20110228final_order_no_32196.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF PACIFICORP DBA ROCKY MOUNTAIN ) CASE NO. PAC-E-I0-07
POWER FOR APPROVAL OF CHANGES TO )
ITS ELECTRIC SERVICE SCHEDULES ) ORDER NO. 32196
)
Issued February 28, 2011
Boise, Idaho
Portions of this Order Relating to the
Economic Valuation of Monsanto's Interrptible Credit
Are Confidential
Offce of the Secretary
Service Date
Februar 28, 20 i i
TABLE OF CONTENTS
SUMMARy....................................................................................................................................1
APPLICATION .............................................................................................................................. 2
APPEARANCES ............................................................................................................................3
PUBLIC WORKSHOPS, HEARINGS AND COMMENTS ......................................................... 4
DISCUSSION ................................................................................................................................. 5
i. TEST YEAR, CAPITAL STRUCTURE AND RATE OF RETURN ....................................... 6
A. Test Year ............................................................................................................................... 6
B. Capital Structure and Rate of Retur .................................................................................... 6
(l) Capital Structure, Cost of Debt (long-term), Cost of Preferred Stock ............................. 6
(2) Return on Equity.............................................................................................................. 7
II. ADJUSTMENTS TO TEST YEAR REVENUES, EXPENSES AND RATE BASE............ 13
A. Agreed Upon Adjustments.................................................................................................. 13
B. Disputed Adjustments ......................................................................................................... 14
(1) Revenues ........................................................................................................................ 14
(a) Change in Disconnect Policy...................................................................................... 14
(b) Uncollectibles.................................................................................................. ........... 16
(c) Other Revenue Adjustments....................................................................................... 17
(2) Operating Expenses........................................................................................................ 17
(a) Wage Increase ............................................................................................................ 17
(b) Incentive Compensation............................................................................................. 19
(c) Pension Expenses....................................................................................................... 19
(d) Supplemental Executive Retirement Plan (SERP) Costs.................. ........ ......... ........ 20
(e) MEHC Management Fees .......................................................................................... 21
(f) Outside Services Expense ...........................................................................................22
(g) Other Expense Adjustments..................................................... .................................. 23
(3) Irrigation Load Control Program....................................................................................24
(a) Expenses and Jurisdictional Treatment ...................................................................... 24
(4) Net Power Costs............................................................................................................. 27
(a) Wind Integration Costs............................................................................................... 27
(b) Cal ISO Wheeling and Service Fees........................ .............. .................................... 31
(c) Normalization of Call Option Contracts..................................................................... 32
1. SMUD...................................................................................................................... 32
2. Black Hills ............................................................................................................... 33
(d) Other Net Power Cost Adjustments ........ ................................................. .................. 34
C. Rate Base............................................................................................................................. 34
(1) Populus to Terminal .......................................................................................................35
(2) Mine Stripping Carring Costs .......................................... ............................................ 38
(3) Coal Pile Inventory.........................................................................................................39
(4) Other Rate Base Adjustments ........................................................................................ 40
Summar of Adjustments to Test Year Revenues, Expenses and Rate Base ........................... 40
Calculation of Revenue Deficiency.............................................................. ............................ 41
III. JURISDICTIONAL ALLOCATION, COST OF SERVICE, REVENUE SPREAD AND
RATE DESIGN ............................................................................................................................41
A. Jurisdictional Allocation - Revised Protocol......................................... .................... ........ 41
ORDER NO. 32196
B. Cost of Service ..................................................................................................................... 42
C. Revenue Spread...................................................................................................................43
D. Rate Design and Electric Rates ........................................................................................... 44
iv. ECONOMIC VALUATION OF MONSANTO'S INTERRUPTIBLE CREDIT................. 48
A. Non-Spinning Reserve Product........................................................................................... 56
B. Economic Curtailment Product ...........................................................................................57
C. System Integrity Product.....................................................................................................57
V. OTHER ISSUES ..................................................................................................................... 58
A. Energy Cost Adjustment Mechanism ................................................................................. 58
B. Prudency ofDSM Expenditures..........................................................................................58
C. Tax Issues ............................................................................................................................ 59
D. Low-income Weatherization Assistance (LIWA)............................................................... 60
E. Miscellaneous Consumer and Customer Service Issues..................................................... 62
(1) Disconnect Policy ........................................................................................................... 62
(2) Estimated Bills ............................................................................................................... 62
(3) Tenant Notice ................................................................................................................. 62
(4) Rebilling Policy .............................................................................................................. 62
(5) Moratorium and Winter Payment Plan........................................................................... 62
F. Miscellaneous Company Rebuttal Proposals............................................................ ........... 62
VI. INTERVENOR FUNDING ................................................................................................... 63
CONCLUSIONS OF LAW .......................................................................................................... 67
ORDER.....................................................................................................................................67
ATTACHMENTS A, B, C
ORDER NO. 32196 11
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF PACIFICORP DBA ROCKY MOUNTAIN ) CASE NO. PAC-E-I0-07
POWER FOR APPROVAL OF CHANGES TO )
ITS ELECTRIC SERVICE SCHEDULES ) ORDER NO. 32196
)
SUMMARY
On May 28,2010, PacifiCorp dba Rocky Mountain Power (RMP; Company) filed an
Application with the Idaho Public Utilities Commission (Commission) for authority to increase
its rates and charges for electric service in the State of Idaho. RMP serves more than 70,000
customers in southeastern Idaho. The Company provides electric service to more than 1,000,000
customers in Utah, Wyoming and Idaho. On December 27, 2010, the Commission issued
Interlocutory Order No. 32151 that contained our initial findings in this case and authorized
changes in the Company's electric rates. We have made numerous revenue requirement
decisions and adjustments to the amount allowed in rates. In making these adjustments we
address concerns raised by parties and customers and acknowledge the economic conditions and
service requirements in the Company's southeast Idaho service territory. In this final Order we
affirm the changes in electric rates set out in Order No. 32151 (with Errata), and provide our
detailed findings. We also establish a credit value for the interruptible (curtailment) products
that Monsanto Company provides to PacifiCorp.
Our prior Order authorized the Company to increase its Idaho electric base revenue
by $13,755,728, or 6.78%. There is no change. The electric rates we approve as just and
reasonable are the rates we established in Interlocutory Order No. 32151 (with Errata) and which
for ease of reference are set out in attached Attachment A. Idaho Code § 61-502. The net
amount of actual increase varies by class of customer and usage. With the rate design approved
by the Commission in this case, an electric residential Schedule 1 customer using an anual
average of 839 kWh per month wil realize a $15.00, or a 1.5% decrease in the customer's anual
electric bil.
ORDER NO. 32196 1
In this Order the Commission establishes a pro forma electric rate base of
$677,562,962. The Commission reaffirms a return on equity of 9.9% and an overall weighted
cost of capital and rate of return of 7.98% as approved in Interlocutory Order No. 32151.
APPLICATION
On May 28,2010, PacifiCorp dba Rocky Mountain Power (RMP; Company) filed an
Application with the Idaho Public Utilties Commission (Commission) for authority to change its
electric service schedules to reflect a proposed revenue increase of $27.698 milion, or 13.7%.
The Company's request was revised at the technical hearing to $24.870 milion, or 12.3%. Tr.
1171. The Company requests a retur on equity (ROE) of 10.6%. The proposed increase is
based upon normalized results of operations for the test period ending December 31, 2009, with
adjustments for known and measurable changes through December 31, 2010.
Rocky Mountain Power is a public utilty engaged in the generation, transmission
and distribution of electric power. The Company owns more than 10,000 megawatts of
generation from coal, hydro, natural gas-fueled combustion turbines and renewable wind and
geothermal power. Without the requested increase in revenues, RMP contends that it wil be
increasingly difficult for the Company to maintain its utility infrastructure and continue to
provide adequate, effcient, just and reasonable service to its Idaho customers. PacifiCorp
represents that it is in the midst of a multi-year program of investing in renewable energy,
transmission facilities and environmental controls to serve its customers in Idaho and across its
six-state system. At a total Company level, the test period includes over $4 bilion of new plant
investment and $87 milion in increased power costs.
The Company in its Application requested a Commission Order approving revised
electric rates and charges for a proposed effective date of June 28, 2010. The proposed effective
date was suspended pending hearing on the Application and further Order of the Commission.
