20100331final_order_no_31033.pdf

Office of the Secretary
Service Date
March 31 , 2010
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF PACIFICORP DBA ROCKY MOUNTAIN
POWER FOR AUTHORITY TO
IMPLEMENT POWER COST ADJUSTMENT
RATES FOR ELECTRIC SERVICE FROM
APRIL 1,2010 THROUGH MARCH 31 , 2011
THROUGH THE ENERGY COST ADJUSTMENT MECHANISM
CASE NO. PAC-10-
ORDER NO. 31033
APPLICATION
On February 2010, PacifiCorp dba Rocky Mountain Power (PacifiCorp; Company)
filed an Application with the Idaho Public Utilities Commission (Commission) for authority to
implement a power cost adjustment to rates for all customer classes excluding tariff contract
customers (Monsanto Company and Agrium, Inc.! The proposed power cost adjustment is
calculated pursuant to an Energy Cost Adjustment Mechanism (ECAM) approved by the
Commission on September 29, 2009 in Case No. P AC-08-, Order No. 30904. The energy
cost adjustment is calculated to collect or credit the accumulated difference between total
Company base net power costs (Base NPC) collected ITom Idaho customers through rates and
total Company actual net power costs (Actual NPC) incurred to serve customers in Idaho
calculated on a cents-per-kilowatt-hour basis. The initial deferral period was July 1 , 2009
through November 30, 2009. The Company is proposing to recover approximately $2.2 million
in total deferred net power costs. The energy cost adjustment is set forth in a new electric
service Schedule No. 94. The proposed effective date is April 1 , 2010. The Commission in this
Order authorizes recovery of a calculated ECAM deferred balance of$2 013 140.
The ECAM is designed to recover the sum of all components of net power costs as
traditionally defined in the Company s general rate cases and modeled in its production dispatch
model GRID. The mechanism addresses only power cost expenses and does not include any
costs associated with fixed-cost recovery, i., capital investment in rate base. Specifically, base
I Tariff contract loads (Monsanto and Agrium) are not subject to any ECAM
surcharges/credits until January 1
2011. Reference Case No. PAC-07-, Order No. 30482.
ORDER NO. 31033
and actual NPC will include costs typically booked to the following Federal Energy Regulatory
Commission (FERC) accounts:
Account 447 - Sales for resale , excluding on-system wholesale sales and
other revenues that are not modeled in GRID.
Account 501 - Fuel, steam generation, excluding fuel handling, start-up
fuel/gas/ diesel fuel, residual disposal and other costs that are not modeled in
GRID.
Account 503 - Steam ITom other sources.
Account 547 - Fuel, other generation.
Account 555 - Purchased power, excluding BP A residential exchange credit
pass-through, if applicable.
Account 565 - Transmission of electricity by others (wheeling).
In addition to the comparison of actual NPC to base NPC, the ECAM includes three
additional components: The load growth adjustment rate (LGAR) revenues, a credit for SO2
allowance sales, and a renewable resource adder. The ECAM also includes a symmetrical
sharing band of 90% (customers)/10% (Company) that shares the NPC differential between
actual NPC and base NPC SO2 sales and LGAR revenues between the customers and the
Company.
Pursuant to the ECAM, a renewable resources adder recognizes that the Company has
made significant investments in renewable generation projects that are not yet being recovered in
Idaho rates, even though these projects provide significant benefits to customers. Specifically,
the adjustment recognizes that actual NPC were reduced by power generated ITom these
renewable generation projects. Pursuant to Commission Order No. 30904, the Commission
approved a renewable resource adjustment of $55 per megawatt-hour (MWh) multiplied by the
actual MWh output generated by the renewable resources that were not included in rate base in
Case No. PAC-08-07.
The components making up the deferred ECAM balance set forth in the Application
are reflected in the following table:
2 Start-up fuel is accounted for separatlely ITom the primary fuel for steam-powered generation plants. Start-upcosts are not accounted for separately for natural gas plants, and therefore all fuel for natural gas plants is included
in the determination of both base NPC and actual NPC.
