20081014Said Direct.pdf

RECEIVED
100 OCT , 4 PH 4: 03
UT1d9~~O.PU8UÇCOMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
)
)
) CASE NO. IPC-E-08-19
)
)
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION FOR APPROVAL
OF CHAGES TO ITS POWER COST
ADJUSTMENT (UpCA") MECHAISM
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
GREGORY W. SAID
1 Q.Please state your name and business address.
2 A.My name is Gregory W. Said and my business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what
5 capacity?
6 A.I am employed by Idaho Power Company as the
7 Director of State Regulation in the Pricing and Regulatory
8 Services Department.
9 Q.Please describe your educational background.
10 A.In May of 1975, I received a Bachelor of
11 Science Degree in Mathematics with honors from Boise State
12 University. In 1999, I attended the Public Utility
13 Executives Course at the Uni versi ty of Idaho.
14 Q.Please describe your work experience with
15 Idaho Power Company.
16 A.I became employed by Idaho Power Company in
17 1980 as an analyst in the Resource Planning Department. In
18 1985, the Company applied for a general revenue requirement
19 increase. I was the Company witness addressing power
20 supply expenses.
21 In August of 1989, after nine years in the Resource
22 Planning Department, I was offered and I accepted a
23 position in the Company's Rate Department. With the
24 Company's application for a temporary rate increase in
SAID, DI 1
Idaho Power Company
1 1992, my responsibilities as a witness were expanded.
2 While I continued to be the Company witness concerning
3 power supply expenses, I also sponsored the Company's rate
4 computations and proposed tariff schedules in that case.
5 Because of my combined Resource Planning and Rate
6 Department experience, I was asked to design a Power Cost
7 Adj ustment ( u PCA") which would impact customers' rates
8 based upon changes in the Company's net power supply
9 expenses. I presented my recommendations to the Idaho
10 Public Utilities Commission in 1992, at which time the
11 Commission established the PCA as an annual adjustment to
12 the Company's rates. I sponsored the Company's annual PCA
13 adjustment in each of the years 1996 through 2003. I
14 continue to supervise PCA-related regulatory filings.
15 In 1996, I was promoted to Director of Revenue
16 Requirement. I have managed the preparation of revenue
17 requirement information for regulatory proceedings since
18 that time.
19 Earlier this year, I was promoted to Director of
20 State Regulation adding the area of Rate Design to my
21 responsibilities.
22 Q.What is the purpose of your testimony in
23 this proceeding?
SAID, DI 2
Idaho Power Company
1 A.My testimony in this proceeding is intended
2 to sponsor and support the Stipulation regarding Idaho
3 Power Company's Power Cost Adjustment (UpCA") mechanism
4 (UStipulation"), and to urge the Commission to adopt the
5 Stipulation without material change or condition. The
6 Stipulation is Exhibit No. 1 to my testimony. In my
7 testimony, I will discuss the workshop and settlement
8 discussions leading up to the Stipulation signed by the
9 Company, the Commission Staff, the Industrial Customers of
10 Idaho Power, the Idaho Irrigation Pumpers Association, the
11 Uni ted States Department of Energy, and Micron Technology.
12 These entities are collectively referred to in my testimony
13 as Uthe Parties." I will discuss each of the issues
14 addressed in the Stipulation focusing on the merits of the
15 Stipulation from the Company's perspective and I will
16 discuss the benefits that customers will receive as a
17 result of PCA changes recommended in the Stipulation.
18 Q.Could you briefly describe the PCA and
19 summarize the reasons underlying Idaho Power's support for
20 the adj ustments to the PCA methodology set out in the
21 Stipulation?
22 A.Yes. Idaho Power, like other regulated
23 public utilities, is compensated for historically Unormal"
24 power supply expenses through its base electricity rates
SAID, DI 3
Idaho Power Company
1 established by the Commission in general rate cases.
2 Because the Company's actual power supply expenses have
3 significant variation from year to year while the power
4 supply expense component embedded in base rates is static,
5 the Commission has adopted a PCA that is intended to
6 mi tigate, but not entirely eliminate, the impact of power
7 supply expense variability on the Company's earnings. Net
8 power supply expenses vary from year to year in inverse
9 correlation to the amount of electricity generated by the
10 Company's hydro generation facilities.
11 Although the PCA benefits the Company by reducing
12 the variability associated with power supply expenses,
13 certain elements of the current PCA methodology, such as
14 the usharing methodology" and the uload growth adjustment
15 rate" (uLGAR"), have significantly impaired the Company's
16 ability to earn its authorized rate of return. Two primary
17 conditions in recent years - sustained low water (and
18 resultant low hydro production) and sustained system-wide
19 increased demand for electricity - have significantly
20 amplified the adverse effect of these elements of the PCA
21 methodology on the Company's earnings and cash flow.
22 Q.How do reduced earnings and cash flow affect
23 the Company and its customers?