Order No. 32001; Idaho Code § 61-622. The Company noted that pursuant to special contract,
rates under tariff Schedules 400 (Monsanto) and 401 (Nu-West) were to remain unchanged
through year-end 2010. i
i In Case No. PAC-E-06-09, Order No. 30197 (approving Monsanto's 2007 Service Agreement), the Commission
stated "we expect the parties to address interrptible product valuation in the context of a general rate case when
Monsanto's cost of service is determined." In Order No. 32098 (October 22, 20IO), we stated our prior direction in
Order No. 30 I 97 "was not a suggestion, it was a requirement." In failng to fie its interrptible product valuation
with its Application, we found that RMP had failed to comply with the Commission's Order. We established
additional scheduling for the separated issue of the economic valuation of Monsanto's interrptible products and
ORDER NO. 32196 2
APPEARANCES
A technical hearing in Case No. PAC-E-1O-07 was held in Boise, Idaho the week of
November 30, 2010. The following parties appeared by and through their respective counsel of
record:
PacifiCorp dba Rocky Mountain Power Paul J. Hickey, Esq.
Daniel Solander, Esq.
Monsanto Company Randall C. Budge, Esq.
Idaho Irrigation Pumpers Association, Inc. (IIPA)Eric L. Olsen, Esq.
Idaho Conservation League (ICL)Benjamin J. Otto, Esq.
PacifiCorp Idaho Industrial Customers (PIIC)Melinda J. Davison, Esq.
Ronald L. Wiliams, Esq.
Community Action Parnership Association
of Idaho (CAP AI)
Brad M. Purdy, Esq.
. Commission Staff Scott D. Woodbury, Esq.
D. Neil Price, Esq.
A continued technical hearing (Economic Valuation of Monsanto Interrptible Products) was
held in Boise on February 1, 201 1. The following parties appeared by and through their
respective counsel of record:
PacifiCorp dba Rocky Mountain Power Paul J. Hickey, Esq.
Daniel Solander, Esq.
Monsanto Company Randall C. Budge, Esq.
Idaho Irrigation Pumpers Association, Inc.Eric L. Olsen, Esq.
Commission Staff D. Neil Price, Esq.
directed the Company to "continue the existing interrptible credit (and terms of service) under the Monsanto
contract (2008 Service Agreement) until February 28, 2011."
ORDER NO. 32196 3
PUBLIC WORKSHOPS, HEARINGS AND COMMENTS
Prior to the technical hearings in this case, the Commission Staff in September 2010
conducted public workshops in Preston and St. Anthony, Idaho to discuss the Company's
Application and to answer customer questions.
Of those who attended hearings or otherwise paricipated in the public process,
nearly 100 people testified at the hearings in eastern Idaho and 4 people testified in the
Commission's telephonic hearing. Public testimony hearings were held in Shelley and Rexburg,
Idaho on December 14, 2010, and in Grace and Preston, Idaho on December 15, 2010. A
telephonic public hearing providing customers with an additional opportunity to offer sworn
testimony was held on December 20,2010.
The Commission also solicited public written comments regarding the Company's
Application. Written comments were filed by over 200 customers, area taxing authorities, school
districts, municipalities, chambers of commerce, small business owners, far bureaus, and Idaho
Legislators, all concerned about the impact of the rate increase proposed by the Company on the
region, communities, area businesses, constituents and familes.
As reflected in comments, area businesses, hospitals, schools and homes are
struggling financially. It is feared that significant increases in energy costs could cause large
employers such as Monsanto to close and that would have a ripple effect through the local
communities and economy. Customers of RMP state they have already been asked to tighten
their belts. They have been asked to conserve. Many responded by insulating their homes,
lowering their thermostats, reducing energy usage, switching to time-of-day rates and off peak
usage and installng more efficient light bulbs.
What follows is a small ilustrative sampling of comments fied:
. Utilty profits should be equal to the state's domestic growth rate.
. Expansion and investment in new plant and equipment need to be adjusted
with growth and the economy - we are not in normal times.
. During these economic times, a 10.6% return on equity (ROE) seems
absolutely unfair and unreasonable.
. A deviation from time tested and proven hydro and coal generation to
wind wil create a tremendous financial burden and promote reliabilty
risks for Idaho customers.
ORDER NO. 32196 4
. RMP needs to change its attitude and correct the waste in the Company.
Wages need to be curailed and bonus payments need to be curailed until
the economy has retured to normaL.
. RMP needs to cut back, spend less and make less just like the rest of the
people they serve.
. Costs are going up but our income is staying put. How do you expect us
to make it?
DISCUSSION
The Commission has reviewed and considered the fiings of record in Case No. PAC-
E-10-07 including the transcript of technical proceedings held November 30 through December
2, 2010. We have also considered the public testimony of customers in eastern Idaho and fied
public comments. On October 22,2010, the Commission in Order No. 32098 established further
scheduling in this case and tolled the suspension period which was set to expire December 28,
2010. In our Order, we stated our intent to issue an interim or interlocutory Order by December
28, 2010, establishing rates for all tariffs, save and except the interruptible credit portion of
Monsanto's Schedule 400. On December 27, 2010, we issued Interlocutory Order No. 32151
establishing new rates. It is those rates and findings that we revisit in this Order. A further
technical hearing on the economic valuation of Monsanto's interrptible products was held on
February 1,2011.
The Commission in this Order reaffirms the findings of Interlocutory Order No.
32151. We approve a 12-month test year ending December 31, 2009, adjusted for known and
measurable changes through year-end 2010. We approve an average capital structure for RMP
through December 31, 2010, consisting of 47.6% debt, 0.3% preferred stock, and 52.1%
common equity. We accept a cost of debt of 5.88%, and a preferred stock cost of 5.42%. We
approve a retur on common equity of 9.9% and an overall weighted cost of capital and rate of
retur of 7.98%. The interrptible product valuation credit we establish for Monsanto is ._.
ORDER NO. 32196 5
I. TEST YEAR, CAPITAL STRUCTURE AND RATE OF RETURN
A. TestYear
Rocky Mountain Power proposes use of a historic 2009 calendar test year with pro
forma adjustments for known and measurable changes through December 31,2010. Tr. pp. 82,
315. No pary opposes the proposed test year.
Commission Findings
The Commission finds use of a 12-month test year ending December 31, 2009
adjusted for known and measurable changes through December 31, 2010 to be reasonable and
appropriate. Annualization and normalization adjustments are made to the Company's historical
test year revenues and expenses for items that are not reflective of a typical 12-month activity,
while other adjustments are made for one-time or nonrecurring items. The matching of test year
adjustments wil be discussed later with other revenue, expense and rate base adjustments.
B. Capital Structure and Rate of Return
(1) Capital Structure, Cost of Debt (long-term), Cost of Preferred Stock
PacifiCorp's capital structure and cost of debt (long-term) and preferred stock was
determined using an average of the five quarters ending balances from the quarer ending
December 31, 2009 through the quarter ending December 31, 2010. Tr. p. 315. The Company's
proposed capital structure is comprised of the following components: long-term debt, 47.6%;
preferred stock, 0.3%; and common stock equity 52.1 %.
Commission Staff accepts the Company's proposed capital structure. Tr. pp. 2139,
2145. Staff updates the cost of long-term debt (5.88%) and preferred stock (5.42%) to reflect
curent information. Tr. pp. 2156, 2157, Exh. 132, Sch. 1, 2. The Company accepts Staffs
proposed cost of debt and preferred stock. Tr. p. 328.
Monsanto proposed reducing the Company's common equity component of capital
structure from 52.1 % to 49.7% by removing equity supporting short-term cash investments
(assets not devoted to utilty operations). Tr. pp. 855, 856, 866. The Company states these
assets are primarily attributable to PacifiCorp's decision to retain all earnings in the utilty and
build up its common equity balance and are not included in utilty plant in service or utility rate
base. Tr. p. 856. Monsanto accepts the Company's proposed cost oflong-term debt (5.92%) and
preferred stock (5.41%). Exh.202.
ORDER NO. 32196 6
RMP contends that Monsanto's recommendation to remove special deposits, short-
term investments, and the difference in affiiate notes receivable and payable from the
Company's actual common equity compqnent is unreasonable. Monsanto, the Company
contends, proposes the use of a hypothetical capital structure without a clear and compellng
justification for disregarding PacifiCorp's actual capital structure. Tr. p. 330. RMP disagrees
with Monsanto's analysis and conclusions.
As of September 30, 2010, RMP states the Company had exhausted its temporar
cash investments, effectively eliminating that aspect of Monsanto's adjustment. Additionally,
RMP notes that generally short-term investments are often netted against long-term debt to
determine what is known as "net debt." Net debt is used as a financial metric to reflect the
Company's net obligation to its bondholders. Nowhere in general finance, RMP contends, is
there support for Monsanto's novel proposal to net common equity with cash to derive net
common equity. Tr. pp. 330, 331. All of the Company's net cash from operations since
acquisition by MEHC, RMP contends, has been reinvested in the business. Furhermore,
Monsanto, RMP points out, used a different period of time to determine its proposed
hypothetical capital structure. Tr. p. 331.
Commission Findings
The Commission accepts the Company's proposed average capital structure through
December 31,2010, consisting of 47.6% debt, 0.3% preferred stock and 52.1% common equity
and Staffs proposed cost of debt (5.88%) and preferred stock (5.42%). We reject Monsanto's
adjustments to common equity. RMP rebuttal reflects the nature of these accounts showing that
these special deposits and short-term investments were exhausted. The funds have been utilized,
therefore no netting is required.
