20090109final_order_no_30715.pdf

Office of the Secretary
Service Date
January 9, 2009
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION FOR APPROVAL
OF CHANGES TO ITS POWER COST
ADJUSTMENT (PCA) MECHANISM
ORDER NO. 30715
CASE NO. IPC-08-
On October 14, 2008 , Idaho Power Company filed a Petition requesting a
Commission Order approving changes to the Company s Power Cost Adjustment (PCA)
mechanism as set forth in a Settlement Stipulation filed with the Petition. Consistent with a
previous Commission Order, Idaho Power hosted workshops and settlement discussions
addressing a number of issues and components of the PCA. The discussions resulted in a
settlement signed by Idaho Power, Commission Staff, Micron Technology, the Industrial
Customers of Idaho Power, the u.s. Department of Energy, and the Idaho Irrigation Pumpers
Association. By this Order, the Commission approves the Stipulation and the changes to the
PCA formula.
BACKGROUND
On May 30 2008, the Commission issued Order No. 30563 in Case No. IPC-08-
the Commission s annual Idaho Power PCA review for 2008/2009. In that Order the
Commission noted, regarding a proposal to evaluate the PCA mechanism, that "Staff, Idaho
Power, and the Irrigators all proposed workshops to address issues such as sharing methodology,
forecasting methodology, the distribution of power cost deferrals, and load growth adjustment
rates.The Commission directed Idaho Power to schedule PCA review workshops as soon as
practicable. Order No. 30563, p. 8.
The first PCA workshop was held July 30, 2008, with representatives from Idaho
Power, Commission Staff, Micron Technology, the Industrial Customers of Idaho Power and the
u.s. Department of Energy participating. Two additional workshops were convened on August
13 and September 3, 2008 with irrigation customer class representatives joining the discussions.
On October 14 2008 , Idaho Power filed the PCA Settlement Stipulation, developed as a result of
the workshops and signed by all participating parties. The Company filed direct testimony of
Gregory Said to support its request for approval of the Settlement Stipulation.
ORDER NO. 30715
On November 13 , 2008, the Commission issued a Notice of Application and Notice
of Modified Procedure, establishing a period for the filing of written comments, to process Idaho
Power s Petition. Written comments were filed by Commission Staff; no other party filed
written comments. The record in this case thus consists of the Petition and Stipulation, the
written testimony of Idaho Power s witness, and Staffs written comments. All support approval
of the Stipulation.
THE STIPULATION
The Stipulation, filed as Exhibit No.1 to Mr. Said's testimony, identifies six issues
discussed in the workshops. For each issue, the Stipulation also describes the current PCA
component or process and the proposed solution and rationale for the recommended change. The
first issue is the sharing methodology that assigns purchased power costs or benefits to customers
and shareholders. Since inception of the PCA, annual deviations in normalized power supply
costs have been shared 90%/10% by customers and Company shareholders, respectively. If
costs are below those anticipated, customers receive 90% of the difference. If costs are above
those anticipated, customers pay 90% of the excess costs and the Company absorbs 10%. The
Stipulation changes the sharing percentages to 95% and 5%. The Stipulation states that the
reduced Company share remains sufficient to provide incentive for it to make careful resource
acquisition decisions.Increases in power supply cost volatility and development of the
Company s Risk Management Policy justify the change.
The second issue addressed in the Stipulation is the load growth adjustment rate
(LGAR). The LGAR is part of the PCA mechanism intended to eliminate recovery of power
supply costs associated with load deviations due to weather, growing customer totals or changing
customer usage patterns. The current LGAR is calculated by multiplying the marginal cost of
serving new load by one-half of the difference between current load and the load established in
the Company s last rate case (Case No. IPC-07-08). The current rate is effectively $31.39 per
MWh. The proposed new methodology recognizes that the Company incurs additional power
supply costs to serve new load between rate cases and has no opportunity to collect those costs.
By using three components - a return component, an expense component, and a revenue
component of the production-related rate base - the new calculation recognizes the generation-
related revenue that is collected from new load through rates. The proposed LGAR using the
Stipulation s formula is $28.14 per MWh.
ORDER NO. 30715
The third component addressed in the Stipulation is the PCA forecast. Currently the
power supply forecast is based on estimated stream flow into Brownlee Reservoir. Power supply
costs are estimated using load and natural gas prices as established in the Company s last rate
case. Variations in the forecast from actual expenditures included in rates are collected the
following year through the PCA. The Stipulation recognizes that the current forecast
methodology has created unreasonably large true-ups at annual PCA reviews. The Stipulation
states that forecasting power supply costs based on the Company s existing Operating Plan will
improve forecasts and reduce future true-ups.