SAID, DI 4
Idaho Power Company
1 A.The Company's inability to recover its
2 authorized rate of return has, in turn, resulted in
3 deterioration of the Company's credit quality as measured
4 by the national credit rating agencies. Between 2000 and
5 2007, the Company's Standard & Poor's credit rating has
6 dropped four grades, from a rating of uA+" to a rating of
7 UBBB." The credit agencies and financial markets attribute
8 this drop directly to the PCA's sharing formula and LGAR.
9 This lessening of the Company's creditworthiness has
10 direct, adverse financial consequences not just for the
11 Company's shareholders but also for its customers.
12 Impaired financial strength reduces share value to the
13 detriment of shareholders. Moreover, a lower credit rating
14 increases the interest cost of debt, which is borne by the
15 Company's customers. The cumulative additional interest
16 expense of a $100 million, 30-year bond issued by a UBB"
17 rated utility is approximately $60 million greater than a
18 comparable bond issued by an UA" rated utility.
19 Q.Why is the Company credit rating important
20 to customers?
21 A.The Company is undertaking an infrastructure
22 build-out that is unprecedented since its construction of
23 the Hells Canyon complex. The Company currently expects to
24 spend $900 million in construction expenditures in the
SAID, DI 5
Idaho Power Company
1 immediate future (2008 to 2010), excluding any expenditures
2 for a nominal 250-MW combined cycle combustion turbine
3 expected to be in service as early as 2012.Significant
4 additional capital expenditures are expected thereafter.
5 Financing this new infrastructure will be at a much greater
6 cost to the Company's shareholders and customers if its
7 credit ratings remain impaired by the current application
8 of the PCA' s methodology.
9 Q.Please describe the PCA workshop/settlement
10 process leading up to the Stipulation.
11 A.As per Commission Order No. 30563 issued in
12 Case No. IPC-E-08-07, Idaho Power Company held a PCA Issues
13 Workshop on July 30, 2008. At that workshop, the Company
14 identified five PCA issues that it was hopeful the
15 interested parties in the Company's PCA proceeding would
16 agree merited modification on a going-forward basis. The
17 five issues were:
18 1.The PCA sharing ratio
19 2.The Load Growth Adjustment Rate
20 3.The annual PCA forecast
21 4.Third-party transmission expenses
22
23
5.The Power Supply Expense Distribution for
Deferral purposes.
SAID, DI 6
Idaho Power Company
1 The workshop was attended by members of the
2 Commission Staff, representatives for the Industrial
3 Customers of Idaho Power, and representatives for Micron
4 Technology . Representatives for the United States
5 Department of Energy participated via telephone.
6 At the end of the first workshop, Micron suggested
7 adding a sixth issue to address PCA rate spread and revenue
8 allocation to customer classes. The parties agreed that
9 all of the issues identified merited discussion and agreed
10 that further discussions should be considered settlement
11 discussions rather than merely workshops.
12 Subsequently, two settlement meetings were conducted
13 on August 13, 2008, and September 3, 2008, to further
14 discuss the identified issues. The Idaho Irrigation
15 Pumpers Association, which had not participated in the
16 workshop, participated by phone in each of the settlement
17 meetings.
18 Following the September 3rd settlement meeting, the .
19 Company worked with the parties to prepare the settlement
20 Stipulation filed in this case. All participating parties
21 have agreed to and signed the Stipulation. It is my
22 understanding that the Commission Staff will file testimony
23 supporting the Stipulation.
SAID, DI 7
Idaho Power Company
1 Q.Please discuss the agreed-upon change to the
2 PCA sharing ratio.
3 A.The current PCA sharing ratio for non-PURPA
4 power supply expenses is 90 percent customer, 10 percent
5 Idaho Power Company. What that means is that customers are
6 responsible for 90 percent of power supply expense
7 increases above levels included in base rates or that they
8 receive 90 percent of power supply expense decreases below
9 levels included in base rates.
10 The historic rationale supporting the 90/10 sharing
11 ratio has been that it aligns the Company's interests with
12 those of its customers to assure that the Company makes
13 prudent decisions regarding its power supply expenses. The
14 stated reason for the 90/10 percent sharing ratio in the
15 PCA was to incent the Company to make wise decisions with
16 regard to the purchase or sale of energy because the
17 Company was Uon the hook" for 10 percent of expenditures.
18 Several things have changed since the adoption of the
19 current 90/10 sharing ratio that necessitate its change.
20 These changes include:(1) a substantial increase in the
21 magnitude and volatility of power supply expenses; (2)
22 development of the Company's Risk Management Policy; (3)
23 the shift of the Federal Energy Regulatory Commission
24 (UFERC") away from setting wholesale rates based on cost-
SAID, DI 8
Idaho Power Company
1 of - service and towards wholesale rates based on market
2 prices; and (4) reduced base flows in the Snake River
3 system, combined with continuous years of sustained drought
4 and sustained system load growth.
5 The combined impact of these changes has
6 substantially increased the magnitude and volatility of
7 power supply expenses since the original implementation of
8 the PCA.
9 Q.Can you provide an example of this increased
10 magnitude and volatility?