(2) Return on Equity
RMP
Cost of equity is the rate of return that equity investors expect given the risks of an
individual security and consistent with returs that are available from other similar investments.
The equity retur is not directly observable in advance and must be estimated or inferred from
capital market data and trading activity. Tr. pp. 366, 367, 371.
RMP estimates the cost of equity for the Company to be 10.6%. Tr. p. 402. The
Company's recommendation is supported by discounted cash flow and risk premium analyses
ORDER NO. 32196 7
and fuher review of other economic data. Its discounted cash flow (DCF) analysis generates a
resultant return on equity (ROE) range of 10.3% to 10.8%. Exh. 13. Its risk premium analysis
indicates a ROE range of 10.39% to 10.59%. Exh. 14. Given what he perceives to be continuing
market turbulence, the Company's witness, Samuel Hadaway, contends that RMP's
recommended ROE is conservative. Tr. pp. 364, 381, 382; Exh. 11, p. 2; 384, 391. Estimating
the cost of equity, he contends, is fudamentally a matter of informed judgment. Tr. p. 366. A
combination of DCF and basic equity risk premium methods, Mr. Hadaway contends, provides
the most reliable approach for estimating ROE. Tr. p. 374.
Other data considered by the Company in its ROE analysis and assessment of risk
includes the volatility in fundamental operating characteristics (Tr. p. 390), credit market
gyrations and the volatilty of utility shares (Tr. p. 391), the continued transition to more open
market conditions and competition (Tr. p. 392), climate change legislation (Tr. p. 392), risks
associated with coal-fired generation and greenhouse gas (GHG) emission reduction
requirements and permitting requirements for best available control technology for GHGs (Tr. p.
393), fuel price volatilty (Tr. p. 393), and ongoing capital requirements (Tr. p. 402).
'RMP proposed an 8.357% overall weighted cost of capital.
Monsanto
Monsanto estimates the cost of equity for the Company to be in a 9.1 - 9.9% range
with a point value of 9.5%. Monsanto's recommendation is supported by DCF, risk premium
and Capital Asset Pricing Model (CAPM) analyses. Tr. pp. 855, 869, 890. Monsanto's witness,
Gorman, has applied these models to a group of publicly traded utilities that he has determined
reflect investment risk similar to RMP. Tr. pp. 869, 870; Exh. 203. Monsanto's constant growth
Discounted Cash Flow (DCF) analysis generates a resultant ROE of 10.45% average and 10.5%
median that exceeds the growth rate of the overall U.S. economy or U.S. GDP and are
unsustainable. Tr. pp. 874-876. Its sustainable growth DCF analyses generates a resultant ROE
of 9.92% average and 9.14% median. A sustainable growth rate is based on the percentage of
the utilty's earnings that are retained and reinvested in utilty plant and equipment. Tr. pp. 876,
877. Its multi-stage growth DCF analysis generates a resultant ROE of 9.87% average and
9.90% median. The multi-stage growth DCF model reflects the possibility of non-constant
growth for a Company over time. Tr. p. 878. The results of Monsanto's DCF analyses produce
an average DCF return of9.85%. Tr. pp. 880.881.
ORDER NO. 32196 8
Monsanto's risk premium analysis produces a retur estimate in the range of8.98% to
9.94%, with a midpoint estimate of 9.46%. Tr. pp. 881-885. Monsanto's CAPM analysis
produces a return in the range of 8.28% to 9.31%, with a midpoint estimate of 8.80%. The
CAPM method of analysis is based upon the theory that the market required rate of return for a
security is equal to the risk-free rate, plus a risk premium associated with the specific security.
Tr. pp. 885-890.
RMP is an operating division of PacifiCorp, which is owned by MidAmerican Energy
Holdings Company (MEHC). PacifiCorp issues debt and equity on behalf ofRMP. PacifiCorp's
curent senior secured bond rating from S&P and Moody's are "A" and "A2," respectively.
PacifiCorp's corporate credit ratings from S&P and Moody's are "A-" and "Baal," respectively.
Monsanto believes a 9.5% ROE wil support internal cash flows that wil be adequate
to maintain RMP's current investment grade bond rating. Tr. p. 895. Based on its recommended
ROE and capital structure, Monsanto recommends an overall rate of return of 7.70%. Tr. p. 895.
Commission Staff
Staff estimates the cost of equity for the Company to be in a 9.5 to 10.5% range with
a point value of 10%. Tr. p. 2138. Staffs recommendation is supported by DCF and
comparable earings analyses. Tr. pp. 2145, 2150. Staffs DCF range is 8.8 - 9.3% (Tr. p.
2155), its comparable earnings range is 9 - 10.5%. Staffs recommended range and 10.0% ROE
point estimate is based on a review of market data and comparables; average risk for PacifiCorp
operating characteristics and the Company's capital structure. It also considers the reduced risk
of Paci fi Corp for the Energy Cost Adjustment Mechanism (ECAM) (rr. pp. 2152,2153) and the
increased risk for PacifiCorp itself for the recovery risk caused by the recommended change in
allocation of Irrigation Load Control Program costs. The adjustments proposed by Staff moving
plant in service to plant held for future use wil delay recovery and impact cash flows. Tr. pp.
2157,2158. PacifiCorp, Staff contends, continues to be in a better position than many utilties to
fund its near-term capital requirements with its current debt authority and equity levels. Tr. p.
2153.
Staff recommends an overall weighted cost of capital for the Company in the range of
7.769 - 8.29% with a point estimate of 8.03% to be applied to rate base for the test year. Tr. p.
2139.
ORDER NO. 32196 9
Commission Findings
All paries providing testimony on RMP's cost of equity accurately recount the
accepted standards to be applied. The standards for determining a fair cost of common equity for
a regulated utilty have been framed by two decisions of the U.S. Supreme Cour: Bluefield
Water Works & Improvement Co. v. Public Servo Commission of West Virginia, 262 U.S. 679
(1923) and Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 (1944). The
standards to be considered provide that the authorized retur should: (1) be sufficient to maintain
financial integrity; (2) be sufficient to attract capital under reasonable terms; and (3) be
commensurate with returns investors could earn by investing in other enterprises of comparable
risk.
In this case, the parties have advanced different methodologies to analyze and
ascertain a fair rate of return on common equity capital, including Discounted Cash Flow (DC F),
risk premium analysis, capital asset pricing model (CAPM) and the comparable earnings method.
Each method attempts to establish a rate of retur on common equity at a point sufficiently
attractive that free market investors wil consider purchasing common equity shares in the
company. As with other analytical tools used in the ratemaking process, the methods to evaluate
a common equity rate of return are imperfect predictors of future requirements and performance.
Additionally, the authorized rate of return on equity specified by a regulatory agency is but one
factor considered by prudent investors when evaluating a utility's stock. A utility's stock
performance in the marketplace is determined by many variables, including management
decisions, weather, streamflow conditions, and a host of separate economic factors.
This Commission has found it reasonable in the past to primarily rely on DCF and the
comparable earings method to determine an appropriate rate of return on common equity. We
have confidence in these approaches and primarily rely on them in this case. The DCF analysis
utilzes the dividend rate, stock price and expected growth rate of a company to quantify the
retur required by the investor. The comparable earnings method evaluates returns earned by
other companies, including utilties, to quantify an investor's expected return, taking into account
the risks associated with a particular investment. A third methodology to determine a required
rate of return on common equity is the risk premium analysis. The risk premium method stars
with the rate of retur for a low-risk investment, such as governent or utilty bonds, and adds a
premium based on the relative risk associated with a utilty's stock. A fourth method, the capital
ORDER NO. 32196 10
asset pricing model (CAPM) measures risks using the Beta coeffcient. The retur on equity is
measured in relation to the market as a whole. As markets change, new concerns develop in
various financial circles related to the calculations used to determine the cost of equity.
We find that RMP has, in this case, downplayed the poor economic conditions that
exist in its Idaho service terrtory where many are on fixed incomes, unemployed and under-
employed. This Commission canot discount as simply anecdotal the testimony and comments
of RMP customers. While we canot say "No" to a requested increase in rates because
customers are uniform in their opposition, together their testimony serves as the real-life context
and backdrop of our decision. Their testimonies and comments remind us that we are not
engaged in simply an academic exercise dealing in regulatory principles, generalities and
industr averages. Our decision has real consequences. RMP is not immune or shielded from
the state of the local economies in its service area. They are a factor in our decision as to what is
fair, just and reasonable. RMP is par of the economy, not separate from it. If the economy is
ailng, it is reflected in our decisions. We recognize that for some customers any increase may
result in economic hardship. That said, we have a dual obligation in rate cases. To customers
our task is to establish rates that are fair and reasonable. To the Company we have a statutory
obligation to set rates at a level suffcient to allow RMP the opportunity to recover its reasonable
expenses of operation and receive a reasonable retur on prudent capital investments in utilty
plant and facilities. Caring out this duty is necessary for the Company to be financially sound
and capable of providing its customers with safe and reliable electric service. Our decision-
making requires mindful consideration of our statutory obligations and a balancing of interests.