The fourth issue in the Stipulation is third-party transmission expense. The
Stipulation states that third-party transmission expenses are a necessary component to facilitate
purchases and sales of energy and thus should be considered to be a power supply expense
although they have not historically been tracked through the PCA. Because these expenses vary
in relation to power purchases and sales, the Stipulation recognizes that they should reasonably
be reflected in the PCA calculation.
The last issue resolved in the Stipulation is power supply expense distribution. Power
supply expenses have been reported monthly based on a computer-modeled distribution. The
Stipulation provides that the power cost distribution should be reported based on a monthly
revenue shape. This adjustment will not affect the PCA calculation of the difference between
actual power purchase expenses and the base net power supply expense, but will make
comparisons easier for interim and annual financial reporting periods.
A final issue addressed in the Stipulation is not resolved. Currently PCA expenses
are allocated to the different customer classes on an equal cents-per-kWh basis. The Stipulation
provides that "this rate spread and revenue allocation needs to be reexamined following Idaho
Power s current general rate case to determine if this methodology needs to be changed.
COMMISSION DISCUSSION
Only the proposed PCA modification to sharing percentages, the LGAR and
transmission cost recovery impact power supply costs the Company will recover and the PCA
rates that customers ultimately pay. We note initially that the PCA is symmetrical, that is, in
above-average water years, power supply costs are below amounts anticipated and customers
receive a credit. In below-average water years power supply costs are above expected costs and
ORDER NO. 30715
customers pay a surcharge. None of the changes agreed to in the Stipulation change the
symmetry of the PCA.
PCA Sharing Ratio
The proposed change that could have the greatest impact on customer rates is the
modification to the sharing percentages. By requiring the Company to pay a portion of the
purchased power expense, set at 10% in the initial PCA formula, the Commission intended the
Company to have a strong incentive to make prudent purchase decisions.There is now
however, significantly greater volatility in the purchased power markets than when the PCA was
established in 1992. Evidence in this case demonstrates that modeled power supply scenarios in
1992 showed annual power supply cost volatility of approximately $100 million dollars, while
power supply cost volatility modeled today is in the $330 million range. Applying the 10%
Company share to power supply costs in 1992 resulted in a potential impact of approximately 50
basis points on Company earnings, and currently the potential impact is twice that amount. For
the period 2001 through 2007, the Company s share of above-normal Idaho jurisdictional power
supply costs totaled approximately $100 million or 95 basis points of equity return per year.
Idaho Power asserts that the existing PCA sharing percentage has affected its credit
rating, resulting in higher borrowing costs that are ultimately paid by its customers. By lowering
the sharing percentage, the Company maintains that credit ratings could improve and interest
costs on debt could decline to the benefit of customers. Despite the Company s assertions
however, the Commission cannot find on the record in this case that a change in the PCA sharing
ratio will assure that the Company s credit rating will improve to any particular level, or that
lower interest rates on debt will generate quantifiable savings for customers. We do find that
power supply cost volatility has increased significantly since the PCA was implemented, and that
with increased volatility, a sharing percentage of 5% still provides strong incentive for the
Company to make prudent power purchases.
The evidence also demonstrates that the Company has taken significant steps to
include other interested parties, including Commission Staff, to collaboratively approach
resource acquisition and mitigate overall power supply cost risks. The Company has developed
a risk mitigation program with customer advisory oversight and has developed resource
acquisition customer advisory groups for integrated resource planning and demand-side
management. These programs that include customer and Commission Staff participation have
ORDER NO. 30715
helped direct the resource acquisition decisions of the Company and, to a greater extent than
before, help to determine power supply costs that flow through the PCA.
Given the potential for lower interest costs, the increased volatility in power supply
costs and improved collaborative resource acquisition processes of the Company, the
Commission finds that a 95%/5% sharing split for customers and the Company is fair, just and
reasonable.
The Load Growth Adjustment Rate (LGAR)
The treatment of growth-related power supply costs in the PCA has been an issue
since the PCA was originally established. Because actual booked power supply costs, including
growth-related costs, are compared to normalized power supply costs without load growth
growth-related costs are automatically included in the PCA without an LGAR. The Commission
recognized this fact and originally established an LGAR of $16.84/MWh, a rate believed to
generally reflect the cost to serve new load on the margin at the time. In 2007, the Commission
increased the LGAR to $29.41/MWh to reflect a more current marginal cost to serve new load.
