20070109final_order_no_30215.pdf

Office of the Secretary
Service Date
January 9, 2007
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE PETITION OF
IDAHO POWER COMPANY FOR
MODIFICATION OF THE LOAD GROWTH
ADJUSTMENT FACTOR WITHIN THE
POWER COST ADJUSTMENT (PCA)
METHODOLOGY
ORDER NO. 30215
CASE NO. IPC-06-
On April 13 , 2006, Idaho Power Company (Idaho Power; Company) filed a Petition
to modify the method for determining the Power Cost Adjustment (PCA) load growth adjustment
factor. The PCA is an annual rate adjustment mechanism that changes a portion of customer
rates to reflect hydro conditions and variations in power supply costs. The PCA methodology
was established in 1993 by Order No. 24806, Case No. IPC-92-25. Base power supply costs
and the various components of the PCA are reviewed and updated in general rate cases. The
load growth adjustment factor or Expense Adjustment Rate for Growth (EARG) is included as a
component in the PCA's annual true-up computations.
In Idaho Power s recent 2005 rate case settlement Stipulation, the parties agreed "that
the PCA load growth rate issue will be addressed contemporaneously with the Company
upcoming PCA" application. Stipulation at 'if6(d), Case No. IPC-05-28. On May 12, 2006
the Commission issued Order No. 30035 adopting the rate case Stipulation. Idaho Power filed
the present case in compliance with the Stipulation.
Petition - PCA Load Growth Adjustment Factor
The Petition states the load growth adjustment "is intended to compensate for
additional revenues attributable to load growth that occurs between rate cases.Petition at 'i! 1.
Idaho Power explains that the load growth adjustment rate results in a credit during periods of
load growth and results in a debit during periods of load decline. Id.
Idaho Power states the currently approved load adjustment rat~ "uses predicted
marginal costs of serving load rather than embedded costs of serving load.Id. at 'if 3 (emphasis
added). Idaho Power asserts that using "predicted marginal costs" is unfair. Idaho Power
argues that it is more appropriate to use current embedded peA-related costs of serving load to
determine the load growth adjustment rate. Id. The current load growth adjustment rate
approved by the Commission is $16.84 per MWh. Using the embedded peA-related costs of
ORDER NO. 30215
serving load, Idaho Power calculates that the load growth rate should be $6.81 per MWh. Id. at 'if
Idaho Power maintains that using the current marginal cost methodology to calculate
the load growth adjustment multiplier "credits customers with the higher, marginal PCA-related
costs of serving new customer loads, even though Idaho Power is only allowed to recover the
lower, embedded PCA-related costs of serving new customer loads.Id. The Company asserts
this mismatch penalizes Idaho Power when new customers are added. Consequently, Idaho
Power claims it "is not afforded a reasonable opportunity to recover its PCA-related expenses
associated with serving new customer loads in a timely manner.Id.
On May 18 , 2006, the Commission issued Notices of Petition and Intervention
Deadline in Case No. IPC-06-8. Intervention was granted to the Industrial Customers ofIdaho
Power (ICIP), NW Energy Coalition (NWEC; Coalition) and the U.S. Department of Energy.
On October 30, 2006, a technical hearing in Case No. IPC-06-08 was held in
Boise, Idaho. The following parties appeared by and through their respective counsel of record:Idaho Power Company Barton L. Kline
Northwest Energy Coalition William M. Eddie
Advocates for the West
Industrial Customers of Idaho Power Peter Richardson
Mark R. Thompson
Richardson & O'Leary
Commission Staff Scott Woodbury
Deputy Attorney General
A transcript of proceedings was filed with the Commission on December 8, 2006. The positions
of the parties can be summarized as follows:
Idaho Power Company
Idaho Power contends that between rate cases the Company should be permitted to
recover the variable power supply expenses associated with serving load growth. Normalized
power supply expenses are set in general rate cases using historic data. Because expenses
associated with prospective load growth are not used in rate cases, the Company maintains that
the PCA is the only way it can recover prudently incurred variable power supply expenses. Tr.