ORDER NO. 31033
NPC Differential for Deferral
LGAR
SO2
Total
Customer Responsibility
Renewable Resource Adder
Interest
Total Company Recovery
$ 121 504
499 793
(120,562)
500 735
90%
350 662
811 412
022
170 096
The Schedule 94 energy cost adjustment proposed by the Company will have the
following rate impacts:
Residential Customers - an increase of 1.29%, i., approximately $0.91 per
month for the average residential home using 850 kWh per month.
Irrigation Customers (Schedule 10): 1.55% increase
General Service
Schedule 23/23A: 1.34% increase
Schedule 6/6A18/35: 1.70% increase
Schedule 9: 2.13% increase
Schedule 19: 1.57% increase
Public Street Lighting
Schedules 717A , 12: 0.46% increase
COMMENTS
On February 12 2010, the Commission issued a Notice of Application and Modified
Procedure in Case No. PAC-IO-O1. The deadline for filing written comments was March 10
2010. Comments were filed by Commission Staff and two customers, one located in Ammon
the other in Firth. Reply comments were filed by the Company on March 17 2010.
Customer Comments
The Firth customer questions the high price of natural gas used by the Company to
power its plants and queries whether an affiliate relationship might exist between the seller and
buyer of the gas.
The Ammon customer (husband and wife) are on social security (age 83), have no
other income and state that they cannot afford an increase in rates.
ORDER NO. 31033
Staff Comments
Staff suggests changes to the Company s Application proposal and recommends a
reduction in the Idaho ECAM deferral balance from $2 170 096 to $1 978 865 for the July 1
2009 - November 30, 2009 deferral period.
ECAM Deferral
Staff notes that this is the first ECAM filing made by the Company subsequent to
approval of the mechanism in Commission Order No. 30904. As a result, the ECAM filing in
this case differs in several respects from Company filings that will be made in subsequent years:
(1) This filing includes adjustments for Net Power Cost Differential, Load
Growth Adjustment, and SO2 Sales for the 5-month period of July 1 , 2009
through November 30, 2009; future filings will be for the 12-month period
of December 1 through November 30 of the application year.
(2) The Renewable Resource Adder will be included in the ECAM only until
the costs and benefits can be included in base rates in the Company s next
general rate case. A rate case will eliminate the need for this special
adjustment.
(3) In future years there will be a "true-up" between the deferral balance and
amounts actually recovered; any over- or under-recovery that occurs as a
result of this ECAM filing will result in an adjustment to future ECAMs.
Staff reviewed the Company s ECAM filing and audited the Company s actual results
as they pertain to the ECAM. Staff makes the following recommended changes to the
Company s proposal.
Net Power Cost Differential - The Net Power Cost differential, Staff states, is the
driving force behind the creation and need for a power cost adjustment mechanism. Normally
this differential is the single largest cost component of the mechanism. In this case it is a small
portion of the total deferral. Two primary reasons for this are (1) the review period is only five
months instead of twelve months and (2) the actual system load was lower than the base load
assumed in the Company s last general rate case. The lower system load, Staff speculates, is
probably associated with the current economic downturn.
Staff reviewed transaction activity in the FERC accounts of the Company used to
record net power costs. Staff s transaction evaluation and trend analysis revealed nothing
unreasonable or out-of-trend with previous activity.The Idaho share of net power costs
ORDER NO. 31033
increased by $121 504; the Idaho customers' share of the increased cost is $109 354 after 90/10
sharing. This amount represents 5.43% of the Company s proposed total ECAM deferral.
Load Growth Adjustment - The Load Growth Adjustment Rate (LGAR) is the largest
component ofthis ECAM deferral. During the five-month review period actual Idaho loads were
down 85 810 MWh or 7.95% from the same 2007 normalized five-month period used to
calculate Idaho base load. At an approved adjustment rate of $17.48/MWh, this results in an
adjustment of $1 499 793. The Idaho customer share is $1 349 814 after 90/10 sharing. These
are the same results presented by the Company.