In Case No. IPC-07-, the Commission approved a comprehensive settlement that established
the LGAR at its current level of $3 2. 14/MWh. The rate is based on a marginal cost to serve new
load of $64.28/MWh but is applied to only 50% of the load growth.
The LGAR of $28. 14/MWh proposed in the Stipulation recognizes the magnitude and
financial impact of serving new load at current marginal costs, the obligation of the Company to
incur new load-related variable power supply cost between rate cases, and the inability of the
Company to recoup these expenditures after the fact through general rates. The proposed LGAR
also recognizes that revenue embedded in new customer rates will offset a significant portion of
the growth-related power supply costs.
The Commission finds that the methodology using marginal power supply costs and
power supply revenue embedded in rates as established in a general rate case provides a
reasonable basis to calculate an appropriate LGAR. The agreement on an LGAR methodology
in the Stipulation represents a reasonable compromise and resolves the issue in a fair and
equitable manner for the Company and its customers. The specific methodology is shown in
Exhibit A to the Settlement Agreement and is Exhibit 1 to this Order.
ORDER NO. 30715
Third-Party Transmission Expense
Third-party transmission expenses have not historically been tracked through the
PCA, even though they are directly associated with the level of off-system sales and purchases.
These expenses are incurred by the Company when transmission is purchased from third parties
outside the Company s transmission network, and the Stipulation recognizes that "third-party
transmission expenses are a necessary component to facilitate purchases and sales of energy and
are reasonably considered a power supply expense." Stipulation p.
The Stipulation provides that the level of transmission costs approved by the
Commission in the Company s most recent rate case is a reasonable basis for calculating
transmission expenses in the PCA. For example, actual 2007 third-party transmission costs were
in the $13 million range. If the Commission includes this amount in base rates set in the
Company s pending rate case, it will also be used as the basis for determining extraordinary
third-party transmission expense in the PCA in the future.
We find that third-party transmission costs are incurred in conjunction with market
purchases and sales and should be tracked through the PCA like other variable power supply
costs. Including third-party transmission expenses in the PCA is a straightforward treatment of
power supply costs that fluctuate with power purchases and sales.
Forecast and Expense Distribution
The remaining issues addressed in the Stipulation do not affect the overall PCA cost
responsibility between customers and shareholders. These issues are forecast of PCA power
supply costs, reporting of power supply expenses during the year, and the rate spread/revenue
allocation that has historically been used in the PCA. The Stipulation recognizes that the current
PCA forecast is flawed and sends inaccurate and improper power supply price signals.
Inaccuracies in river flow forecasts and the power supply modeling create errors in the power
supply forecast when compared to actual power supply expenditures. In addition, the system
load and the gas price forecast used in the power supply model are based on information
established in the last general rate case. The combination of internal modeling inaccuracies and
outdated load and gas price data has resulted in a significant underestimation of power supply
costs and subsequent very large PCA true-ups.
The Stipulation recognizes that the Company s Operating Plan provides the best
forecast available for use in the PCA. The Operating Plan is continually updated based on gas
ORDER NO. 30715
prices, loads, resources, water conditions and other power supply variables. It is the de facto
forecast used by the Company to actually meet system load throughout the year. It is also an
integral part of the Company s Risk Management Program and is subject to review by Staff and
customers as part of the risk management customer advisory group. The Commission finds that
Idaho Power s Operating Plan more accurately forecasts power supply costs, thereby sending a
more accurate price signal to customers and should reduce the magnitude of subsequent PCA
reconciliations.
The distribution of power supply expenses throughout the year used for comparison
to actual expenses has historically been based on the monthly power supply model output. The
evidence shows that this reporting process can create confusion for the financial community by
inappropriately showing large swings between expected and actual earnings on a quarterly basis
and earnings that eventually result on an annual basis. The Commission finds using the monthly
revenue shape to report base net monthly power supply expenses will improve information
disseminated to financial entities without sacrificing appropriate accounting for PCA purposes.
Modeled power supply costs on a monthly basis will be tracked with PCA expense deferrals and
reported to the Commission Staff.
Finally, the Commission approves the Stipulation prOVlSlon calling for later
investigation of the rate spread/revenue allocation that has historically been used in the PCA.