ORDER NO. 30215
pp. 26 , 32, 35, 51 and 66. Idaho Power argues that the appropriate load growth adjustment
rate is $6.811MWh, the current embedded PCA-related cost of serving load. Reference Case No.
IPC-05-28; Tr. pp. 9, 16, 19.
The current load growth adjustment multiplier of $16.84/MWh used in the PCA true-
up calculation is a marginal cost based rate determined in 1993 when the PCA was instituted. It
was calculated by averaging the fuel costs of the Company s two highest operating cost base-
load resources, Boardman and Valmy, which were the Company-owned resources deemed in
1993 most likely to be dispatched to meet additional loads. Reference Order No. 24806, IPC-
92-25; Tr. pp. 38 65 and 221.
Idaho Power argues that so long as historical test years are used, even annual rate
cases will not allow the Company to recover the additional variable costs attributable to load
growth. Tr. p. 51. To correct this outcome the Company proposes that the load growth
adjustment rate be equal to the embedded PCA-related cost. Tr. p. 18. This is a change in the
approved PCA methodology.
The Company contends it should be afforded a reasonable opportunity to recover the
expenses associated with serving new customer loads because it does not have "discretion not to
serve new customer loads." Tr. p. 17. However, should the Commission reject the Company
embedded cost approach for determining the load growth adjustment factor, Idaho Power
recommends no change in the existing PCA load growth adjustment methodology. The
Company s two highest cost Company-owned base-load resources, it states, continue to be
Valmy and Boardman. In the IPC-05-28 rate case, Valmy cost was $16.51/MWh and
Boardman cost was $ 12.62/MWh. The average of these two numbers, the Company states, is
$ 14.57/MWh. Tr. pp. 39 92.
Alternatively, the Company proposes a load adjustment factor of $17.15, a number
that reflects the marginal cost of Company-owned resources and the occasional operation of the
Company s combustion turbine units. Tr. p. 41; Exhibit 1 , p. 2. It is a Company calculated
number that results from removing surplus sales (FERC Account 447) and off-system purchases
(FERC Account 555) from the marginal cost approach of Staff.
Commission Staff
Staff rejects the embedded cost approach of the Company as not conforming with the
stated intent of the Commission regarding the PCA methodology in Order No. 24806, which was
ORDER NO. 30215
to factor out of the PCA power supply costs associated with changes in load. Order No. 24806
pp. 2 , 20; Tr. pp. 220, 221. The PCA, Staff contends, was created not to provide recovery of
variable power supply expenses associated with serving new load between rate cases, but to
address the problem of fluctuating water conditions that cause widely varying power supply
costs and that had resulted in two Company requests for surcharges. Tr. pp. 218, 232. The costs
attendant to load growth, Staff contends, should appropriately be addressed in a general rate case
where other expenses can be examined and the prudency of all more fully explored. The
elimination of power supply expense related to load growth from the PCA, Staff contends, puts
the Company in no different position than it was prior to the PCA. The Company assumes a risk
for which it is compensated in its return on equity.
Recounting the history of the PCA since its inception, Staff notes that in the
Company s 1994 general rate case, IPC-94-, no change in the marginal cost multiplier was
requested and no testimony concerning the multiplier was submitted. Tr. pp. 222, 223. In the
Company s 2003 and last fully litigated rate case, IPC-03-, Staff proposed use of the
Marginal Cost of Energy" to establish the Expense Adjustment Rate for Growth component of
the PCA formula. The amount from the Company s 2003 Marginal Cost Analysis study was
$27.01lMWh that became $29.41/MWh when 8.9% line losses were included. Tr. p. 223. The
Company in the 03-13 case proposed an Expense Adjustment Rate for Growth of either
$7.30/MWh, the embedded cost of serving load or $13.98/MWh, the marginal cost calculated
consistent with prior Orders. Tr. p. 223. The Commission did not decide to change the
multiplier in that case but granted the request of Staff, Idaho Power and the Department of
Energy to consider adjustments to the EARG in a separate proceeding. Reference Order No.
29505. The multiplier stayed at $ 16.84/MWh but was, by agreement and Commission Order, to
be re-evaluated in' a separate proceeding. Tr. pp. 223 , 224.
