Company in the 2010
Annual Report. The lower level of pension funding would have resulted in a ROE that would have
triggered sharing. Staff acknowledges that the Company was allowed to make contributions to its
balancing account at the level it chose.4 However, Staff canot overlook the additional Company
benefit the decision to fund the pension at the $60 milion level in 2010 has on the coincidental
action of not triggering any sharing with ratepayers.
Staff believes it is the responsibilty of the Commission to assure that ratepayers are treated
fairly with respect to the revenue sharng provisions of the Stipulation approved by Order No.
30978. Moreover, the ROE sharng mechanism was not evaluated in the recent pension review
case (Case No. IPC-E-II-04). Consequently, Staff maintains that the interests of the Company and
its customers can be reasonably balanced by amortizing the $60 milion pension contribution over
two years for the earings test and recommends that the resulting 2010 revenue above a 10.5%
ROE be shared with customers.
5
Staff s proposed adjustment to amortize the pension contribution of $60 milion over two
years stil recognizes the Company's entire pension contribution. This amortization, net of non-
utilty amounts, increases 2010 system net income by $17,714,189. The increase in net income
4 "There may be circumstances where the Company could choose to contribute in excess of the minimum amount
required by ERISA or prior to the final due date of the minimum payment. . .." Order NO.3 1003 at 9.
5 Staff is aware that the amortization of this pension expense wil also impact the ROE earnings test and potential
sharing for next year's PCA fiing. If this adjustment is accepted by the Commission, Staff fully expects the Company
to include the remaining $30 milion of pension expense in next year's ROE earings test calculation.
STAFF COMMENTS 12 MAY 17,2011
changes the Idaho ROE from 10.37% to 11.65%. The increase in the return on equity triggers the
sharing mechanism. The 50% sharing amount above 10.5% for Idaho ratepayers from this
adjustment is $7,462,104.
Staff recommends the sharing amount of $7,462,104 be utilized to reduce the rate increase
associated with DSM expense recovery in the PCA. As noted above, the Commission approved
recovery of$10 milion in DSM expenses incured through 2009 in the 2011/2012 PCA, effective
June 1, 2011. The sharing offset Staff proposes in this case reduces the DSM adjustment included
in the PCA on June 1,2011 to $2,537,896 ($10,000,000 - $7,462,104).
Staff believes reducing the DSM adjustment is reasonable for the following reasons. First,
it simply reduces a previously approved DSM adder rather than affecting other base rates. Second,
changing the DSM component properly allocates the sharing revenue to each customer class on a
class revenue basis consistent with curent base rate allocations.
Energy Effciency Rider Recovery
Staff reviewed Idaho Power's class allocation of the Energy Efficiency Rider to make sure
the methodology comports with the Commission's Order "to separate the DSM expenditures and
allocate them to each customer class based on the amount that would have been recovered from
each class through the Rider." Order No. 32217. As previously discussed, the Company based the
$10 milion allocation on forecasted base revenue during the coming PCA year (June 1, 2011
through May 31,2012). Staff compared the Company's base revenue forecast for each class to
actual base revenue in 2010 to evaluate the potential differences of how the $10 millon surcharge
might be allocated. The Company used a forecast of2011/2012 customer revenues to allocate the
DSM Expenses to the individual classes. Staff believes the forecast is reasonable and comparable
to actual 2010 class revenues. Revenue sharng proceeds are allocated to the various customer
classes on the same forecasted revenue basis to reduce DSM Expense recovery through the PCA.
At the end of the year, any under- or over- collection of the net $2.5 millon (10.0 milion EER
-7.5 millon revenue sharing) in DSM Expenses wil be included in the Energy Efficiency Rider
deferral balance.
PCARATES
The uniform PCA rate credit of 0.0629 ~/kWh is the sum of the three components
described above (0.0445 + 0.0273 -0.1347). This new PCA rate, shown on Attchment B, line 27
represents a PCA credit rather than the 0.3114 ~/kWh surcharge currently in place. The new PCA
STAFF COMMENTS 13 MAY 17,2011
rate constitutes a refud of the combined power cost components. In this case, the uniform PCA
rate is combined with the Energy Efficiency Rider rate, net of the revenue sharing amount, to
arive at the total PCA rate for each class. Attachment D shows these rates.