The Commission has considered all methodologies and rationale in the cost of capital
testimony of the witnesses and finds the middle ground position advanced by Staff witness
Carlock to be reasonable. The recent rates of return on equity for Idaho Power and A vista cited
by the Company are distinguishable. Idaho Power's 10.5% ROE was utilzed for Stipulation and
was not contested. Avista's 10.25% ROE resulted from and was par of settlement terms. The
evidence in this case supports a rate of return on common equity for PacifiCorp ranging from 9.5
- 10.5%. The higher end of this range encompasses the mid-range ofPacifiCorp's recommended
DCF range of 10.3 - 10.8%. This range also encompasses the middle range of approximating the
9.85% average DCF retur recommended by Monsanto. We find PacifiCorp's reasonable
required rate of retur on common equity to be 9.9%. In authorizing a 9.9% retur on common
ORDER NO. 32196 11
equity, this Commission reaffrms its desire to maintain PacifiCorp as a financially viable utilty
with credit ratings at or above the curent leveL.
The use of this cost of common equity together with the cost of long-term debt,
cost of preferred stock and capital structure previously found, yields the following overall
return for rate base:
Component
Debt
Preferred Stock
Common Equity
TOTAL
Percentage of
Capital Structure
47.6%
0.3%
52.1%
100.00%
Cost
5.88%
5.42%
9.9%
Weighted Cost
2.80
0.02
5.16
7.98%
Many of the adjustments accepted by the Commission, sumarized below, reduced
some of the revenue requirement in this case. However, the majority of Company expenditures
are reasonable and have been approved for recovery.
The capital structure authorized is strong. It reflects the business strength of
PacifiCorp and the overall regulatory support. This decision supports capitalization requirements
by rejecting proposals to reduce equity balances. In separate security filings, the Commission
has authorized PacifiCorp to maintain adequate equity and debt authority thereby allowing
PacifiCorp to access capital markets at reasonable costs.
The Populus to Terminal adjustment, we note, allows 73% of the investment in rates
curently and places 27% of plant investment that was adjusted in the plant held for future use
account. This is not a disallowance requiring a write off but a deferral until the project is used
and usefuL.
The coal stockpile adjustment is a reduction in the current case. However, it also
allows a three-year transition to increase the coal stockpile. The coal studies referenced by the
Company may provide analysis showing appropriate stockpile levels, with appropriate rationale
and documentation.
RMP has an energy cost adjustment mechanism (ECAM) approved in Idaho.
Decisions where the power costs were not sufficiently known or adequately documented, reduce
the power cost level in base rates. However, the actual costs will be included in the ECAM rate
changes. This is a deferral of cost recovery not a disallowance.
ORDER NO. 32196 12
Finally, contrar to the belief of many of RMP's customers, we recognize that the
Company does not have direct access to Berkshire Hathaway money. The cost of common
equity we establish above reflects a Company risk which, we find, is tempered by anual
adjustments that we have authorized and the Company's abilty and stated intention to request
rate increases more frequently.
II. ADJUSTMENTS TO TEST YEAR REVENUES,
EXPENSES AND RATE BASE
A. Agreed Upon Adjustments
Once a test year is selected, adjustments are made to test year accounts and rate base
to reflect known and measurable changes so that test year totals accurately reflect anticipated
amounts for the future period when rates wil be in effect. The Idaho Supreme Court has
described "rate base" as "the utility's capital investment amount." Industrial Customers of Idaho
Power v. Idaho PUC, 134 Idaho 285, 291, 1 P.3d 786, 792 (2000). Adjustments to test year
accounts generally fall into three categories: (1) normalizing adjustments made for unusual
occurrences, like one-time events or extreme weather conditions, so they do not unduly affect the
test year; (2) anualizing adjustments made for events that occurred at some point in the test year
to average their effect as if they had been in existence during the entire year; and (3) known and
measurable adjustments made to include events that occur outside the test year but wil continue
in the future to affect Company income and expenses.
RMP determined revenues and expenses for its 2009 test year in the same way it
established a test year rate base. The Company stared with 2009 actual figures and made known
and measurable adjustments to specific revenue and expense accounts it deemed appropriate for
regulatory purposes and made adjustments using extended forecast period through December 31,
2010.
Staff and other parties raised some objections to the Company's 2009 actual revenue
and expense items as well to the Company's proposed adjustments. All of the challenges and
recommended account adjustments affect the test year revenue requirement.
As reflected in RMP rebuttal Exhibit 79 (tab 11), the Company on rebuttal agreed to a
number of adjustments in net operating income and/or rate base proposed by intervenors and
Staff. RMP proposed an updated additional adjustment ($1.8 milion bonus depreciation
deduction) not included in its initial filing. The updated adjustment proposed by the Company
ORDER NO. 32196 13
incorporates a change in bonus depreciation law. The Small Business Jobs Act of 2010 (enacted
September 27, 2010) extended the 50% bonus depreciation allowance for qualifying assets for
one year (calendar year 2010). Tr. p. 1170. The revised revenue requirement in the Company's
rebuttal case reduced its original request of $27.698 milion (13.7%) in increased revenue by
$2.8 milion to a rebuttal requested revenue increase of $24.870 milion (12.3%). Tr. p. 1169.
The Company's revised request incorporates the following rebuttal adjustments:
Proposed Revenue Increase
$27,698,000
(Adjustment figures are in $1,000s)
Original Request
Rebuttal Adjustments
Cost of Debt and Preferred (Tr. p. 1171)
Bridger Unit 2 Overhaul Liquidated Damages
(Tr. p. 1172)
Medicare Subsidy (Tr. p. 1173)
Avian Settlement (Tr. pp. 1174-1176)
Generation Overhaul Expense (Tr. p. 1177)
Major Plant Additions - Plant in Service
(Tr. pp. 1179-1180)
Major Plant Additions - Tax Impact
Major Plant Additions - Depreciation Expense
Major Plant Additions - Depreciation Reserve
Net Power Costs (Tr. p. 1180)
S02 Sales (Tr. p. 1180)
Rebuttal Revenue Increase
(127)
(2)
(5)
(10)
(82)
(226)
(1.784)
(45)
7
(274)
(280)
$24,870,000
Exh. 79, Tab 11; Tr. p. 1171.
Commission Findings
We accept RMP's rebuttal adjustments as fair and reasonable and acknowledge that
the Company's requested revenue increase amount has been reduced to $24,870,000 or 12.3%.
B. Disputed Adjustments
(1) Revenues
(a) Change in Disconnect Policy
RMP has a policy of not physically disconnecting electric service when a customer
closes an account and discontinues service until metered usage exceeds a 1,000 kWh threshold
(previously 400 kWh). Tr. p. 2061. As a result, energy continues to be used even though there is
no customer to bil for that usage. Tr. pp. 2059, 2060.
ORDER NO. 32196 14
RMP, Commission Staff contends, maintains that most premises are only vacant for a
few days between customers. According to the Company, by not physically disconnecting
service after a customer discontinues service, the Company realizes a dollar savings in employee
time and vehicle mileage. Tr. p. 2060.
Based on its investigation, Staff contends that the presumed net benefit of RMP's
policy of not disconnecting service may be more myth than fact. Tr. p. 2060. In 2009, Staff
states there were 835 instances where usage exceeded 1,000 kWh, meaning at least 835,000 kWh
was unbiled. The majority of affected accounts were residentiaL. Tr. p. 2061. Staff estimates
that in excess of 1,000,000 kWh went unbiled in 2009 due to this policy. Based on the current
average residential rate, Staff calculates that more than $90,000 in revenue was foregone by the
Company in 2009. Tr. p. 2062. In promoting conservation and engaging in energy wasting
practices, Staff contends the Company is sending mixed signals. Staff recommends that the
Company change its policy.
RMP in rebuttal disagrees with Staffs contention that the net benefit of the
Company's current policy may be "more myth than fact." The Company believes its current
policy is cost-effective. Tr. p. 1051. Of 7,837 accounts closed in 2009, the Company states
there were only 835 instances where field orders to disconnect service were generated for
unbiled usage of 1,000 kWh or greater. Of these 835 instances, the Company states that
approximately 42% of the orders resulted in a customer taking responsibility for the unbiled
usage after receiving a notice of disconnection or having the service disconnected. The usage for
2009 lost as a result of the remaining sites where unbiled usage was not recovered, the Company
states, was 798,319 kWh. Based on an average of 8ø/kWh, the unbiled revenues would be
approximately $63,866. Tr. p. 2052. Based on current activity rates of the personnel needed to
disconnect electric service, the Company estimates the approximate cost for completing the
7,837 requests would be $178,183. Then, when a new customer requests service at the site, the
Company would again need to dispatch personnel to connect the service. This would increase
the costs to $356,366. By comparison, the total cost for the curent process is approximately
$180,621. Tr. p. 1503. The Company states that it would seek to recover any additional costs
occasioned by following Staffs recommendation through customer rates and/or fees. Tr. p.