11 A.Volatility in power supply expenses from
12 high to low water conditions based upon modeled scenarios
13 was slightly over $100 million in 1992 when the PCA was
14 first implemented. Volatility in modeled power supply
15 expense scenarios is now over $330 million. When the 90/10
16 sharing ratio was initially established, the 10 percent
17 component represented approximately 50 basis points of the
18 Company's earnings. Today, because of the many changed
19 conditions referenced below, the 10 percent sharing ratio
20 represents more than 100 basis points of Company earnings.
21 Modifying the sharing ratio to 95/5 simply restores the
22 Company's risk parameter to approximately 50 basis points
23 of earnings.
SAID, DI 9
Idaho Power Company
1 Q.How has the development of the Company risk
2 management policy affected net power supply expense
3 volatility?
4 A.To address power supply expense volatility,
5 the Company worked closely with its customers to develop
6 the Company's Risk Management Policy. The Risk Management
7 Policy establishes a prescriptive buying and selling
8 policy. Before the energy crisis of 2000 and 2001, the
9 Company exercised considerable discretion with regard to
10 the advance purchase of energy for anticipated future
11 deficiencies or the advance sale of energy for anticipated
12 future surpluses. Following the energy crisis, the
13 Commission directed the Company to adopt a prescriptive
14 Risk Management Policy to mitigate risk associated with
15 hydro and market price variability. The risk management
16 policy is conservatively biased to provide adequate
17 resources to meet anticipated demand and to protect against
18 extremes in market electricity prices. As a result, the
19 process is now far more prescriptive in nature than when
20 the PCA was adopted. With a prescriptive buying and
21 selling policy driving the vast majority of the Company's
22 energy purchases and sales, the need for the incentive
23 provided by the sharing methodology is reduced
24 significantly, if not eliminated entirely.
SAID, DI 10
Idaho Power Company
1 Q.How have the parties to the Stipulation
2 agreed to address the sharing ratio to address volatility?
3 A.Given the changes in power supply expense
4 volatility and the prescriptive nature of the Company's
5 Risk Management Policy, the parties to the Stipulation
6 agree that shifting the sharing ratio to 95 percent
7 customer, 5 percent Idaho Power Company is reasonable. As
8 a result, customers will be responsible for 95 percent of
9 power supply expense increases above levels included in
10 base rates or will receive 95 percent of power supply
11 expense decreases below levels included in base rates.
12 Conversely, the Company will have only 5 percent exposure
13 to the higher power supply expense volatility rather than
14 10 percent. The Parties agree that this PCA sharing ratio
15 change is fair, just, and reasonable, and aligns with the
16 original intent of the PCA sharing methodology.
17 Q.Please discuss the stipulated change in the
18 Load Growth Adjustment Rate.
19 A.The Load Growth Adjustment Rate (ULGAR") has
20 been a topic of frequent and divergent debate over the
21 years. Rather that rehashing the discussions of the past,
22 I will focus on the stipulated change to the LGAR. The
23 Parties agree that the intent of the LGAR is to eliminate
24 recovery of that component of power supply expenses
SAID, DI 11
Idaho Power Company
1 associated with load growth resulting from changing weather
2 conditions, a growing customer base, or changing customer
3 usage patterns. The agreed-upon method for computing the
4 LGAR recognizes generation-related revenue that results
5 from the growth drivers that I have just described and will
6 be quantified at the end of each general rate case. The
7 stipulated LGAR methodology consists of three components, a
8 return component, expense component, and a revenue
9 component of the production related rate base. An example
10 of the agreed-upon LGAR computation is contained in Exhibit
11 A to the Stipulation. All Parties have agreed that the
12 calculation set forth in Exhibit A to the Stipulation is
13 fair, just, and reasonable and accomplishes the stated
14 intent of the LGAR. Acceptance of the LGAR computation
15 contained in the Stipulation will resolve a long-standing
16 dispute to the satisfaction of all Parties to the
17 Stipulation.
18 Q.Please discuss the agreed-upon change in the
19 PCA forecast methodology set out in the Stipulation.
20 A.Since the inception of the PCA, the PCA
21 forecast methodology has been based upon a single input.
22 Each April the National Weather Service's Northwest River
23 Forecast Center (UNWRFC") makes a stream flow forecast upon
24 which the PCA forecast is based. Proj ected expenses are
SAID, DI 12
Idaho Power Company
1 calculated by using a natural logarithmic function of a
2 single variable - proj ected April through July Brownlee
3 reservoir inflows. Variations in this forecast from actual
4 expenditures included in rates are collected the following
5 year. Thus, the more accurate the forecast is, the smaller
6 the amount that accrues in the deferral for inclusion with
7 the following year's PCA rates during the Utrue-up." The
8 better the forecast, the smaller the subsequent year true-
9 up amount. All parties agree that the best possible
10 forecast should be utilized. All parties agree that the
11 Company's Operation Plan is the best available forecast of
12 power supply expenses.
13 Q.Please discuss the parties' agreement to
14 include third-party transmission expenses in PCA
15 computations.