Traditionally, PCA costs have been allocated on an energy-only basis in Commission-approved
cost of service studies, and thus have been spread on an equal cents-per-kWh basis to all
customer classes. Some parties in this case argue that if variable power supply costs tracked
through the PCA are allocated in a general rate case based on demand and energy, then
extraordinary PCA costs should also be allocated on both demand and energy. We direct the
Company and interested parties to review this issue further following conclusion of the
Company s current rate case.
CONCLUSIONS
For the reasons cited above, the Commission finds the terms of the Stipulation to be
fair, just and reasonable, and we approve the Stipulation and the changes to the PCA
methodology set forth in the Stipulation. We find the Stipulation filed by the Company in this
case represents a fair and reasonable resolution of the issues originally identified by the
Commission and as discussed in the workshops.
ORDER NO. 30715
ORDER
IT IS HEREBY ORDERED that the Petition of Idaho Power Company for approval
of the Stipulation and changes to its Power Cost Adjustment mechanism, as set forth in the
Stipulation filed with the Petition, is approved.
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.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this Cf
+A.
day of January 2009.
MACK A. REDFORD, PRESIDENT
ARSHA H. SMITH, COMMISSIONER
4.
~,
JI KEMPTO , CO ISSIONER
ATTEST:
(d~
)e D. Jewell
Co mission Secretary
bls/O:IPC-08-19 ws2
ORDER NO. 30715
EXHIBIT A
LOAD GROWTH ADJUSTMENT RATE ("LGARU) CALCUA TION
SETTLEMENT AGREEMENT
The Parties agree to use the following methodology to determine the Load Growth
Adjustment Rate: The LGAR will consist of three components:
A return component based .upon production-related rate base.
An expense component based upon production-related rate base.
A revenue component based upon production-related rate base.
Component 1: Production-Related Rate Base
The Production-Related Rate Base component would be the result of an IPUC order in
general revenue requirement proceedings. As an example from the current Company
request in Case No. IPC-08-10, page 1 of Exhibit No. 54 contains the demand and
energy comp6nents of rate base allocated to the production function.
Demand
Energy
Total
$428,477 746
$501 479 100
$929 956 845
Assuming the Commission approved cost of capital structure is 50 percent debt and 50
percent equity and the approved overall rate of return is 8.55 percent:
Rate base
Debt
Equity
$929 956 845 (?Y 8.55% = $79 511,310
$464 978,423 ~ 5.85% = $27,201 125
$464 978,423 ~ 11.25% = $52 310 185
The Equity piece is grossed-up for taxes (1.642 multiplier)
Grossed-up Equity
Debt
LGAR Component
$ 85 893 324
27.201....:1 25
$113,094,449
Component 2: Production-Related Expenses
The Production-Related Expenses component would be the result of an (PUC order in
general revenue requirement proceedings. An example from the current Company
request in Case No. (PC-O8-, page 2 of Exhibit No. 54 contains the demand and.
energy components of expenses allocated to the production function.
Demand
Energy
Total
$ 84 862 274
~372.833.595
$457 695 869
STIPULATION -
Exhibit 1
Case No. IPC-08-
I Order No. 30715
The Parties recognize that included in this allocation are expenses related to customer
service, and general and administrative expenses that are not directly associated with
production and are reasonably removed. These amounts can be found in Exhibit 53
page 61 , lines 467 through 485 and Exhibit 53 page 66, lines 489 through 520. The
sum of these exclusions is $40 508 666.
Total from above
Less exclusions
LGAR Component 2
$457 695,869
UO,508.666
$417 187,203
Component 3: Production-Related Revenues
The Production-Related Revenues component would be the result of an IPUC order
general revenue requirement proceedings. An example from the current Company
request in Case No. IPC-08-10, page 3 of Exhibit No. 54 contains the demand and
energy components of revenues allocated to the production function.
Demand
Energy
LGAR Component 3
$ 950 801
$106,270.965
$107 221,766
LGAR Rate
The Load Growth Adjustment Rate (LGAR) is equal to the result of adding Components
1 and 2, subtracting Component 3, and finally dividing by the Commission approved
Idaho jurisdictional firm load.
Component 1:$113 094 449
Component 2:$417 187 203
Component 3:$107 221 766
(1) + (2) - (3)$423,059 886
Idaho jurisdictional load 036 726 MWh (Exhibit 51)
LGAR Rate $28.14/ MWh
STIPULATION -
Exhibit 1
Case No. IPC-08-
Order No. 30715