The Company s 2005 rate case, IPC-05-28, was not litigated, but was settled prior
to the filing of any Staff or intervenor testimony. The PCA load growth adjustment multiplier
issue was by Stipulation agreement and Commission Order to be determined "as part of the
Company s 2006 PCA application.Stipulation'i! 6(d); Order No. 30035. Tr. p. 224. This is
that proceeding.
Staff recommends a load growth adjustment factor of $40.87/MWh. Exhibit 102; Tr.
p. 235. Both Company embedded cost and Staff proposed marginal cost numbers are derived
ORDER NO. 30215
from the Company s IPC-05-28 AURORA power supply model. Tr. p. 230. Staffs number is
a result of a marginal cost approach that compares two AURORA runs of power supply
expenses, one at 2005 base levels, and one with 2005 base levels incremented by 10 MWa. Staff
results indicate power supply costs $3 578 900 higher than the base amount filed in the
Company s last rate case (IPC-05-, Exhibit 20), a marginal cost of power supply of
$40.86/MWh ($3 578 900/$87 600 MWh). Tr. pp. 146-148. Staffs proposed number, it states
is appropriate if the purpose is not to allow the Company to recover the variable cost of power
supply associated with load growth between rate cases and to also prevent the double counting of
embedded power supply costs. Tr. p. 229.
Staff notes that the electric PCA of Avista Corporation is similar to Idaho Power
Its purpose is to track hydro conditions as they affect power supply costs. Tr. p. 224. Avista
PCA removes power supply costs associated with load growth that occur between rate cases by
multiplying load growth by the marginal cost of power supply and subtracting that amount from
actual power supply costs. In Avista s last general rate case, Case No. A VU-04-01 (Order No.
29602, p. 46), Avista s load change revenue requirement adjustment multiplier was set at
$36.38/MWh. Tr. p. 225.
Idaho Power counters that Staff in its derivation of marginal costs is also requesting a
change in the PCA load growth adjustment factor methodology, a change from a
Valmy/Boardman Company-owned resource fuel cost based number to a power supply model
based number that looks beyond just the cost of Company-owned generation fleet to the value of
power in the marketplace. Tr. pp. 65, 102. Idaho Power objects to Staffs introduction of
marginal surplus sales revenues and marginal purchase power expenses into the marginal cost
equation.
The Company contends that surplus sales exist only because it does not have
additional loads. The Company also argues that it does not have an obligation to serve those
surplus sales customers. It does, however, have an obligation to serve new firm loads. Tr. p. 93.
Removing the benefits derived from surplus sales and the expense of purchased power results in
a Company calculated load growth adjustment number of$17.15/MWh. Tr. pp. 93 , 95.
Company witness Said stated "my only criticism of the use of the (AURORA) model
is that it includes the market value of power at any given time rather than the resource cost that
the Company would use.Tr. p. 122. To the extent that the adjustment rate is greater than the
ORDER NO. 30215
rate that Idaho Power can actually recover, the Company maintains that it is eroding the earnings
that would be associated with other rate components. Tr. p. 27.
Industrial Customers of Idaho Power
The Industrial Customers contend that the marginal cost approach of serving new
load, consistent with Commission Orders , is the correct method for calculating the load growth
adjustment rate used in the true-up portion of the PCA methodology. Tr. p. 146. The PCA, it
states, was not intended to substitute for normal prudency review of costs incurred by Idaho
Power to serve load growth, a review that occurs in rate cases not the PCA. Reference Order No.
24806, p. 20; Tr. pp. 136, 144.
The PCA, ICIP notes, was approved following two separate drought related
surcharges. The PCA was acknowledged as a regulatory method that would provide customers
with a reduction in rates during high water years (Order No. 24806 , pp. 4, 5). The PCA
mechanism, it states, was a limited exception to the usual reliance on normalization procedure
(basing power supply costs on multiple hydro years) - the Commission stating, "our decision is
limited to the unique circumstances of Idaho Power s highly variable power supply costs.
Order No. 24806, p. 5; Tr. p. 135. The PCA's purpose, the Industrial Customers contend, was to
create a system where both Idaho Power and its customers would share in the costs and benefits
of changes in power supply costs, caused primarily by variations in streamflows that occur
between rate filings. Tr. pp. 135, 145.