16 A.Third-party transmission expenses are
17 incurred by the Company in order to facilitate either
18 purchases of energy from or sales of energy to various
19 trading hubs. As an example, a purchase of energy from the
20 Mid-C trading hub requires wheeling the power to the
21 Company's system and, conversely, the sale of energy at the
22 Mid-C hub requires wheeling the power from the Company's
23 system to the Mid-C hub. Variability of third-party
24 transmission wheeling expense is directly related to the
SAID, DI 13
Idaho Power Company
1 volumes of purchases from and sales of energy to entities
2 that are some distance from the Company's service territory
3 boundaries. The Parties agree that third-party
4 transmission expenses are directly related to power supply
5 expenses and should therefore reasonably be included in PCA
6 computations.
7 Q.Please discuss the stipulated change in the
8 Power Supply Expense Distribution for PCA true-up
9 computations.
10 A.Historically, power supply expenses were
11 reported throughout the year using an AURORA-based
12 distribution. In order to provide the financial community
13 more transparent and understandable financial
14 communications, the parties agree that for purposes of PCA
15 deferral reporting, the Base Net Power Supply Expenses will
16 be distributed to monthly values based upon a monthly
17 revenue shape. This adjustment will not affect the total
18 PCA year calculation of the deviation between actual and
19 Base Net Power Supply Expenses, but will improve
20 comparability between interim and annual financial
21 reporting periods.
22 Q.Please comment on the discussion in the
23 Stipulation regarding rate spread and revenue allocation
24 within PCA computations.
SAID, DI 14
Idaho Power Company
1 A.The Parties recognize the PCA rates are
2 implemented on a 100 percent energy basis. The Parties
3 agree that rate spread and revenue allocations will be
4 examined as part of the current general rate case and that
5 such examination may suggest changes to PCA rate design as
6 well. The Parties agree to a reexamination of PCA rate
7 design following the general rate case.
8 Q.Please describe the benefits that Idaho
9 Power Company's Idaho jurisdictional customers will receive
10 as a result Commission approval of this Stipulation.
11 A.I believe that Idaho Power Company's Idaho
12 jurisdictional customers will benefit from each of the
13 areas of agreement contained in the Stipulation.
14 First, as a result of the change in the PCA sharing
15 ratio, customers will get a more accurate picture of their
16 true power supply related cost-of-serVice as it fluctuates
17 wi th water and market conditions. By adj usting the sharing
18 ratio to 95%/5% from 90%/10%, the intent of the sharing
19 ratio's impact on the Company will be more closely
20 realigned to the impact envisioned at the time the PCA was
21 initiated.
22 Second, as a result of the stipulated change to the
23 LGAR rate determination, customers are assured that double
24 recovery of power supply expenses will not occur and a
SAID, DI 15
Idaho Power Company
1 major concern of the financial community will be mitigated.
2 This should benefit customers in both the short and long
3 runs.
4 Third, as a result of the stipulated change to the
5 PCA forecast methodology, PCA forecasts should be improved
6 from PCA forecasts of the past. With more accurate
7 forecasts, true-ups will be reduced making annual changes
8 to PCA rates more understandable to customers. PCA rates
9 should be primarily the result of the upcoming year's power
10 supply expenses rather than a result of truing-up the
11 previous year's power supply expenses.
12 Fourth, including third-party transmission expenses
13 in PCA computations assures alignment of cost
14 considerations to the benefit of both the Company and its
15 customers.
16 Fifth, utilizing a power supply expense distribution
17 based upon a revenue shape, for deferral purposes, provides
18 for more understandable quarterly earnings statements.
19 Customers benefit when the financial community understands
20 key drivers of the Company's earnings.
21 Finally, the totality of these changes to the PCA
22 should help the Company retain or improve its credit
23 ratings. Both the Company and its customers benefit from
24 favorable credit ratings from the national credit rating
SAID, DI 16
Idaho Power Company
1 agencies, especially given the large capital expenditures
2 that are planned and necessary in the near future.
3 Q.Given the customer benefits to be derived
4 from Commission approval of the Stipulation, what is your
5 recommendation to the Commission?
6 A.I recommend that the Commission find the
7 Stipulation to be in the public interest and approve the
8 same without change or conditions. I further recommend
9 that the Commission direct the Company to implement changes
10 to the PCA consistent with the terms of the Stipulation.
11 Q.Does that conclude your testimony?
12 A.Yes, it does.
SAID, DI 17
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-08-19
IDAHO POWER COMPANY
SAID, DI
TESTIMONY
. EXHIBIT NO. 1
BARTON L. KLINE (ISB No. 1526)
DONOVAN E. WALKER (ISB No. 5921)
Idaho Power Company
1221 West Idaho Street
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: 208w338-6936
bklinecaidahopower.com
dwalker((idahopower.com
Attorneys for Idaho Power Company
Street Address for Express Mail:
1221 West Idaho Street
Boise, Idaho 83702
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 )
)
CASE NO. IPC-Ew08-19
STIPULATION
This stipulation ("StipulationJl) is entered into by and among Idaho Power
STIPULATION -1
Exhibit No. 1
Case No. IPC~E-08-19
G. Said, Idaho Power Company
Page 1 of 17
I. INTRODUCTION
1. The terms and conditions of this Stipulation are set forth herein. The
Parties agree that this Stipulation represents a fair, just and reasonable compromise of
the issues raised in this proceeding and that this Stipulation is in the public interest.. ,
The Parties maintain that this Stipulation and its acceptance by the Idaho Public Utilties
Commission ("i PUC" or the "Commission") represent a reasonable resolution of multiple
issues identified in this matter. The Parties, therefore, recommend that the
Commission, in accordance with RP 274, approve the Stipulation and all. of its terms
and conditions without material change or condition.