1056.
ORDER NO. 32196 15
Advancing non-economic reasons for maintaining the curent policy, the Company
states a change in disconnect policy would present an increase in the safety risks inherent every
time a field metering specialist disconnects or connects a meter. Also it would require additional
manpower, could cause customer dissatisfaction, and could increase the number of customer
guarantee failures. Tr. p. 1056.
RMP does not believe the Company is sending mixed signals to customers when it
encourages conservation but leaves service connected when there is no customer. The economic
costs of disconnecting the power at all premises, the Company believes, outweigh the benefits
realized by a change in policy. Tr. p. 1057.
Commission Findings
The Commission is persuaded that Staffs position is correct. We are concerned that
the Company makes part of its economic argument on the fact that in 43% of 835 instances
where field orders were generated for unbiled usage of 1,000 kWh or greater, ". . . customers
(took) responsibilty for the unbiled usage after receiving a notice of disconnection or having
services disconnected." This appears to constitute a threat to a connecting or reconnecting
customer to pay the unbiled usage, or else. Until this issue can be resolved, we accept Staffs
recommendation. The impact of our decision is a revenue requirement adjustment of $90, 161.
(b) Uncollectibles
RMP has included in its fiing the actual 2009 test year level of uncollectibles
adjusted for known and measurable events ($472,263). Tr. pp. 1200, 1675. PIIC contends that
the 2009 test year amount is the highest in three years and recommends using a historical four-
year average of uncollectibles expense. Tr. p. 1639. The following is a table depicting the
Company's level of uncollectible expense and recorded revenues from 2006 through 2009.
Uncollectible Expense by Year
Amount
$529,196
308,510
303,856
472,263
Year
2006
2007
2008
2009
Revenues
$140,250,947
182,699,838
197,505,456
184,995,386
RMP in rebuttal contends that this recommendation is another example of an
adjustment that isolates a single expense account to produce a reduction to revenue requirement.
The Company contends that the proposed adjustment is uneasonable and inappropriate. PIIC's
ORDER NO. 32196 16
method, the Company contends, fails to account for conditions during the rate effective period.
The Company states it has experienced a steady increase in uncollectible expense since 2008.
Tr. pp. 1200, 1201.
The proposed averaging method, RMP states, produces a 2010 uncollectible expense
level that is below the actual expense for the first 10 months of 2010 ($652,554). Adopting
PIIC's adjustment, RMP contends, would result in under-recovery of the Company's
uncollectible expense. Tr. p. 1201.
Commission Findings
The Commission has considered the arguments presented and finds use of an average
of uncollectible expense to be preferable to use of a single test year amount. PIIC recommends
four years. To be consistent with our practice elsewhere in this Order, we find it reasonable to
require use of a three-year average (2007-2009) for uncollectible expense. A three-year average
results in a reduction of $110,720 (Idaho) from the uncollectible level included in the Company's
case.
(c) Other Revenue Adjustments
The other revenue adjustments proposed by paries are either agreed to or the
Commission accepts the Company's position. Therefore, we address them together. The
Commission accepts use of a five-year average to reflect S02 emission credit sales revenue. The
Commission accepts the Company's rebuttal position related to normalization considerations
related to residential and irrigation usage. We also accept that the One Utah Center rental
agreement is properly reflected below the line. All of these issues are reflected in the
Company's rebuttal numbers, making no further adjustments necessary.
Renewable Energy Credit (REC) revenues will be included as a revenue credit in the
Company's ECAM filings. The base level of REC revenue wil be $91,779,696 on a total
system basis, $7,031,166 Idaho.
(2) Operating Expenses
(a) Wage Increase
In RMP's fiing, actual December 31, 2009 labor related expenses are annualized to
reflect any increases that occurred in 2009 as being included for a full 12 months. The
annualized 2009 labor expenses were then escalated at either the contractual increase for union
employees or the actual increase for non-union employees to reflect a 2010 pro forma budgeted
ORDER NO. 32196 17
amount. In 2009, non-union employees received a 3.5% wage increase, while the union
employees received between 1.25% and 3%. In 2010, the non-union employees received an
increase of 0.88% while the union employees received between 1.5% and 2.5%.
Commission Staff proposes that all wage increases awarded by the Company to its
employees during 2009 and 2010 be disallowed in rates, or an employee wage adjustment of
($14,375.075). This adjustment by Staff sets the level of straight-time labor at the January 1,
2009 leveL. Tr. p. 2008, Exh. 104. As justification for its adjustment, Staff cites economic
conditions in the Company's Idaho service territory. Exh. 115, 116. Unemployment rates have
increased. Wages and the consumer price index have remained relatively flat. Those on Social
Security received no cost of living adjustments for 2010 and 2011. Many Idaho state employees
were forced to take furloughs. While much of the population struggles, Staff argues that it is not
prudent for utility companies to continue to grant increases to its employees. Staff believes also
that the Company could have done a better job these last two years in controllng costs. Tr. p.
2009.
RMP in rebuttl states that the wage increase levels for its union population are set as
part of a collective bargaining process typically covering multiple years and are part of many
considerations such as work rules, benefits, and retirement. Together the variables deliver a
competitive set of benefits and compensation. The wage levels are part of contracts, the
Company argues, that were prudently entered into by management and are known and
measurable in the test period and should be provided full cost recovery. Tr. p. 840.
RMP states that the 2009-2010 wage increase levels for its non-union employees are
set by reviewing market data for labor wage adjustments and positioned at the market average.
For 2009, the Company contends, an increase level of 3.5% was market competitive. Tr. p. 841,
Exh. 70. For 2010, the Company states it factored in the economic crisis and conditions facing
its customers and implemented a 2010 wage increase slightly below-market practices, awarding
increases only to those employees who received a base compensation below $100,000. Tr. p.
841.
Commission Findings
The Commission finds that in challenging economic times the local economy in the
Company's service area is a greater indicator as to the appropriateness of a wage increase than
market data and industry averages. We find no demonstration by the Company that the union
ORDER NO. 32196 18
and non-union wage increases were required for the Company to be a competitive employer able
to retain orattract employees. We find no evidence that without the union and non-union wage
increase the service provided by the Company would be degraded and safety compromised. We
find that as a certificated provider of service RMP has elected to be a member of the
communities it serves. We find Staffs proposed wage adjustment to be reasonable. The
Company may choose to implement its wage increases, but we wil not allow recovery of that
expense from its Idaho customers.
(b) Incentive Compensation
As part of our review of employee compensation we evaluated wage increases,
incentive compensation and pension expense. We believe incentive compensation can be an
important component of base pay. With our wage adjustments, we accept RMP's position that
these incentives are an at-risk piece of base pay. We caution RMP to only reflect incentives tied
to operational efficiency, customer service and safety for inclusion in base rates. The at-risk
incentives must benefit customers. We find our adjustment to wages to be reasonable making
fuher adjustment to the at-risk incentives unecessary.
(c) Pension Expenses
RMP in its fiing requests recovery of its 2010 actual cash contributions to its pension
plan, $104.8 milion for 2010 on a total system basis. Commission Staff stated that, as of the
date it prepared testimony, the Company's 2010 actuarial valuation had not been completed. The
Company provided no detailed calculations from its actuaries ilustrating how the $104.8 milion
contribution was calculated. The estimated future contributions calculated by the Company's
actuaries, Staff represents, indicate a significant decrease in pension funding in future years, and
approximately twice as much in 2011 as in 2010. Staff recommends using a five-year projected
average of pension contributions (2010-2014) rather than just 2010 resulting in a total Company
adjustment of ($20,875,647). Tr. pp. 2003, 2004; Exh. 104 and 105; Conf. Exh. 106.
RMP in rebuttal rejects Staffs proposed adjustment and recommends continuing on a
cash basis. Exh. 2, p. 4, 13. If the Commission finds use of an average reasonable, the Company
recommends a three-year historical average (2008-2010) resulting in an adjustment of ($19.11
milion (total Company)). Tr. pp. 1191, 1192,336,337.
Actual cash contributions to fund the pension plan in 2010 was $112.8 millon. Tr. p.
335. The Company made an additional $8 milion contribution during 2010 in order to help
ORDER NO. 32196 19
improve the fuded status of the pension plan. The resulting funded ratio with a 2010
contribution of $104.8 milion would have been 79.45%. Plans with funded ratios below 80%
are subject to restrictions and place the plan in "at risk" status as of January 1, 2011, causing a
significant increase in the 2011 minimum funding requirement. Tr. p. 335.