The theory behind the LGAR, Staff contends, is that the Company should not be
allowed to collect growth-related power supply costs through an ECAM surcharge and then also
collect base revenue from that new load to cover the same power supply costs. The mechanism
is symmetrical and the same theory applies when loads decline. The Company should not be
required to provide a credit to customers when power supply costs decline due to declining load
and also suffer the loss of base revenue from the lost load. In this case, power supply costs
increased slightly at the same time load decreased significantly. Rather than offsetting lost
revenue that the Company already gave back in an ECAM credit, the Load Growth Adjustment
simply reimbursed the Company for lost revenue due to lost load. This, Staff notes, is very
similar to decoupling or the Fixed Cost Adjustment Mechanism (FCA) in place for Idaho Power
Company.
While Staff does not propose to remove the Load Growth Adjustment in this case
Staff notes that decoupling has not been approved in Idaho for PacifiCorp. Staff also notes that
all three Idaho utilities have ECAMIPCAs in place with similar provisions. Staff believes that
further investigation is necessary in conjunction with Company filings for all three mechanisms
to determine if a Load Growth Adjustment is appropriate when the adjustment exceeds the
magnitude of the ECAM/PCA surcharge/credit or is otherwise reasonable when loads decline.
SO2 Credits - The ECAM approved by the Commission requires that revenues ITom
the sale of SO2 credits be shared between the Company and its customers (90% customers/1 0%
Company). This requirement applied to all SO2 sales beginning July 2009. The Company
calculated the Idaho portion of the SO2 credit sale proceeds by multiplying total sales by the
Idaho energy allocation factor of 6.5865%. The Idaho portion of the SO2 credit sale proceeds
was then further reduced to an Idaho tariff customer portion based on the percent of the Idaho
ORDER NO. 31033
tariffload to total Idaho load in each month. (Shu Direct Testimony p. 5 , lines 18-23 through p.
, lines 1-5 and Company Exhibit 1 , lines 13-17). The Company calculated the Idaho tariff
customer portion to be $108 506 after the 90/1 0 sharing.
Staff agrees that SO2 sales proceeds should be allocated to Idaho based on the energy
allocation factor. However, Staff believes further adjustment by the percentage representing the
tariff customer portion of total Idaho Load is not consistent with prior rate case treatment of SO2
credit sale proceeds to tariff customers. Ratemaking treatment of SO2 credit sale proceeds prior
to the ECAM resulted in 100% of the sale proceeds reducing the approved rate increase whether
contract customers were affected or not. Staff believes the 10% sharing represents the
appropriate Company share as the sale of SO2 credits are moved ITom base rates to the ECAM.
This final Company-proposed reduction in Idaho SO2 proceeds, which have already been
reduced to 90% of the originally allocated amount, results in an even smaller allocation to Idaho
tariffed customers and an even larger share retained by the Company. Staff believes that this
further reduction in Idaho SO2 proceeds should not occur. Therefore, Staff recommends that the
Commission reject the Company s proposal to further reduce Idaho SO2 credits. Eliminating the
reduction results in a net SO2 credit of $142 609 after 90/10 sharing, increasing the Idaho tariff
customer credit by $34 104.
Renewable Resource Adder - The Renewable Resource Adder, Staff notes, allows
the ECAM to include a cost for renewable resources that have come on-line since base power
costs were set in the Company s last rate case, Case No. P AC-08-07. The costs are included at
$55/MWh. The costs of these resources are not included in base rates but generation ITom the
resources reduces actual Net Power Costs. In the Company s next general rate case the costs and
benefits of these resources will be included in base rates and the need for this special adjustment
will be eliminated. The Idaho customer share of this cost is $811 412. These are the same
results presented by the Company.
Goose Creek Transmission Sale Credit - Commission Order No. 30904 required the
Company to include an Idaho customer benefit for the sale of Goose Creek Transmission assets
in its ECAM calculation. The amount that was to be included as an Idaho customer benefit was
established as $156 434. The Company inadvertently left this credit out of its Application filing.
Shortly after the filing was made the Company identified the error and contacted Staff. The
credit is included in Staff s calculations.
ORDER NO. 31033
Interest - As required by Commission Order No. 30904, the Company included
interest on monthly deferral balances at the Commission-approved customer deposit interest rate.