II. BACKGROUND
2. In the settlement Stipulation for Idaho Power's 2007 general rate case, the
Parties agreed that they would "make a good faith effort to develop a mechanism to
adjust or replace the current Load Growth Adjustment Rate (LGAR) to address cost of
serving load growth between rate cases." Stipulation at pA, Case No. IPC-E-07 -08. In
the Commission's final Order for the 2008-2009 Power Cost Adjustment ("PCA") .case
the Commission stated:
With respect to further evaluation of the PCA mechanism,
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. We support
these proposals and direct Idaho Power to schedule such
workshops as soon as practicable.
Order No. 30563 at p.6w7, Case No. IPC-E"08-07.
3. Idaho Power held three workshops where issues related to the PCA
mechanism were discussed. All of the Parties to this Stipulation participated in the
STIPULATION - 2
Exhibit No. 1
Case No. IPC-E-08-19
G. Said, Idaho Power Company
Page 2 of 17
workshops. The first workshop, held on July 30, 2008, introduced the issues. The
second and third workshops, held on August 13, and September 3, 2008, respecively,
consisted of continued dialogue on the relevant issues, as well as discussions regarding
the consensus of the Parties, which is represented by the terms of this Stipulation.
4. Idaho Power, like other regulated public utilties in Idaho, is compensated
for historically "normal" power supply expenses through its base electricity rates
established by the Commission in general rate cases. Because the CompanyJs actual
power supply expenses have . significant variation from year. to year, while the power
,
supply expense component embedded in base rates is static, the Commission has
adopted a PCA that is intended to mitigate, but not entirely eliminate, the impact of
power supply expense variabilty on the Company's earnings. Net power supply
expense~ vary from year to year in inverse correlation to the amount of electricity
generated by the Company's hydro generation facilties.
Although the PCA benefits the Company by reducing the variabilty associated
with power supply expenses, certain elements of the PCA methodology, such as the
"sharing methodology" and the "load growt adjustment rate" can reduce the
Company's abilit to earn its authorized rate of return. Two primary conditions in recent
years - sustained low water (and resultant low hydro production) and sustained system-
wide increased demand for electricity - have amplified the adverse effect of these
elements of the PCA methodology on the Company's earnings and cash flow.
In the workshops, Idaho Power presented evidence that the Company's inabilty
to recover its authorized rate of return is one of the reasons for the deterioration of the
Company's credit qualit as measured by the national credit rating agencies over the
STIPULATION - 3
Exhibit NO.1
Case NO.IPC-E-08-19
G. Said, Idaho Power Company
Page 3 of 17
last several years. The evidence presented by the Company included statements from
analysts noting that this summer the Company's inabilit to fully recover power supply
expenses, coupled with capital expansion outlays, have gradually whittled away the
Company's financial strength. These factors contributed to Standard and Poors recent
downgrade of IDACORP and Idaho Power debt and to Moody's placement of IDACORP
and Idaho Power debt on watch for possible downgrade from its current ratings leveL.
Deterioration of the Company's credit rating has increased the cost to access capital
and resulted in increased costs to customers.
5. Based upon the discussions and consensus among the Parties at the
workshops, as a compromise of the positions in this case, and for other consideration as
set forth below, the Parties agree to the following terms:
II. TERMS OF THE STIPULATION
6. Sharing Methodology. The PCA Sharing Methodology establishes a fixed
allocation of non"PURPA power supply expenses between customers (90%) and
shareholders (10%). The Parties agree to change the current 90%/10% Sharing
Methodology to 95%/5%. When the 90%/10% Sharing Methodology was initially
established, the 10% component represented approximately 50 basis points of the
Company's earnings. Today, because of the many changed conditions referenced
below, the 10% sharing component represents more than 100 basis points of Company
earnings. Modifying the Sharing Methodology to 95%/5% restores the Company's risk
parameter to approximately 50 basis points of earnings.
The historic rationale for the 90%/10% sharing has been to assure that the
Company's interests are aligned with those of the customer, and that the Company
STIPULATION -4
Exhibit NO.1
Case No. IPC-E-08-19
G. Said, Idaho Power Company
Page 4 of 17
makes prudent decisions regarding its power supply expenses. The stated reason for
the 90%/10% sharing ratio in the PCA was to incent the Company to make wise
decisions with regard to the purchase or sale of energy because the Company was "on
the hook'. for 10% of expenditures. Two things have changed since the adoption of the
Sharing Methodology that necessitte its change: (1) a substantial increase in the
magnitude and volatilit of power supply expenses driven by market and fuel pñce
volatilty coupled with increasing loads and (2) development of the Company's Risk
Management Policy.