If the Commission adopts Staffs forward-looking five-year average proposal, the
Company contends it would assure under recovery of 60-80% of the 2010 contributions
depending on the timing of the Company's next rate case. Tr. p. 338.
Commission Findings
The Commission wil accept as reasonable in this case the three-year historical
average of actual pension contributions (2008-2010) identified by RMP in its rebuttal case. We
find that the averaging method has merit; that regulation favors a consistent approach; and that
regulation should afford a utility a reasonable opportunity to recover its prudently incurred costs.
(d) Supplemental Executive Retirement Plan (SERP) Costs
RMP contends that the Company's Supplemental Executive Retirement Plan (SERP)
expense is related to a market competitive benefit offering. The Company's primary objective in
establishing employee compensation, it states, is to provide pay at the market average.
Compensation at the market average (competitive level), the Company contends, is critical to
attracting and retaining qualified employees to support the business and its customers. Tr. p.
825.
Commission Staff recommends that SERP costs in this case ($2.6 milion total
system) be disallowed as these benefits, Staff contends, are above and beyond those covered in
more conventional retirement plans and are intended to ensure the Company's executives can
maintain the same standard of living in retirement. Ratepayers, Staff contends, should not bear
costs beyond the retirement benefits available to rank and fie employees. Tr. pp. 2005, 2006.
RMP disagrees with Staffs assessment and proposed adjustment. These are not
extra, unecessary or excessive benefits, the Company contends. RMP provides programs/plans,
it states, at the market average (no better and no worse). The Company states it no longer offers
the SERP benefit to new paricipants. The expenses sought in this case are related to one active
paricipant (the President of RMP) and past participants who, during their employment, the
Company contends, delivered value to then current customers, while also shaping the Company
ORDER NO. 32196 20
to benefit future (current) customers. The Company honors its commitment to continue to fud
SERP expenses. Tr. p. 842.
Commission Findings
The Commission finds Staffs argument persuasive and finds it reasonable to disallow
Company recovery of SERP costs of $2.6 milion (total Company) in this case. The Company
has not demonstrated that the costs are related to providing services to southeast Idaho. The
responsibility for generous severance benefits for executives, we find, is the responsibility of the
Company and its shareholders, not Idaho customers.
(e) MEHC Management Fees
RMP pays an annual "Management Fee" to MidAmerican Energy Holding Company
(MEHC) under an "Inter Company Administrative Services Agreement."
Pursuant to MEHC acquisition Commitment I28,
MEHC and PacifiCorp will hold customers harless for increase in costs
retained by PacifiCorp that were previously assigned to affiliates related to
management fees. . . this commitment is off settable to the extent PacifiCorp
demonstrates to the Commission's satisfaction, in the context of a general rate
case the following:
1. corporate allocations from MEHC to PacifiCorp included in PacifiCorp's
rates are less than $7.3 milion.
Tr.p.1155.
Staff proposes to reduce MEHC management fees allocated to PacifiCorp. Staff
acknowledges that the Company limited the amount of allocations from MEHC to PacifiCorp to
$7.3 milion. However, Staff contends that included in the $7.3 milion allocation from MEHC
is $2.15 millon in Supplemental Executive Retirement Plan (SERP) contributions and bonuses
to employees of MidAmerican. Staffs adjustment, it states, is a logical continuation of
adjustments recommended for RMP employees. Tr. pp. 2009, 2010. Staffs related adjustment
is ($1,100,635) on a total Company basis. Exh.107.
PIIC recommends that $2.1 milion (incentive compensation and legislative costs and
contributions) on a total Company basis be disallowed, an adjustment of ($111,601) Idaho. Tr.
p. 1667. PIIC contends that the MEHC acquisition commitment cap is the upper limit for these
charges, and disallowances should be further reductions below the cap. PIIC contends that since
its proposal to remove $2.1 milion is greater than the $1.1 milion reduction the Company made
ORDER NO. 32196 21
to arive at the capped level further adjustment is warranted. Tr. p. 1668. PIIC contends that
bonuses paid to MEHC and MEC executives are tied to performance of PacifiCorp's parent
company and are not closely aligned to customer-related performance at the utility leveL. Tr. p.
1669. PIIC believes costs associated with lobbying or influencing legislation should be
prohibited from recovery through rates. Tr. p. 1669.
RMP in rebuttal maintains that the SERP and incentive compensation that Staff and
PIIC seek to remove are individual components of total compensation packages similar to those
provided to PacifiCorp employees and are appropriately included in regulated results. Tr. p.
1193. RMP agrees that costs strictly related to the Company's legislative activity should not be
included in regulated results, but contrary to PIIC's assertion, RMP states, the Company has
capped the level of MEHC management fee expenses in this case and excluded the $330,636 in
legislative costs from results. Exh. 2, p. 4.8. PIIC, the Company contends, is removing costs
that are not included in the case. Tr. pp. 1193-1195.
RMP admits that the Company's downward adjustment reduced the expenses booked
above-the-line from $8.4 milion to $7.3 milion, but states PIIC fails to consider that a portion of
the $11.6 milion management fee biled to PacifiCorp in 2009 was not booked above-the-line to
begin with. Tr. pp. 1194, 1195.
Commission Findings
The Commission finds that RMP has appropriately excluded the legislative costs
biled to PacifiCorp by MEHC from the MEHC management fees it seeks to recover. We find
Staff s adjustment removing SERP and bonuses to employees of MidAmerican to be reasonable.
We find that the Company has failed to demonstrate that these fees are related to the Company's
Idaho service obligation and that Idaho customers should be required to pay this expense.
(f) Outside Services Expense
RMP in this case requests inclusion in its base rates the test year level of outside
services expense. PIIC contends that the 2009 expense level ($1,209,260) is too high and
recommends that outside services expense be based on a four-year average of expenses from
2006-2009. Tr. p. 1639. The effect of this adjustment reduces revenue requirement by $327,080
(Idaho). Tr. p. 1640.
ORDER NO. 32196 22
Outside services expense includes expenses for outside services such as legal and
engineering. The following table reflects the levels of outside services expense assigned to
RMP's Idaho operations.
Outside Services Expense by YearYear Amount2006 $1,067,8142007 580,9872008 670,6612009 1,209,260Four-year Average 882,181
Tr. p. 1670. A four-year average of outside services expense would reduce RMP's Idaho cost of
service by $327,080. Tr. p. 1671.
RMP in rebuttal contends that the level of expense or revenue change over time is, by
itself, no reason to use an average. PIIC, the Company states, does not take issue with the
prudence of any of the specific costs contained within the base period outside services expense.
The Company contends that the level of outside services expense in the base period is reasonable
and that fluctuations from year-to-year are normaL. Tr. p. 1197. Accepting PIIC's adjustment,
RMP contends, would be unfair and would not provide the Company a reasonable opportunity to
recover its costs of providing service to customers. Tr. p. 1199.
Commission Findings
The Commission finds that the Company's outside services expense varies
significantly from year-to-year. With this type of varation the Commission often utilzes
averages. We find the Company's argument against using an average to be unpersuasive. PIIC
recommends using a four-year average. We find use of a three-year average of outside services
expense to be reasonable and consistent with the approach this Commission follows in this and
other rate cases. The three-year average results in a reduction of $388,957 (Idaho) to the level of
outside services included by the Company in this case.
(g) Other Expense Adjustments
The remaining expense adjustments (excluding power supply costs) proposed by the
paries are either agreed to or the Commission accepts the Company's position. The Medicare
subsidy and a portion of the Avian settlement were agreed to by the Company. We accept the
Company's position to use a three-year average for injuries and damages. We also accept the
ORDER NO. 32196 23
Company number for the expense portion of the Avian settlement, property tax expense and the
incremental 2010 O&M expenses for Company-owned wind projects.
(3) Irrigation Load Control Program
(a) Expenses and Jursdictional Treatment
The Idaho Irrigation Load Control Program is offered to Idaho irrigation customers
receiving retail electric service under Schedule 10. Participants agree to allow the Company to
curtail their electricity usage, and in exchange paricipants receive credits valued on a per
kilowatt basis. The Idaho Irrigation Load Control Program is provided under Schedules 72 and
72A. Schedule 72 is a prescheduled service interrption, whereas Schedule 72A is a
dispatchable service interruption. Tr. pp. 1940, 1941.
Commission Staff contends that RMP's Idaho Irrigation Load Control Program has
evolved since inception to a point that it now provides PacifiCorp a valuable system resource.