This rate is 2% for 2009. The Company calculated the interest amount to be $8 022. Due to the
addition of the Goose Creek Sale Credit and the adjustment for SO2 sales, Staff calculates a
slightly different interest amount than the Company calculated. Staff calculates interest of
329 resulting in an adjustment of$693.
Incorporating the Staff adjustments discussed above, Staff calculates the ECAM
components and Total Idaho Deferral to be:
NPC Differential
Load Growth Adjustment
SO2 Credit
Sub-Total
Customer Responsibility
Renewable Resource Adder
Goose Creek Sale Credit
Interest
Total Idaho Deferral
$ 121 504
499 793
(158,455)
462 842
90%
316 558
811 412
(156 434)
7,329
978 865
The Staff adjustments reduce the deferral amount from the Company calculation of
170 096 to $1 978 865. The sum of all Staff adjustments reduces the ECAM deferral by
$191 231.
ECAM Rates
The methodology for calculating ECAM rates is generally defined in the Settlement
Stipulation accepted by the Commission in Order No. 30904. The details of the rate design were
accepted by participating parties in discussions after Order No. 30904 was issued. The rates
were to be energy rates (~/kWh) and they were to be differentiated based on delivery losses. In
Company Exhibit No., the Company proposes three different energy rates that vary by delivery
voltage. In general, the lower the delivery voltage the higher the losses associated with serving
the load. Higher losses translate into higher ECAM rates; lower losses, due to higher delivery
voltages, translate into lower ECAM rates. Staffs calculation of the three loss-differentiated
rates is as follows:
Secondary Distribution Rate: .00098 $IkWh (0.098~IkWh).
ORDER NO. 31033
Primary Distribution Rate: 0.00091 $IkWh (0.091~IkWh).
Transmission Rate: 0.00089 $IkWh (0.089~/kWh).
The Staff-proposed ECAM rate adjustment results in an average rate increase to tariff customers
of 1.34%.
Staff notes that the application of these three rates to the estimated metered energy
sales produces a revenue amount of approximately $1 981 000, which is approximately $2 000
above the deferral amount. This occurs because the rates are rounded to five decimal places like
all Rocky Mountain Power energy rates. This is not a problem because this difference, or any
other difference, between the deferral amount and amounts actually recovered is carried back
into the following year s deferral balance as a true-up.
Staff Recommendation
Commission Staff recommends that the Commission accept an Idaho ECAM deferral
balance of $1 978 865 for the July 1 , 2009 through November 30, 2009 deferral period. This
number includes a Goose Creek Transmission Sale credit, an adjustment to the SO2 sale credit
and an adjustment to the Company interest calculation. Staff recommends that the
Commission approve the Staff-calculated loss differentiated energy rates set out above for an
effective date of April 1 , 2010.
As previously discussed above, Staff also recommends that the application and
implementation of the Load Growth Adjustment be further evaluated either in the Company
next general rate case or in a separate case before the next annual ECAM filing.
PacijiCorp Reply Comments
Staffs proposal reduced by $156 434 the amount requested by the Company for
Idaho s allocation of the Goose Creek sale and by an additional $34 104 to adjust the allocation
of SO2 sales. Based on these two adjustments and associated interest, Staff recommended an
ECAM deferral balance of $1 978 865. PacifiCorp addressed Staffs proposed adjustments as
follows:
Goose Creek
The Company agrees that the ECAM deferred balance of $2 170 096 should be
reduced by $156,434 for the Goose Creek sale and by an additional $522 of associated interest
resulting in a new ECAM balance of$2 013 140.
ORDER NO. 31033
S02
PacifiCorp opposes Staffs SO2 adjustment because (i) in Order No. 30482 ITom Case
No. PAC-07-, the Commission stated: "the cost of service methodology proposed by the
Company in this proceeding will remain as the accepted methodology though the maximum
duration of the rate plans for Agrium and Monsanto, which expire December 31 , 2010.
Stipulation 'illl , (ii) the Order further states "the Company agrees that in any rate filing during
the terms of such rate plan that it will not seek to recover any revenue shortfalls related to
Agrium and Monsanto ITom other Idaho customers when compared to cost of service studies
from those filings." Stipulation'ill0.