The more significant change is the fact that the magnitude and volatilty of power
supply expenses have increased substantially since the initial implementation of the
PCA. Volatilit from high to low water conditions has increased from the expectation of
slightly over $100 milion in 1992 to over $330 millon based upon modeled scenarios.
This large increase in magnitude and volatilit is primarily attributable to a fundamental
change in market conditions and increased loads.
The other significant change directly related to supporting a change in the
Sharing Methodology is the development of the Company's prescriptive "Risk
Management Policy." Before the western energy crisis of 2000 and 2001, the Company
exercised considerable discretion with regard to the advance purchase of energy for
anticipated future deficiencies or the advance sale of energy for anticipated future
surpluses. As a direct result of high PCA rates duñng the energy crisis. the
Commission directed the Company, Commission Staff, and customer groups to
formulate a Risk Management Policy to mitigate ñsk associated with hydro and market
price variabilty. The Risk Management Policy is conservatively biased to provide
STIPULATION - 5
Exhibit NO.1
Case No. IPC-E-08-19
G. Said, Idaho Power Company
Page 5 of 17
adequate resources to meet anticipated demand and to protect against extremes in
market electricit prices. As a result, the market purchase and sale process is now far
more prescriptive in nature than when the PCA was adopted. With a prescriptive buying
and sellng policy driving the vast majori of energy purchases and sales, the need for
the incentive provided by the Sharing Methodology is reduced.
The Parties agree that given the change in circumstances since the PCA was
initially instituted, changing the 90%/10% Sharing Methodology to 95%/5% is fair, just,
and reasonable, and aligns with the original intent of the Sharing Methodology. The
Parties agree that the new 95%/5% Sharing Methodology should .be effective on the first
day of the month following Commission approval of this Stipulation.
7. Load Growth Adjustment Rate. The LGAR is an element of the current
PCA formula intended to eliminate recovery of that component of power supply
expenses associated with load growth resulting from changing weather conditions, a
growing customer base, or changing customer usage patterns. The Parties agree to
calculate the LGAR using three components, a return component, an expense
component, and a revenue component of the production related rate base. This
methodology recognizes the generation-related revenue that wil be provided through
base rates by load growth. The LGAR components used in the methodology wil be
updated with other PCA inputs at the conclusion of a general rate case. An example of
the agreed upon calculation is shown in Exhibit A to this Stipulation.
Incident to the PCA true-up, LGAR is currently calculated by comparing actual
system load with normalized system load established in the most recent general rate
case. The diference in megawatt hours is divided by two and multiplied by $62.79.
STIPULATION - 6
Exhibit No. 1
Case No. IPC-E-08-19
G. Said. Idaho Power CompanyPage6of17
When actual load is greåter than normalized base system load, the Company refunds
the difference (subject to the sharing formula) to the customer and records increased
.PCA expense. Because normalized system load is determined in a general rate case
using a historical test year, and because the Company continues to experience system
wide growth, the LGAR has consistently had an adverse effect on the Company's
earnings.
The initial LGAR rate was $16.84 per MWh. The current effective LGAR from the
IPC-E-07 -0-8 rate case is $31.40. The previous determination from the IPC-E-06-08
LGAR case was $29.41 per MWh. The LGAR calculation, using the methodology
agreed to by the Parties in this Stipulation, along with the filed data from the IPC-E-08-
10 rate case is $28.14 per MWh, as shown in Exhibit A. The Parties agree that the
calculation set fort in Exhibit A is fair, just, and reasonable. The Parties agree that the
new LGAR methodology should become effective when its components are established
and new rates implemented as a result ofthe IPC-E-08-10 general rate case.
8. The Forecast. Each April the National Weather Service's Northwest River
Forecast Center ("NWRFC") makes a stream flow forecast upon which the PCA forecast
is based. Projected expenses are calculated by using a natural logarithmic function of a
single variable - projected April through July Brownlee reservoir inflows. Variations in
this forecast from actual expenditures included in rates are collected the following year.
Thus, the more accurate the forecast is, the smaller the amount that accrues in the
deferral for inclusion with the following year's PCA ''te-up'' rate. All Parties agree that
it is in everyone's best interest to have the most accurate forecast of PCA year
expenses for the annual April 15th PCA filings. The Parties also agree that the
STIPULATION - 7
Exhibit No. 1
Case NO.IPC-E-08-19
G. Said, Idaho Power Company
Page 7 of 17
regression formula used in the past is no longer the best forecast tool. Comparing
forecsts used by the Company in developing its Operation Plan to historical PCA filings
shows that the Operation Plan forecast is a more accurate PCA year forecast than the
regression formula. The Parties agree that the Company's forecast based upon its
Operation Planning tools is the current best forecast and should be utilzed for annual
filings. The Parties agree that the Operation Plan forecast should be utilzed for the
Company's next annual PCA rate filing.