The Industrial Customers propose three proxy measures for determining the load
growth adjustment rate:
I. The marginal cost study that the Company uses in general rate cases for
rate design. The Company s 2005 Marginal Cost Analysis (August 17
2005) lists "marginal energy cost at service level: power supply" with an
annual value of$40.96/MWh. Tr. p. 147; Exhibit 202, Schedule 1.
2. The AURORA model used to calculate PURP A rates paid to QFs. The
adjustable energy portion of the current published avoided cost rates paid
to QFs (Case No. IPC-04-25) is $36.42/MWh. The value is derived by
using the cost of a Surrogate Avoided Resource - in this case, a natural
gas combined cycle combustion turbine. As it is a Commission
determined avoided resource for Idaho Power, ICIP contends that its fuel
costs are a reasonable proxy for the marginal fuel costs of the Company.
Tr.'p. 147.
ORDER NO. 30215
3. The fuel costs of the Company s newest resource, Bennett Mountain.
Because Bennett Mountain is the last resource brought online by Idaho
Power, it is the marginal unit and its fuel costs are the Company
marginal fuel costs. Based on data provided on page 403 of the
Company s 2005 FERC Form 1 which lists the cost and output of the
Bennett Mountain plant over the course of 2005 , ICIP calculates a
marginal fuel cost of$48.81/MWh. Tr. p. 147.
Because Bennett Mountain is a peaking unit and would run only a few hours a year
Idaho Power contends it is clear that Bennett Mountain would not be the marginal resource
utilized by the Company to meet load growth during all hours of the year. A load growth
adjustment factor based on Bennett Mountain, it contends, would be inaccurate.
NW Energy Coalition
NW Energy Coalition in its testimony discusses the policy implications of the PCA
vis-a-vis conservation and the contemporaneous decoupling proposal in Case No. IPC-04-15.
All ratemaking regulation, it states, provides utilities with incentives or disincentives to behave
in a certain manner. Tr. p. 178. The fact that Idaho Power has disinvested in DSM in the late
1990s in the face of growing loads indicates that the Company is not penalized enough by the
load growth adjustment in the PCA. Tr. p. 184. If the Commission wishes to provide an
incentive toward conservation by providing a penalty, the Coalition states it should do so directly
- not obliquely through the load growth adjustment. Tr. p. 186. The PCA, it contends, provides
an incentive for or against load growth depending on the level of the load growth adjustment.
Tr. pp. 185, 186.
The Coalition recommends that the load growth PCA adjustment be redesigned to
ensure that the PCA is neutral and does not provide any incentive or disincentive regarding load
growth. To accomplish this result the Coalition would restructure the PCA to reimburse the
Company for 90% of the incremental cost of new power, less the incremental revenues received
from the customer, rather than relying on embedded costs that, it contends, have little relation to
the actual net revenue impacts. Separate load growth adjustments would be made for existing
customers and new customers in each customer class. Tr. p. 186.
As an alternative, the Coalition recommends that the load growth adjustment rate be
set so that the PCA includes an adjustment that reflects the average incremental change of load
growth for each class, and does not differentiate between new and existing customers. Tr. p.
187.
ORDER NO. 30215
To provide the Company with a clear incentive to encourage conservation, the
Coalition recommends that the decoupling proposal in Case No. IPC-04-15 be approved in
order to remove the disincentive on the revenue side and either (1) raise the load growth
adjustment another $10 or so from the number determined in the Coalition s primary
recommendation or (2) use direct conservation targets and benchmarks with incentives and
penalties. Tr. p. 190.
The Commission in its deliberation, the Coalition contends, should consider (1) the
04-15 decoupling case, (2) the Company s line extension policy, and (3) rate design. To make
the Company neutral toward load growth and changing customer numbers, neither harmed nor
benefited, all three factors, the Coalition contends, have to be taken into account. Tr. pp. 205d-e
212.
Idaho Power rejected the PCA redesign recommended by the Coalition. Tr. p. 42.