The Company contends it has complied with Commission Order No. 30482 by
excluding all Agrium and Monsanto (tariff contract customers) impacts ITom the ECAM deferral
calculation, including the NPC differential, load growth adjustment, SO2 credit, and renewable
resource adder. Staff acknowledged, the Company states, that the SO2 sales should be allocated
to Idaho using Idaho s share of the system energy factor. However, Staff states also that "further
adjustment by the percentage representing the tariff customer portion of total Idaho load is not
consistent with prior rate case treatment." The Company disagrees with this statement. Neither
the impacts associated with the components of the ECAM nor the revenue credits related to the
SO2 sales, the Company contends, are being included for Agrium and Monsanto.
Similar to the treatment in a rate case, jurisdictional allocation is first addressed
followed by customer class allocations. Customer class, or cost-of-service, allocation is based on
the intra-jurisdiction usage relationship between customer classes within the state. Thus, the
Company contends, it is necessary to first allocate Idaho s share of the total Company SO2 sales
and then adjust or allocate total Idaho SO2 sales to the tariff customers, removing Monsanto
and Agrium s share of the sales. This is consistent with the way the Company excluded
Agrium s and Monsanto s share of NPC differential $/MWh (line 5 from Ms. Shu s Exhibit 1)
by applying tariff customers load only to the NPC differential $/MWh rate. Had the Company
used total Idaho load to multiply the NPC differential $/MWh rate, then:
1. The NPC differential would have been $204 247 instead of$121 504
2. The load growth adjustment would have been $3.4 million rather than $1.5
million, and
ORDER NO. 31033
3. The renewable resource adder would have been $1.4 million rather than
$811 412.
In total, the Company states the ECAM deferral balance would have been $4.
million rather than $2.0 million. However, the Company acknowledges that this is counter to
Commission Order Nos. 30482 and 30904. Therefore, the Company has deferred and requested
recovery only ofthe tariff customers' portion of the ECAM. The Company s position is that it is
not appropriate to ignore the costs associated with the tariff contract customers while at the same
time taking the SO2 revenues as an offset to the ECAM deferral balance. Staff s adjustment to
SO2 sales, the Company contends, is counter to Commission Order Nos. 30482 and 30904 which
both specify that Agrium s and Monsanto s revenue shortfalls and costs would not be sought
ITom other customers or included in the ECAM until January 1 , 2011.
PacifiCorp accordingly requests that the Commission accept the Idaho ECAM
deferral balance of $2 013 140, which represents the Company s original request of $2 170 096
adjusted for the Goose Creek sale as agreed to by all parties to the ECAM Stipulation, Order No.
30904. The Company s position is that it is not appropriate to reduce the ECAM deferral
balance by Agrium s and Monsanto s share of the SO2 sales and recommends the Commission
deny Staffs proposed SO2 adjustment.
The Company recommends, based on an ECAM deferral balance of $2 013 140, that
the Commission approve the following loss-differentiated energy rates to be included in
Schedule 94:
Secondary Distribution Rate
Primary Distribution Rate
Transmission Rate
IOO~/kWh
093~/kWh
091~/kWh
The resultant average rate impacts for customers are as follows:
Residential Customers: An increase of 1.20%, i., approximately $0.85 per
month for the average residential home using 850 kWh per month.
Irrigation Customers (Schedule 10): An increase of 1.45%
General Service
Schedule 23/23A: 1.25% increase
Schedule 6/6A18/35: 1.59% increase
Schedule 9: 1.98% increase
Schedule 19: 1.46% increase
ORDER NO. 31033
Public Street Lighting
Schedules 717A , 12: 0.43% increase
COMMISSION FINDINGS
The Commission has reviewed and considered the filings of record in Case No. P AC-
IO-Ol including the Application and accompanying workpapers and supporting testimony, the
comments and recommendations of Commission Staff and customers, and the reply comments
and recommendations of the Company. We have also reviewed the Energy Cost Adjustment
Mechanism (ECAM) we approved last year in Order No. 30904, Case No. PAC-08-08 and the
rate case Stipulation we approved in Order No. 30482, Case No. PAC-07-05.