9. Third-Part Transmission Expense. The Parties agree that thirdwpart
transmission expenses are a necessary component to faciltate purchases and sales of
energy and are reasonably considered a power supply expense. These third-part.
transmission expenses are reflected in two FERC accounts: Account 555, purchased
power, and Account 565, transmission of elecricity by others. Third-part transmission
wheeling expenses necessary to faciltate purchases and sales of energy have been
recorded in Account 565. Transmission expenses paid to third-parties for replacement
of their transmission losses have been recorded in Account 555. Historically, neither of
these items has been reflected in PCA computations. The Parties agree that deviations
in these types of expenses from levels included in base rates should reasonably be
reflected in peA computations. In the future, the entire Accunt 555 wil be tracked by
the PCA as wil Account 565. The Parties agree that third-part transmission expense
including losses be included when the base is established as a result of the IPC-E-08-
10 general rate case.
10. -Power Supply Expense Distribution. Historically, power supply expenses
were reported throughout the year using an AURORA based distnbution. In order to
STIPULATION - 8
Exhibit No. 1
Case NO.IPC-E-08-19
G. Said, Idaho Power Company
Page 8 of 17
provide the financial community more trnsparent and understandable financial
communications, the Parties agree that for purposes of PCA deferral reporting, the
Base Net Power Supply Expenses wil be distributed to monthly values based upon a
monthly revenue shape. This adjustment wil not affect the total PCA year calculation of
the deviation between actual and Base Net Power Supply Expenses but will improve
comparabilty between interim and annual financial reporting periods. A shadow PCA
report that shows the PCA impacts associated with using an AURORA based
distribution of power supply expenses wil be provided to Commission Staff. The
Parties agree that the new Power Supply Expense Distribution wil be utilzed when
base rates are changed as a result of the IPC-E-08-10 general rate case.
11. Rate Spread/Revenue Allocation. PCA expenses are currently allocated
to the various customer classes based almost 100% on energy. The Parties agree that
this rate spread and revenue allocatiön needs to be reexamined following Idaho
Power's current general rate case to determine if this methodology needs to be
changed.
12. The Parties agree that this Stipulation represents a compromise of the
positions of the Parties in this case. As provided in RP 272, other than any testimony
filed in support of the approval of this Stipulation, and except to the extent necessary for
a Part to explain before the Commission its own statements and positions with respect
to the Stipulation, all statements made and positions taken in negotiations relating to
this Stipulation shall be confiential and wil not be admissible in evidence in this or any
other proceeding.
STIPULATION - 9
Exhibit No. 1
Case NO.IPC-E-08-19
G. Said, Idaho Power Company
Page 9 of 17
13. The Parties submit this Stipulation to the Commission and recommend
approval in its entirety pursuant to RP 274. Parties shall support this Stipulation before
the Commission, and no Part shall appeal a Commission Order approving the
Stipulation or an issue resolved by the Stipulation. If this Stipulation is challenged by
any person not a part to the Stipulation, the Parties to this Stipulation reserve the right
to file testimony, cross-examine witnesses and put on such case as they deem
appropriate to respond fully to the issues presented, including the right to raise issues
that are incorporated in the settlements embodied in this Stipulation. Notwithstanding
this reservation of rights, the Parties to this Stipulation agree that they wil continue to
support the Commission's adoption of the terms of this Stipulation.
14. If the Commission rejects any part or all of this Stipulation, or imposes any
additional material conditions on approval of this Stipulation, each Part reserves the
right, upon written notice to the Commission and the other Parties to this proceeding,
within 14 days of the date of such action by the Commission, to withdraw from this
Stipulation. In such case, no Part shall be bound or prejudiced by the terms of this
Stipulation, and each Part shall be entitled to seek reconsideration of the
Commission's order, file testimony as it chooses, cross-examine witnesses, and do all
other things necessary to put on such case as it deems appropriate. In such case, the
Parties immediately wil request the prompt reconvening of a prehearing conference for
purposes of establishing a procedural schedule for the completion of the case. The
Parties agree to cooperate in development of a schedule that concludes the proceding
on the earliest possible date, taking into accunt the needs of the Parties in participating
in hearings and preparing briefs.
STIPULATION -10
Exhibit No.1
Case No. IPC-E-08-19
G. Said, Idaho Power Company
Page 10 of 17
15. The Parties agree that this Stipulation is in the public interest and that all
of its terms and conditions are fair, just, and reasonable.
16. No Part shall be bound, benefited, or prejudiced by any position asserted
in the negotiation of this Stipulation, except to the extent expressly stated herein, nor
shall this Stipulation be construed as a waiver of the rights of any Part unless such
rights are expressly waived herein. Execution of this Stipulation shall not be deemed to
.constitute an acknowledgment by any Part of the validity or invalidity" of any particular
method, theory, or principle of regulation or cost recovery. No Part shall be deemed to
have agreed that any method, theory, or principle of regulation or cost recovery
employed in arriving at this Stipulation is appropriate for resolving any issues in any
other proceeding in the future. No findings of fact or conclusions of law other than those
stated herein shall be deemed to be implicit in this Stipulation.