The Company believes the incremental revenue it receives (i.e., the embedded power supply cost
of $6.81/MWh) is more appropriately considered than is the incremental cost of serving new
load. Tr. pp. 42 , 43. A new kilowatt hour of consumption at any specific point in time, the
Company states , will have the same incremental variable power supply cost regardless of the
customer type (new or existing) or customer class (e., residential or commercial) consuming
this power. Tr. p. 43.
The Company also rejects the assumption of the Coalition and other witnesses in this
case that the Company always benefits from load growth. This suggestion, it states, is incorrect
and with the exception of the irrigation class, the incremental fixed costs of serving new loads
for every component (distribution, transmission and generation) between the 2003 test year and
the 2005 test year were higher than the embedded fixed costs of serving the customers. Tr. pp.
47.
Regarding the Coalition s recommendation that the load growth adjustment rate be
increased by $10 per megawatt hour to provide the Company with a clear incentive to encourage
conservation, Idaho Power contends that creation of a PCA load growth penalty is not a means
of removing disincentives to DSM activity. Rather, it states, it is an anti-growth position that
penalizes the Company for growth trends that are beyond its control. Tr. p. 47. DSM programs
identified in its resource plan are not, the Company states, designed with the intent to
ORDER NO. 30215
consistently eliminate load growth. Instead, the Company s DSM programs, it states, are
intended to reshape or reduce consumption in a cost-effective manner. Tr. pp. 47 48.
Creating PCA credits that are greater than the embedded cost of variable power
supply, the Company contends, artificially and unfairly lowers the price customers pay. Creating
PCA credits that are greater than the total rate that a customer pays, it contends, creates an
incentive for customers to consume more in order to reduce per unit costs. Tr. p. 49.
Commission Findings
The Commission has reviewed and considered the filings of record in Case No. IPC-
06-, including the testimony and exhibits included in the hearing transcript. We have also
reviewed the underlying PCA methodology in Order No. 24806, Case No. IPC-92-, and our
review and treatment of the PCA components in subsequent rate case Order Nos. 29505 (Case
No. IPC-03-13) and 30035 (Case No. IPC-05-28).
The PCA methodology established in 1993 by Order No. 24806 was a rate
adjustment mechanism intended to provide earnings stability for the Company in low water
years and ratepayer benefits in high water years. Order No. 24806, p. 25. The Company
application for a PCA mechanism followed its request and receipt of two separate drought
related surcharges. In each surcharge case the Company s financial condition had deteriorated to
the point where additional rate relief was critical.
The PCA adjusts rates annually to reflect hydro related variations in power supply
costs. It was the Company s contention that during extended periods of low water it suffered
earnings instability and cash flow problems because it was unable to recover its increased net
power supply costs, costs that could vary from year to year by more than $100 million. Order
No. 24806, p. 3. Conversely, it was recognized that in years of abundant streamflows with
correspondingly low power supply costs, the Company retained the savings for itself and did not
share them with ratepayers. Id. The PCA design provided symmetry, earnings stability for the
Company in low water years with increased rates and ratepayer benefits in high water years
through reduced rates. Without the PCA the Company s rates would not reflect the annual
difference between actual streamflow conditions and average normalized conditions.
We emphasized in our PCA methodology that our decision was limited to the unique
circumstances ofIdaho Power s highly variable power supply costs. Order No. 24806, p. 5. The
unique circumstances we considered were the variable hydro conditions that affected the
ORDER NO. 30215
Company s power supply costs. Specifically factored out of the PCA methodology were power
supply costs associated with changes in load. Order No. 24806, pp. 2, 20. Idaho Power in this
case now seeks to include what was previously specifically excluded. The Company proposes to
modify the load growth adjustment factor to capture the power supply costs associated with load
growth. The Company contends that with normalization and use of historical test years in rate
cases, it has no opportunity between general rate cases, except for the PCA, to recover load
growth related variable power supply costs.
The Commission notes that load growth between rate cases is not unique to Idaho
Power or electric utilities. The ratemaking process is carefully designed and implemented to
match revenues and expenses for a specified time period, i., a test year. This snapshot of a
company s overall financial position allows the matching of expenses and revenues. It is not
appropriate to select and adjust one part of that picture - for example, power supply costs
associated with load growth - in a process that does not include all other parts that are impacted
such as revenues associated with growth. The Company presents no compelling reason to alter
the traditional and well functioning process and handle load growth outside of general rate cases
and the traditional ratemaking process. There is likewise no persuasive reason to include load
growth related power costs in the PCA.