Combined PCA and Energy Effciency Rider Recovery
Attachment E shows the total PCA rate decrease for all Idaho Power customer classes. It
includes the uniform PCA decrease and the Energy Effciency Rider increase net of the Staff s
ROE sharing adjustment amount. The impact is measured against all biled revenue. The total
Staff-recommended decrease is $48.0 milion (as compared to the Company's $40.4 millon),
representing an average decrease of 5.66%. The Schedule 1, Residential Class decrease is 4.44%,
and the Schedule 19, Large Industrial class decrease is 8.39%, a reduction of 7.45 milion.
Other PCA Attachments
The Staff has included two other Attachments that provide summar or historical
information concerning the PCA. Staff Attachment F summarizes PCA expense amounts and rate
components for this case. The Attachment also shows amounts allocated to other jurisdictions and
amounts shared with shareholders. Attachment G is a bar graph that shows the amount of each
PCA since its inception.
CUSTOMER RELATIONS
Customer Notice and Press Release
Idaho Power's PCA Application contained both the customer notice and press release.
Staff reviewed both and determined that they complied with requirements of Procedural Rule 125,
IDAPA 31.01.0 1.125 (effective April 7, 2011). The customer notice was mailed with Idaho
Power's cyclical bilings beginning April 27, 2011 and ending May 25, 2011. Customers had until
May 17, 2011 to fie comments. Because this Application constitutes a rate decrease, Staff does
not object to the fact that the comment period ends before all customers wil have received the
notice in their monthly bils.
Customer Comments
By May 11, 2011, one customer had sent a comment to the Commission regarding the
PCA. That customer did not state whether or not he supported the decrease in rates. His
comments focused on the long-term strategy for energy supplies.
STAFF COMMENTS 14 MAY 17,2011
STAFF RECOMMENDATION
Staff recommends that the Commission approve the PCA rate credit fied by the Company
as modified by the Staff-proposed ROE adjustment to the DSM expense.
Staff recommends that the Commission approve a total PCA rate comprised of the uniform
PCA decrease of 0.0629 ~/kWh and class-specific rates, as shown on Attachment D, to recover the
Energy Efficiency Rider surcharge net of Staff-proposed revenue sharing. The Staff recommends
that the rate changes be effective June 1, 2011 through May 31, 2012.
Staff recommends the retur on equity earnings test in conformance with Order No. 30978
issued in Case No. IPC-E-09-30 be adjusted as discussed above. The proposed adjustment results
in a sharing with customers of $7,462,104.
Staff fuher recommends the $7.462 milion sharing amount be used to reduce the
Company-proposed DSM expense surcharge for the 2011-2012 PCA period.
Respectfully submitted this J rday of May 2011.
Donald L. ell, I
Deputy Attorney General
Technical Staff: Keith Hessing
Kathy Stockton
Matt Elam
Marilyn Parker
i:umisc:commentslipce 11.6dhkhklsmemp.doc
STAFF COMMENTS 15 MAY 17,2011
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....I00"
TRUE-UP CALCULATIONS FOR 2010 - 2011
FOR
IDAHO POWER COMPANY PCA
CASE NO.IPC-E-11-06
Base Costs are Redistributed
1 2010 2010 2010 2010 2010 2010 2010
2 DESCRIPTION Units APR MAY JUN JUL AUG SEPT OCT
3 PCA Revenue
4 Normalized Idaho Jurisd. Sales MWh 968,949 998,195 1,123,624 1,316,280 1,400,447 1,280,168 1,033,366