The Commission Staff in filed comments proposes two adjustments to the Company
Application, i., (1) SO2 credits and (2) Goose Creek transmission sale credit. The Company in
reply concedes the Goose Creek credit adjustment (noting it was an oversight not to include
same) and contests Staffs proposed SO2 credit adjustment. The Commission is informed that
Staff concurs with the Company s reply argument regarding SO2 credits. We are persuaded that
the Company s SO2 argument is correct. That being the case, we find that the Company and
Staff are now in agreement as to the ECAM deferral balance, i., $2 013 140 , and the related
Schedule 94 loss-differentiated energy rates, to wit:
Secondary Distribution Rate 0.1 OO~/k
Primary Distribution Rate 0.093~/kWh
Transmission Rate 0.091~/kWh
We find that PacifiCorp s Application correctly implements the ECAM methodology
we approved. The Company s accounts have been audited. We find the $2 013 140 deferral
balance agreed to by the Staff and Company to be correct for the initial deferral period (July 1 to
November 30, 2009), as are the related Schedule 94 loss-differentiated energy rates. We find it
reasonable to approve the Schedule 94 energy cost adjustment for an effective date of April 1
2010.
Our approval of an energy cost adjustment in this case is tempered by the following
expressed concern and recommended course of action. In approving the ECAM last year, we
authorized the Company to track annual deviations in power supply costs embedded in base rates
ORDER NO. 31033
and to surcharge or credit customers the accumulated balance over the subsequent year. Power
supply costs represent a large portion of the Company s total revenue requirement and are
subject to a high degree of volatility largely outside of the Company control. The
mathematical symmetry of the ECAM seemed reasonable. Observing how the ECAM operates in
practice, however, reveals an unintended consequence in periods of declining retail load. In such
a situation, the ECAM, we find, appears to operate much the same as a decoupling mechanism
reimbursing the Company for lost revenue for reductions in customer usage (sales). The
Company s Application in this case is a striking example of this end result. Seventy-five percent
of the ECAM deferral in this case is related to declining load. The Load Growth Adjustment
Rate (LGAR) adds power supply costs to make up for the generation portion of lost sales. In
deferral periods of load reduction such as occurred in the instant case, the ECAM looks less like
a power cost adjustment and more like a vehicle to restore lost revenue due to decreases in
customer usage. We find the result that is presented by use of an ECAM containing an LGAR
during periods of declining load growth is a problem that may also occur in the Power Cost
Adjustment (PCA) mechanisms of Idaho Power and A vista. Because the Company realized
benefits differently than we anticipated, the Commission needs to further explore how the
methodology operates in practice. We therefore direct Commission Staff to hold a workshop for
the three utilities to discuss this phenomenon and report continued justification for use of an
LGAR when loads decline.
For the ECAM to act as a decoupling mechanism was unintended. A decoupling
mechanism breaks the link between customer usage (sales) and the utility's revenues. If the
Company desires a decoupling mechanism it should request and justify one in a separate filing.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over PacifiCorp dba Rocky
Mountain Power, an electric utility, and the issues raised in Case No. PAC-I0-0l pursuant to
the authority granted the Commission in Title 61 , Idaho Code, and the Commission s Rules of
Procedure, IDAPA 31.01.01.000 et seq.
ORDER
In consideration of the foregoing and as more particularly described above, IT IS
HEREBY ORDERED and the Commission does hereby approve implementation of a Schedule
94 Energy Cost Adjustment for an effective date April 1 , 2010, to recover a deferral balance of
ORDER NO. 31033
013 140 by means of a Secondary Distribution Rate of 0.1O0~IkWh, a Primary Distribution
Rate ofO.093~IkWh, and a Transmission Rate ofO.091~/kWh.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7)
days after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See Idaho Code 9 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this .2/
sf"
day of March 2010.
D. EMP , P SIDENT
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MARSHA H. SMITH, COMMISSIONER
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MACK A. REDFORD, COMMISSIONER
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Commission Secretary
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ORDER NO. 31033