Additionally, we are not persuaded to modify the PCA to achieve Coalition
objectives. While we are mindful that all ratemaking has built-in incentives and that we need to
avoid ratemaking measures that are at cross-purposes, we are not convinced that adjusting the
PCA for power supply related costs of load growth is a better vehicle for stimulating the
Company s efforts for DSM or conservation than other cases that we will consider soon.
In the PCA methodology case we chose to prevent recovery of load growth related
power costs through the PCA mechanism. It should not be necessary to remind Idaho Power that
a regulated utility is not guaranteed recovery of all power supply expenses. Expenses must be
adjudged to be prudent and must be considered in a process that appropriately matches them
with revenues. Unusual or out of ordinary expenses are factored out in the normalized test year.
Because this process puts the Company at some business and financial risk, it is awarded a
commensurate equity return. Idaho Power s current equity return was set in a process that
recognized it would not recover the power supply costs of load growth in the PCA mechanism.
ORDER NO. 30215
It was demonstrated in this case that continued use of the PCA $16.84/MWh
marginal cost adjustment factor approved in 1993 is not sufficient to factor out the power supply
costs associated with changes in load. While the true adjustment rate may approximate the
$40/MWh number recommended by Staff in this case, we are sensitive to the Company
argument as to how such a large and immediate increase might be perceived within the financial
community and by utility raters, and we wish to maintain the integrity of the rate case matching
principle. We continue to find it reasonable to use a marginal cost based number to establish the
expense adjustment rate for the load growth component of the PCA formula for annual true-ups.
We adopt the $29.4l1MWh adjustment factor proposed by Staff in the Company s IPC-03-
rate case. We find this number to be derived from the $27.01 MWh marginal generation cost in
the Company s 2003 Marginal Cost Analysis study, adjusted for 8.9% line losses. This number
is matched in time with the other rate case revenue and expense levels. We find line loss as
calculated by Staff to be a reasonable adjustment factor to generation required to serve new load
growth for setting the rate in this case.
In adopting a number derived from the Company s 2003 study, we acknowledge that
the power supply numbers included in the IPC-05-28 rate case settlement and reflected in
current rates were the base numbers derived from studies in the Company s IPC-03-13 rate
case. We expect the Company in its next general rate case and in all future rate cases to update
the load growth adjustment factor utilizing its updated marginal cost analysis study and to
provide line loss data. To the extent the Company believes a more accurate line loss calculation
is available, it should provide such methodology in the derivation of its next load growth
adjustment factor.
NWEC Petition for Intervenor Funding
Idaho Code ~ 61-617 A and Rules 161-165 of the Commission s Rules of Procedure
provide the framework for awards of intervenor funding. Section 61-617 A( 1) declares that it is
the "policy of this state to encourage participation at all stages of all proceedings before the
commission so that all affected customers receive full and fair representation in those
proceedings.Accordingly, the Commission may order any regulated utility with intrastate
revenues exceeding $3 500 000 to pay all or a portion of the costs of one or more parties for legal
fees, witness fees, and reproduction costs, not to exceed a total for all intervening parties
combined of $40 000.
ORDER NO. 30215
Rule 162 of the Commission s Rules of Procedure provides the form and content
requirements of a Petition for Intervenor Funding. The petition must contain: (1) an itemized
list of expenses broken down into categories; (2) a statement of the intervenor s proposed finding
or recommendation; (3) a statement showing that the costs the intervenor wishes to recover are
reasonable; (4) a statement explaining why the costs constitute a significant financial hardship
for the intervenor; (5) a statement showing how the intervenor s proposed finding or
recommendation differed materially from the testimony and exhibits of the Commission Staff;
(6) a statement showing how the intervenor s recommendation or position addressed issues of
concern to the general body of utility users or customers; and (7) a statement showing the class
of customer on whose behalf the intervenor appeared.