5 Forecast Rate $/MWh 4,967 4.967 1.404 1.404 1.404 1.404 1.404
6 Revenue $4,812,770 4,958,035 1,577,568 1,848,057 1,966,228 1,797,356 1,450,846
7
8 Load Change Adjustment
9 Actual System Firm Load - Adjusted MWh 1,038,330 1,127,939 1,260,708 1,676,222 1,518,959 1,232,322 1,053,647
10 Normalized Firm Load MWh 1,077,297 1,254,940 1,412,842 1,685,870 1,594,331 1,225,589 1,100,776
11 Load Change MWh (38,967)(127,001)(152,134)(9,648)(75,372)6,733 (47,129)
12 Expense Adjustment $1,037,691 3,382,037 4,051,328 256,926 2,007,156 (179,300)1,255,045
13
14 Non..F peA
15 ACTUAL:
16 Water Leases $0 0 0 0 914,320 457,160 0
17 Fuel Expense - Coal $9,388,938 9,136,222 7,240,469 14,273,344 14,070,545 15,073,998 12,759,450
18 Fuel Expense - Gas $570,931 456,002 633,254 2,365,212 4,670,666 730,457 340,716
19 Non-Firm Purchases $3,057,227 2,261,341 8,319,121 18,739,777 15,878,714 3,809,004 1,801,892
20 Third Party Transmission $371,978 322,544 1,029,307 1,122,875 978,682 325,744 347,500
21 Surplus Sales $(4,452,277)(8,213,149)(4,500,060)(2,908,250)(2,977,706)(5,109,310)(3,670,472)
22 Hoku First Block Energy $(25,732)(1,229)0 0 0 0 0
23 Expense Adjustment $1,037,691 3,382,037 4,051,328 256,926 2,007,156 (179,300)1,255,045
24 Sub-Total $9,948,755 7,343,767 16,773,419 33,849,886 35,542,379 15,107,753 12,834,131
25
26 BASE:
27 Water for Power (Leases)$4,734 4,664 153,090 190,953 204,643 179,325 133,942
28 Fuel Expense - Coal $9,357,518 9,219,352 14,041,049 17,513,694 18,769,296 16,447,224 12,284,817
29 Fuel Expense - Gas $429,483 423,141 507,539 633,064 678,450 594,515 444.057
30 Non-Firm Purchases $4,012,962 3,953,710 5,583,131 6,963,955 7,463,219 6,539,89e 4,884,802
31 Third Party Transmission $734,112 723,272 691,679 862,746 924,599 810,211 605,165
32 Surplus Sales $(8,173,502)(8,052,819)(7,755,827)(9,674,005)(10,367,560)(9,084,921 )(6,785.741)
33 Sub-Total $6,365,307 6,271,320 13,220,661 16,490,407 17,672,647 15,486,250 11,567,042
34
35 Change From Base $3,583,448 1,072,447 3,552,758 17,359,479 17,869,732 (378,497)1,267,089
36 Emission Allowance Sales Cred~$0 0 0 0 0 0 0
37 Renewable Energy Credit Sales $(1,037,449)10,739 (476,754)506 (555,010)(366,861)(449,562)
38 Sub-Total $2,545,999 1,083,187 3,076,005 17,359,984 17,314,722 (745,358)817,527
39
40 Deferral (Shared and Allocated)$2,292,927 975,518 2,776,094 15,667,386 15,626,537 (672,685)737,818
41
42 OF Deferral
43 Actual (includes Net Metering)$3,138,813 4,806,159 7,042,314 7,749,957 7,523,824 6,098,940 4,756,343
44 Base $4,436,330 4,370,826 5,261,808 6,563,163 7,033,693 6,163,509 4,603,670
45
46 Change From Base $(1,297,517)435,333 1,780,506 1,186,794 490,131 (64,569)152,673
47 Deferral (Allocated)$(1,230,047)412,696 1,691,481 1,127,454 465,624 (61,340)145,040
48
49 Total Deferral (-6+40+47)$(3,749,889)(3,569,821 )2,890,007 14,946,783 14,125,934 (2,531,381)(567,988)
50
51 Principal Balances
52 Beginning Balance $0 (3,749,889)(7,319,710)(4,429,703)10,517,079 24,643,013 22,111,632
53 Amount Deferred $(3,749,889)(3,569,821 )2,890,007 14,946,783 14,125,934 (2,531,381)(567,988)
54 Ending Balance $(3,749,889)(7,319,710)(4,429,703)10,517,079 24,643,013 22,111,632 21,543,643
55
56 Interest Balances
57 Accrual thru Prior Month $0 0 (3,125)(9,225)(12,916)(4,148)16,388
58 Interest tl 1 % per Year $0 (3,125)(6,100)(3,691)8,764 20,536 18,426
59 Prior Month's Interest Adj.$0 0 0 0 4 0 0