Dispatchable service interrption, under Schedule 72A contracts, allows PacifiCorp to reduce
loads during peak periods and during outages at generation plants. These contracts provide
system flexibilty. The interrptions are large enough (over 200 MW load reduction capabilty)
and are reliable enough to allow PacifiCorp to utilze these interrptions as a resource for
planning purposes in the Company's Integrated Resource Plan (IRP). The Idaho Irrigation Load
Control Program contracts are more like power purchase agreements or ancilary service
contracts, Staff contends, and should be classified as such and treated the same for allocation
purposes. Tr. pp. 2139, 2140.
The current designation, Staff contends, is appropriate for IRP and DSM assessment
puroses but is not appropriate for allocation purposes in a state where the state loads are a small
percentage of the system operations. The program's success, Staff contends, has outgrown the
benefits that can be attributed to Idaho alone. The system operations rather than the state loads
are the driver to evaluate cost-effectiveness. Tr. p. 2141. Between 2007 and 2009 with
increased participation, the annual megawatts available for interruption increased from 78 MW
to 276 MW (a 250% increase). Tr. p. 2144.
As reported by Staff, the PacifiCorp system receives a benefit of approximately $20
milion (2009 DSM Report) due to avoidance or delay of generation. The total program costs,
including irrigation payments for interrption, are $11.4 milion. Tr. p. 2141. As calculated by
Staff, a simple costienefit analysis shows how the costs do not follow the system benefits,
ORDER NO. 32196 24
creating a mismatch to the detriment of Idaho customers. This mismatch, Staff contends, needs
to be corrected. Tr. p. 2141. Staff recommends that Irrigation Load Control Program costs be
assigned as a power supply cost. Staff believes that its proposal is not a violation of the
jurisdiction Revised Protocol allocation methodology and advises the Commission that the
Multi-State Process Standing Committee is addressing this issue. Reference Revised Protocol,
Case No. PAC-E-02-3, Order No. 29708 adopted February 28, 2005. Staff also notes the curent
in-house Company filing for Revised Protocol amendments, Case No. PAC-E-10-09. Staff in
this case accepts the Company's Revised Protocol allocation methodology with the exception of
the proposed treatment of Idaho Irrigation Load Control Program costs. Tr. p. 1933. Staff
recommends that costs associated with the Idaho Irrigation Load Control Program be treated as
system power supply expenses instead of being directly assigned to the Idaho jurisdiction. Tr. p.
1934.
RMP proposes to assign all $11.4 milion in program costs situs to customers in the
Idaho jurisdiction. The Company then credits or decrements the Idaho jurisdictional demand
allocator used in the allocation of system costs to Idaho. The reduced jurisdictional allocation
factor, reflecting the demand reducing effect of the Idaho Irrigation Load Control Program,
benefits Idaho customers by reducing the Idaho jurisdictional revenue requirement by
approximately $7.48 milion. Tr. pp. 1942, 1943. The net effect is that directly assigned Idaho
program costs of $11.4 milion exceed allocated Idaho revenue requirement benefits of $7.48
milion by approximately $3.9 milion a year. Tr. pp. 1943, 1944. Staff contends that the
proposed allocation method is uneasonable. Staff proposes that the Company treat the program
costs as a system purchase power cost and allocate them just as it would any other system power
supply expense. This, Staff contends, wil assure that the costs allocated to each jurisdiction
follow the benefits received by each jurisdiction. Tr. p. 1945.
The revenue requirement effect of treating Idaho Irrigation Load Control Program
costs as a system power supply expense in jurisdictional cost allocation would be a reduction in
Idaho's net revenue requirement of approximately $3.25 milion when Idaho Irrigation Load
Control Program costs previously collected through the tariff rider are included. Under the
Staff s proposal the reduction in revenue requirement collected from Idaho would be collected
from PacifiCorp's other jurisdictions through the dynamic system cost allocation of additional
system power supply expenses.
ORDER NO. 32196 25
RMP in rebuttal agrees with the rationale behind Staffs recommendation but, the
Company states it is placed in a difficult position by Staffs proposal. A reallocation of costs
would shift program costs away from Idaho to other states before the issue has been addressed
and resolved by the Multi-State Process (MSP) Standing Committee or factored into cost
recovery filings in its other jurisdictional states. As a result, RMP believes that 2011 should be
treated as a transitional year to afford the Company and Staff the opportunity to work together to
address the treatment of Class 1 DSM resources with the MSP Standing Committee.
Additionally, the Company believes that certain changes need to be made to the Irrigation Load
Control Program to increase its cost-effectiveness and resolve operational issues that have been
identified during the last two years as the program rapidly expanded. Tr. p. 595.
RMP proposes that the Irrigation Load Control Program continue to be treated as
situs assigned costs during 2011 to allow the issue to be addressed with other states through the
MSP process. Tr. p. 595.
Commission Findings
The Commission finds that there is inequity in continuing with the current
jurisdictional treatment of the Irrigation Load Control Program expenses. Cost recovery from
other jurisdictions represent a timing issue for the Company. The Company proposes that 2011
be a transition year. We find that it is unreasonable to expect Idaho customers to continue to
bear the costs associated with the current jurisdictional treatment of the Irrigation Load Control
Program. We accordingly find it reasonable to adopt Staffs proposed adjustment and change in
the Idaho treatment of Irrigation Load Control Program expenses. Our immediate change
provides impetus for RMP to act quickly in addressing the change in its other jurisdictional
states. We fuher find our actions to be in accordance with the Commission's authority retained
in our approval of the Revised Protocol. These program expenses wil no longer be flowed
through the Company's tariff rider. Instead, Idaho's share of program costs wil be shifted to
base rates. We further decline to make Company-proposed modification to the Idaho Irrigation
Load Control Program as part of this case. Our decision treating the program costs of the
Irrigation Load Control Program as a system cost allows a reduction to the Customer Efficiency
Services Tariff Rider from 4.72% to 3.4%.
ORDER NO. 32196 26
(4) Net Power Costs
The system base net power cost (NPC) number we establish in this case is derived by
making three adjustments to the Company's rebuttal NPC number:
RMP Net Power Costs as Filed (Rebuttal)
Less: Commission Adjustments
Wind Integration Costs
Cal iso Wheeling & Service Fees
Normalization of Call Option Contracts
Total Adjustments
Net Power Costs per Commission Order
System Costs
1,063,230,027*
(34,187,931)
(4,041,991)
(1,293,489)
(39,523,411)
1,023,706,616
*Exh. 71; Exh. 79, Tab 11.9.1; 11.9.4
(a) Wind Integration Costs
RMP in this fiing uses $6.50 per megawatt-hour (MWh) to calculate the costs of
integrating intermittent wind generation into the Company's system, the same wind integration
charge approved by the Commission in Case No. PAC-E-09-07 for setting published avoided
cost rates in Idaho for mandatory purchases pursuant to the Public Utilty Regulatory Policies
Act of 1978 (PURPA). Tr. pp. 926, 934, 935. The Company's net power cost calculation
includes approximately $34.2 milion of wind integration costs, exclusive of wind integration
costs paid to the Bonnevile Power Administration (BPA).
Commission Staff recommends disallowance of wind integration costs in test year
operational costs. Staff excepts from its recommendation wind integration costs paid by the
Company to BPA (approximately $5.89 per MWh). Tr. p. 948. Staffs adjustment reduces net
power supply expense by approximately $34.2 milion (system). Tr. p. 281.
Staff contends that the Company should not be allowed to include the PURP A wind
integration charge ($6.50 per MWh) as a variable cost to its own wind facilities and power
purchase contracts. These are internal costs, Staff states that are neither paid under contract nor
to any other utilty. For wind resources in service during the 2009 test year, Staff contends that
wind integration costs are captured in actual test year expenses. Tr. p. 280. There is no basis to
explicitly add wind integration costs into the rate case, Staff argues, because estimates are neither
accurate nor predictable. Furthermore, Staff notes that RMP has an energy cost adjustment
mechanism (ECAM) in Idaho. According to the Company, the ECAM was designed to capture
the volatility in net power costs due to, among other things, wind variabilty (citing Company
ORDER NO. 32196 27
witness Duval's testimony in PAC-E-08-08). The actual costs of wind variability, both on the
Company's system and to the extent it provides sales opportunities outside the system, Staff
contends, wil be captured in the ECAM. Tr. p. 281.
Monsanto recommends that the Commission reject recovery of wind integration costs
using the $6.50 per MWh rate and recomÌnends that wind integration costs be recovered through
the Company's ECAM. Tr. p. 1521. Monsanto contends that the rate is not cost-based and the
Company has not met its burden of proof regarding recovery of wind integration costs. Tr. p.
1553. This adjustment, Monsanto calculates, reduces NPC by $1.88 millon (Idaho). Tr. p.
1521.