On November 14, 2006, the NW Energy Coalition filed a Petition for Intervenor
Funding in Case No. IPC-06-08. NWEC's filing is in the form required by Idaho Code ~ 61-
617A and the Commission Rules of Procedure 161-165 , IDAPA 31.01.01.161-165. NWEC
requests funding in the total amount of $6 646., representing $411.20 for airfare, $55.65 for
ground transport and miscellaneous travel costs, and $6 180 of legal expense (41.2 hours ~ $150
per hour).
NWEC contends that payment of the requested costs would constitute a financial
hardship for the Coalition. The Coalition is a non-profit (IRS 501(c)(3)) organization with an
annual budget of slightly more than $600 000. With these limited resources to pay the salaries of
11 staff members, plus overhead, NWEC states that it seeks to influence energy policy decisions
in the four northwest states through participation at state, regional and national venues.
NWEC states that its participation in this case differed materially from Commission
Staffs with respect to both discussion of issues and specific recommendations. NWEC contends
that its witness, Steven Weiss, presented a unique policy discussion and recommendations to the
Commission that differed substantially from Staffs testimony and the testimony of all other
parties. The Coalition recommended the Commission adopt a load growth adjustment for the
PCA, which, as part of an overall rate design, would make Idaho Power neutral to load growth.
To the extent that the Coalition represented a specific Idaho Power customer class, it
contends that it is the residential and small commercial customer.
ORDER NO. 30215
Commission Findings
Pursuant to Idaho Code ~ 61-617 A(2) the Commission may order Idaho Power to
pay all or a portion of the costs of one or more parties for legal fees, witness fees and
reproduction costs not to exceed a total for all intervening parties combined of $40,000 in any
proceeding before the Commission. The total requested by NWEC is $6 646.85. We find that
the Petition of NWEC was filed timely and satisfied all of the procedural requirements set forth
in Rules 161-165 of the Commission s Rules of Procedure.
Idaho Code ~ 61-617 A includes a statement of policy to encourage participation by
intervenors in Commission proceedings. The Commission determines an award for intervenor
funding based on the following considerations:
(a) A finding that the participation of the intervenor has materially
contributed to the decision rendered by the Commission;
(b) A finding that the costs of intervention are reasonable in amount and
would be a significant financial hardship for the intervenor;
(c) The recommendation made by the intervenor differed materially from the
testimony and exhibits of the Commission Staff; and
(d) The testimony and participation of the intervenor addressed issues of
concern to the general body of users or consumers.
We find that NWEC's Petition satisfies these criteria. We find it fair, just and reasonable to
award the total request of NWEC in the amount of $6 646.85 and find that the public interest is
well served by such an award. We find that the intervenor funding award to NWEC will further
the purpose of encouraging "participation at all stages of all proceedings before the Commission
so that all affected customers receive full and fair representation in those proceedings.Idaho
Code ~ 61-617A(1).
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over Idaho Power Company,
an electric utility, and its Petition in this case by virtue of 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 adopt a load growth adjustment factor
ORDER NO. 30215
of $29.41/MWh for use in Idaho Power Company s 2007 PCA filing and in future PCA filings
until changed in a general rate case (or other proceeding) by Commission Order.
IT IS FURTHER ORDERED and Idaho Power is directed in its next general rate
case and in all future rate cases to update the PCA load growth adjustment factor utilizing
updated marginal cost analysis studies and line loss data.
IT IS FURTHER ORDERED that the NW Energy Coalition s Petition for Intervenor
Funding is granted in the amount of $6 646.85. Reference Idaho Code ~ 61-617 A. Idaho Power
is directed to pay said amount to the Advocates of the West, counsel for the Coalition, within 28
days from the date of this Order. Idaho Power shall include the cost of this award of intervenor
funding to NWEC as an expense to be recovered in the Company s next general rate case
proceeding from the residential and small commercial customer classes.
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 ~ 61-626.
ORDER NO. 30215
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this
qf-A.
day of January 2007.
r2r
PAUL KJELLANDER, PRESIDENT
MARSHA H. SMITH, COMMISSIONER
Jbt. ~NER
ATTEST:
bls/O:IPC-O6-08 sw
ORDER NO. 30215