60 Total Current Month Interest $0 (3,125)(6,100)(3,691)8,768 20,536 18,426
61 Interest Accrued to Date $0 (3,125)(9,225)(12,916)(4,148)16,388 34,814
62 Balance (True-Up & Interest)$(3,749,889)(7,322,835)(4,438,928)10,504,163 24,638,865 22,128,019 21,578,457
63
64 True-Up of the True-Up
65 True-Up Revenues (Collections)$8,451,840 8,310,810 6,911,723 2,351,308 2,425,726 2,124,626 1,763,836
66
67 Beginning Balance $11,284,407 14,815,717 6,302,048 (604,423)(2,956,235)(5,384,424)(7,513,538)
68 Adjustments:
69 2009-10 PCA Transfer - ON 31093 $11,963,777 0 0 0 0 0 0
70 Emission Allowance - ON 30790 $0 0 0 0 0 0
71 Interest Adjustment - O.N. 31093 $0 (215,027)0 0 0 0 0
72 Sub-Total $23,248,184 14,600,690 6,302,048 (604,423)(2,956,235)(5,384,424)(7,513,538)
73 Interest tl 1 % per Year $19,373 12,167 5,252 (504)(2,464)(4,487)(6,261)
74 Revenue Applied to Interest $19,373 12,167 5,252 (504)(2,464). (4,487)(6,261)
75 Revenue Applied to Balance $8,432,466 8,298,642 6,906,471 2,351,812 2,428,189 2,129,113 1,770,098
76 True-Up of the True-Up Balance $14,815,717 6,302,048 (604,423)(2,956,235)(5,384,424)(7,513,538)(9,283,635)
77
78 Note: Negative amounts indicate benefi to ratepayers Attachment C
Case No. IPC-E-II-06
Staff Comments
5/17/11 Page 1 of2
1
2 DESCRIPTION
3 PCA Revenue
4 Normalized Idaho Jurisd. Sales
5 Forecast Rate
6 Revenue
7
8 Load Change Adjustment
9 Actual System Firm Load - Adjusted
10 Normalized Firm Load
11 Load Change
12 Expense Adjustment
13
14 Non-QF PCA
15 ACTUAL:
16 Water Leases
17 Fuel Expense - Coal
18 Fuel Expense - Gas
19 Non-Firm Purchases
20 Third Party Transmission
21 Surplus Sales
22 Hoku First Block Energy
23 Expense Adjustment24 Sub-Total
25
26 BASE:
27 Water for Power (Leases)
28 Fuel Expense - Coal
29 Fuel Expense - Gas
30 Non-Firm Purchases
31 Third Party Transmission
32 Surplus Sales
33 Sub-Total
34
35 Change From Base
36 Emission Allowance Sales Credtt
37 Renewable Energy Credit Sales
38 Sub-Total
39
40 Deferral (Shared and Allocated)
41
42 QF Deferral
43 Actual (includes Net Metering)
44 Base
45
46 Change From Base
47 Deferral (Allocated)
48
49 Total Deferral (-6+40+47)
50
51 Principal Balances
52 Beginning Balance
53 Amount Deferred
54 Ending Balance
55
56 Interest Balances
57 Accrual thru Prior Month
58 Interest (¡ 1 % per Year
59 Prior Month's Interest Adj.
60 Total Current Month Interest
61 Interest Accrued to Date
62 Balance (True-Up & Interest)
63
64 True-Up ofthe True-Up
65 True-Up Revenues (Collections)
66
67 Beginning Balance
68 Adjustments:
69 2009-10 PCA Transfer- ON 31093
70 Emission Allowance - ON 30790
71 Interest Adjustment - O.N. 31093
72 Sub-Total
73 Interest (¡ 1 % per Year
74 Revenue Applied to Interest
75 Revenue Applied to Balance
76 True-Up of the True-Up Balance
77
78
TRUE-UP CALCULATIONS FOR 2010 - 2011
FOR
IDAHO POWER COMPANY PCA
CASE NO.IPC-E-11-06
Base Costs are Redistributed
MWh
$/MWh
$
Units
2010
NOV
2010
DEC
1,074,126
1.404
1,508,073
1,264,561
1,380,118
(115,557)
3,077,283
°
15,252,103
441,024
7,855,057
243,884
(6,214,673)
°
3,077,283
20,654,677
145,752
13,367,949
483,209
5,315,486
658,522
(7,384,028)
12,586,890
2011
JAN
1,193,372
1.404
1,675,494
1,295,294
1,356,320
(61,026)
1,625,122
215,600
12,440,921
665,501
4,865,362
286,977
(12,245,790)
°
1,625,122
7,853,694
160,237
14,696,534
531,233
5,843,770
723,969
(8,117,896)
13,837,847
2011
FEB
1,115,947
1.404
1,566,790
1,105,065
1,177,732
(72,667)
1,935,122
(46,200)