17. The obligations of the Parties under this Stipulation are subject to the
Commission's approval of this Stipulation in accordance with its terms and ~nditions
and upon such approval being upheld on appeal, if any, by a court of competent
jurisdiction.
18. This Stipulation may be executed in counterparts and each signed
counterpart shall constitute an original document.
DATED this 14th day of October 2008.
Idaho Power Company Idaho Public Utilties Commission Staff
By Ú::t;)øL
Donovan E. Walker
Attorney for Idaho Power Company
(1,."' ~
By
Weldon Stutzman
Attorney for IPUC Staff
STIPULATION -11
Exhibit NO.1
Case No. IPC-E-08-19
G. Said, Idaho Power Company
Page 11 of 17
. n Pumpers Association, Inc.
Eric L. Olsen
Attorney for Idaho Irrigation Pumpers
Association, Inc.
Micron Technology, Inc.
By
Conley E. Ward
Attorney for Micron Technology, Inc.
STIPULATION - 12
Industrial Customers of Idaho Power
By
Peter J. Richardson
Attorney for Industrial Customers
of Idaho Power
u.s. Departent of Energy
By
Lot H. Cooke
Attorney for U.S. Department of
Energy
Exhibit No. 1
Case No. IPC-E-08-19
G. Said, Idaho Power Company
Page 12 of 17
Idaho Irrigation Pumpers Association, Inc.
By
Eric L. Olsen
Attorney for Idaho Irrigation Pumpers
Association, Inc.
Micron Technology, Inc.
By
Conley E. Ward
Attorney for Micron Technology, Inc.
STIPULATION -12
Industrial Customers of Idaho Power
ByiJdl~
Peter J. Richardson
Attorney for Industrial Customers
of Idaho Power
u.s. Department of Energy
By
Lot H. Cooke
Attorney for u.s. Department of
Energy
Exhibit No. 1
Case No. IPC-E-08-19
G. Said, Idaho Power Company
Page 13 of 17
Idaho Irrgation Pumpers Association, Inc.
By
Eric L. Olsen
Attorney for Idaho Irrgation Pumpers
Association, Inc.
Micron Technology, Inc.
By-Q!i~ 0,
Attorney for Micron Technology, Inc.
STIPULATION - 12
Industrial Customers of ldaho Power
By
Peter J. Richardson
Attorney for Industrial Customers
of Idaho Power
u.s. Department of Energy
By
Lot H. Cooke
Attorney for U.S. Department of
Energy
Exhibit No. 1
Case NO..IPC-E-08-19
G. Said, Idaho Power Company
Page 14 of 17
Idaho Irrigation Pumpers Association, Inc.
By
Eric L. Olsen
Attorney for Idaho Irrigation Pumpers
Association, Inc.
Micron Technology, Inc.
By
Conley E. Ward
Attorney for Micron Technology, Inc.
STIPULATION -12
Industrial Customers of Idaho Power
By
Peter J. Richardson
Attorney for Industral Customers
of Idaho Power
u.s. Department of Energy
ByAicJ
Lot H. Cooke
Attorney for U.S. Departent of
Energy
Exhibit No. 1
Case No. IPC-E-08-19
G. Said, Idaho Power Company
Page 15 of 17
EXHIBIT A
LOAD GROWT ADJUSTMENT RATE ("LGARU) CALCUATION
SETTLEMENT AGREEMENT
The Parties agree to use the following methodology to determine the Load Growth
Adjustment Rate: The LGAR wil consist of three components:
1. A return component based .upon production-related rate base.
2. An expense component based upon production-related rate base.
3. 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 currnt Company
request in Case No. IPC-E-08-10, page 1 of Exhibit No. 54 contains the demand and
energy components 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 equit and the approved overall rate of return is 8.55 percent:
Rate base
Debt
Equity
$929,956,845 ~ 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 1
$ 85,893,324
$ 27.201.125
$113,094,449
Component 2: Production-Related Expenses
The Production-Related Expenses component would be the result of an IPUC order in
general revenue requirement proæedings. An example from the current Company
request in Case No. IPC-Ew08-10, 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 -13
Exhibit NO.1
Case No. IPC-E-08-19
G. Said, Idaho Power Company
Page 16 of 17
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, Jines 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
S 40,508,666
$417,187,203
Component 3: Production-Related Revenues
The Production-Related Revenues component would be the result of an IPUC order in
general revenue requirement proceedings. An example from the current Company
request in Case No. IPC-E-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
S106,270,965
$107,221,766
LGARRate
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 :
Component 2:
Component 3:
(1) + (2) - (3)
Idaho jurisdictional load
$113,094,449
$417,187,203
$107,221,766
$423,059,886
15,036,726 MWh (Exhibit 51)
$28.14/ MWhLGARRate
STIPULATION -14
Exhibit No. 1
Case No. IPC-E-08-19
G. Said, Idaho Power Company
Page 17 of 17