8,622,590
546,640
2,104,562
251,821
(7,129,494)
°
1,935,122
6,285,042
149,325
13,695,653
495,054
5,445,791
674,665
(7,565,042)
12,895,446
2011
MAR
1,029,368
1.404
1,445,233
1,117,888
1,160,140
(42,252)
1,125,171
514,305
6,942,649
528,630
2,163,844
324,477
(9,558,817)
°
1,125,171
2,040,260
135,069
12,388,199
447,794
4,925,909
610,258
(6,842,846)
11,664,383
TOTALS
13,492,340
25,952,179
14,825,606
15,556,720
(731,114)
19,469,566
2,055,185
138,868,030
12,921,516
77,085,070
5,812,011
(70,077,566)
(26,961)
19,469,566
186.106,850
1,587,623
163,327,463
6,084,896
65,523,728
8,587,977
(96,181,927)
148,929,760
958,498
1.404
1,345,731
MWh
MWh
MWh
$
1,134,671
1,130,765
3,906
(104,017)
8,067,787
°
(435,465)
7,632,322
6,888,171
4,411,185
5,009,567
(5,984,153)
°
(614,204)
(6,598,357)
(5,955,017)
5,122,518
5,507,447
(6,610,404)
°
(500,119)
(7,110,523)
(6,417,247)
5,186,222
5,132,373
(9,624,123)
°
(750,662)
(10,374,785)
(9,363,244)
4,788,369
4,642,411
37,177,090
°
(5,649,119)
31,527,971
28,447,098
64,792,474
63,051,665
$
$
$
$
$
$
$
$
$
°
13,666,802
972,484
6,229,167
206,220
(3,097,568)
°
(104,017)
17,873,088
$
$
$
$
$
$
$
125,889
11,546,178
417,357
4,591,097
568,779
(6,377,740)
10,871,560
$
$
$
7,001,528
°
(474,280)
6,527,247
$5,890,841
$
$
4,167,831
4,326,868
$
$
$
(159,037)
(151,085)
4,394,024
$
$
$
21,543,643
4,394,024
25,937,667
$
$
$
$
$
$
34,814
17,953
°
17,953
52,767
25,990,434
$
$
$
$
$
$
$
$
$
$
1,566,524
(9,283,635)
°
°
°
(9,283,635)
(7,736)
(7,736)
1,574,260
(10,857,896)
Note: Negative amounts indicate benefi to ratepayers
(598,382)
(568,463)
4,811,636
25,937,667
4,811,636
30,749,303
52,767
21,615
o
21,615
74,382
30,823,684
1,854,932
(10,857,896)
°
°
°
(10,857,896)
(9,048)
(9,08)
1,863,981
(12,721,876)
(384,929)
(365,683)
(7,996,194 )
30,749,303
(7,996,194)
22,753,109
74,382
25,624
2
25,626
100,008
22,853,117
1,942,056
(12,721,876)
o
o
o
(12,721,876)
(10,602)
(10,602)
1,952,657
(14,674,534)
53,849
51,156
(7,932,880)
22,753,109
(7,932,880)
14,820,229
100,008
18,961
°
18,961
118,969
14,939,198
1,757,907
(14,674,534)
°
°
°
(14,674,534)
(12,229)
(12,229)
1,770,136
(16,444,669)
145,958
138,660
(10,669,816)
14,820,229
(10,669,816)
4,150,412
118,969
12,350
°
12,350 I
131,319
4,281,732
1,694,293
(16,444,669)
°
°
°
(16,444,669)
(13,704)
(13,704)
1,707,997
(18,152,666)
1,740,809
1,655,493
4,150,412
4,150,412
131,314
6
30,702 I
4.181.114
41,155,581
11,284,407
11,963,777
°
(215,27)
23,033,156
(30,242)
41,185,823
(18,152,666)
Attachient C
Case No. IPC-E-II-06
Staff Comments
5/17/11 Page20f2
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63
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Attachment G
case No. IPC-E-11-u6
Staff Comments
5/17/11
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 17TH DAY OF MAY 2011,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-II-06, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
DONOV AN E WALKER
JASON B WILLIAMS
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: dwalker(ßidahopower.com
jwillams(ßidahopower .com
MATTHEW T LARKIN
GREG SAID
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: mlarkin(ßidahopower.com
gsaid(ßidahopower .com
PETER J RICHARDSON
GREGORY MADAMS
RICHARDSON & O'LEARY
PO BOX 7218
BOISE ID 83702
E-MAIL: peter(ßrichardsonandoleary.com
greg(ßrichardsonandoleary.com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: dreading(ßmindspring.com
JJJ.:J .\(~SEC TARY
CERTIFICATE OF SERVICE