Monsanto contends furher that RMP should not be allowed to recover wholesale
wheeling customer wind integration costs from retail customers through the ECAM. The
Company has included wholesale wheeling customer wind integration costs in the NPC,
Monsanto contends, because PacifiCorp failed to request an adjustment to its Open Access
Transmission Tarff (OATT) so that these costs can be recovered from wholesale wheeling
customers. These costs, Monsanto contends, are not the responsibilty of Idaho customers and
should be removed from NPC. This adjustment reduces NPC by $0.35 milion (Idaho). Tr. pp.
1521, 1522.
Monsanto contends also that RMP double counted wind integration balancing costs
during the period of January 2010 through April 2010. By its proposed adjustment, Monsanto
removes the double count reducing NPC by $0.14 milion (Idaho). Tr. pp. 1522, 1558.
Monsanto disagrees with RMP's claims that one need only look at BPA's wind
integration costs to determine that the Company's costs are reasonable. The Company itself in
its August 31, 2009 wind integration study, Monsanto states, cautioned against comparing
PacifiCorp's costs with other utilty studies because
there is 1) no industry standard design, different cost components are
incorporated into the studies and different modeling approaches and tools are
applied, 2) costing methodologies and understanding of wind impacts is
evolving rapidly as utilties gain operating experience, 3) utility system
differences, 4) study assumptions (e.g., transmission sufficiency, wind
location diversity, regional coordination, wind forecast improvement
expectations), and 5) conservative vs. optimistic bias.
Tr. p. 1555. PacifiCorp, Monsanto states, has admitted on numerous occasions that it canot
calculate the actual cost of wind integration and has also stated that they have not estimated
ORDER NO. 32196 28
actual costs, which could be used for verification of the reasonableness of wind integration cost
forecasts. Tr. pp. 1555, 1556.
PIIC proposes to remove the inter-hour wind integration costs associated with
integrating non-owned wind projects that are interconnected to the Company's transmission
system because the Company does not have a transmission tariff to recover the costs from those
customers. Tr. pp. 1717, 1733. This adjustment, PUC calculates, would decrease the
Company's NPC by approximately $4.3 milion (system).
RMP in rebuttal maintains that wind integration costs are real, necessary and prudent.
Tr. p. 948. The Company agrees to remove inter-hour wind integration costs associated with the
wind projects that are located in the Company's balancing areas but do not deliver generation to
the Company's system. The corrected adjustment, RMP states, includes an accounting for
generation from the Stateline wind project recovered under a contract with Salt Lake City and
results in a decrease to system NPC of approximately ($1.4 milion). Tr. pp. 940, 950.
Wind integration costs, the Company argues, are not the same as the variation in NPC
that the ECAM is designed to capture. Wind integration costs, it contends, are costs incurred due
to additional reserve requirements to integrate the intermittent generation from the wind projects
into the Company's portfolio of resources (regulation up, regulation down, load following up and
load following down). Tr. p. 947.
The Company contends that it operates its resource portfolio to serve all its
obligations, and does not differentiate what resources are used for serving which obligations. As
such, the Company states it can only estimate the impact of wind integration costs. Tr. p. 949.
The Company notes that it has completed a wind integration study in conjunction with its 2010
Integrated Resource Plan and is presently reviewing comments. Tr. p. 951.
RMP states that it canot charge wholesale transmission customers for wind
integration costs without first obtaining FERC approval. The Company is required by federal
law to interconnect with new facilities under the terms of its Open Access Transmission Tariff.
Once RMP interconnects a new facility to its transmission system, the Company is responsible
for integrating it into the system. PacifiCorp states its intention to fie a rate case with FERC no
later than June 1, 2011, in which the Company wil include a proposed wind integration charge
in its transmission tariff rates. Tr. p. 951.
ORDER NO. 32196 29
As a balancing area authority, RMP states the Company must operate its balancing
areas by matching system resources to actual load and generation fluctuations on a moment-to-
moment basis through automatic generation control. Load fluctuations, outages, and generation
output fluctuations all contribute to the need for balancing resources. The addition of renewable
resources such as wind, the Company contends, has the tendency to increase the need for
balancing resources. The costs associated with wind integration, it contends, are a prudent
expense. Tr. p. 952.
By providing wind integration services II addition to other transmission-related
services as a balancing area authority, the Company states it ensures that its customers are served
by a reliable system with diverse resources. Tr. p. 952.
With the exception of inter-hour wind integration costs, RMP recommends that the
Commission reject the wind integration cost adjustments proposed by Staff, PIIC, and Monsanto.
Commission Findings
No pary to this case denies that wind integration costs are real costs; the consensus,
however is that they cannot be readily forecast with accuracy, calculated or verified. The record
reflects that even PacifiCorp may not have confidence in its own study. The Company, we find,
has not presented the Commission with a verifiable study depicting its wind integration costs.
We wil not allow the Company in this case to use the wind integration cost developed for
mandatory PURP A purchases as a surrogate. They are not the specific integration costs of RMP
and are not adequately supported by a study. We find it reasonable in this case to deny the
inclusion of wind integration costs in the Company's NPC. We exclude from our denial the
contractual wind integration costs paid by the Company to BP A. We are not happy with this end
result, because we believe these integration costs belong in base rates. We encourage the
Company to work with Staff and other interested paries toward a resolution. As par of a new
proposal the Company should be prepared to demonstrate how acceptance of its wind integration
cost estimate would not lead to over recovery of costs. Until then the Company must look to the
ECAM to recover wind integration costs. While RMP is not yet able to calculate wind
integration costs with verifiable accuracy, we acknowledge that the costs of integration are
embedded in the Company's actual power supply costs.
We find also that the responsibility for recovery of wind integration costs from
wholesale transmission customers resides with the Company, not its retail customers.
ORDER NO. 32196 30
(b) Cal iso Wheeling and Service Fees
The Company's filing, Monsanto states, includes a full year estimate of California
Independent System Operator (Cal ISO) wheeling and service fees. The fees are incurred when
the Company uses the Cal iSO system to balance and optimize its system. Some of the fees are
related to the Company's strategy to hedge its long position at Four Corners. However, the
Company's filing, Monsanto states, does not include any transactions that would incur Cal ISO
fees beyond May 3, 2010. As a result, net power cost includes a full year of Cal ISO costs, but
only wholesale transactions that would generate the Cal iSO expense prior to May 4, 2010.
Monsanto recommends disallowance of all Cal iSO fees for the period May 4, 2010 through
December 31, 2010. Monsanto also recommends that actual Cal ISO fees be included for the
period prior to May 4, 2010 to match costs with the actual wholesale transactions included in the
Company's fiing. This adjustment, Monsanto calculates, reduces NPC by $.20 millon (Idaho).
Tr. pp. 1523, 1524, 1540.
RMP urges the Commission to reject this adjustment. Cal ISO fees, the Company
states, are incurred for transactions at market points of SP 15, NP 15, and when the Cal ISO is the
counterparty. The bulk of these transactions are short-term transactions made close to the time
of delivery. Cal iSO is a major counterpary in the Company's activities to balance its system.
Tr. p.975. The Company continues to do business with Cal ISO and continues to incur Cal ISO
fees. Not allowing the Cal ISO fees, the Company maintains, is the same as making the
assumption that the Company would not do business with Cal ISO. Removing Cal iSO as a
counterparty, the Company contends, limits the options that the Company may use to balance its
system economically. The Company states that it expects to do business with the Cal ISO in
2010 and the future and wil continue to incur various fees in the markets governed by the Cal
ISO. Tr. p. 976. Through September 2010, the Company represents it incurred approximately
$3.2 milion of Cal ISO fees, both wheeling fees and service fees, which, it states, are only
$66,265 lower than what the Company included in the fiing for the corresponding period. Tr. p.
977.
Commission Findings
The Commission finds Monsanto's argument persuasive. The issue is what should be
included in base rates. The reduced amount included in base rates does not assume the Company
wil not do business with Cal ISO as a counterpary. Transaction data should have been provided
ORDER NO. 32196 31
if the Company intended this to be a continuing forward expense. The Commission accepts the
adjustment. If Cal iso wheeling and service fees are incured, the Company should seek
recovery of costs in the ECAM.
(c) Normalization of Call Option Contracts
1. SMUD
A call option is a contract that allows the purchaser the right to pre-schedule energy
deliveries based on expected market prices and/or the purchaser's requirements. RMP is both a
buyer and seller of call option contracts. The Company models a "call option sale" contract for
the Sacramento Municipal Utilty District (SMUD) in its GRID power supply modeL. Tr. p.
1728.
In GRID, inputs specify contractual energy limits on an hourly, daily, weekly,
monthly or annual basis. For sales with anual contract energy limits, such as the SMUD
contract, PIIC contends that GRID schedules the contract energy during the highest cost hours of
the year. Because the contract has an annual energy limit of approximately 350,400 MWh (with
a 100 MW maximum hourly take), the Company, PIIC contends, assumes SMUD wil call the
energy from the contract during the highest cost 3,500 hours in the year. PIIC contends that for
SMUD, GRID assumes the counterparty finds the most costly way possible to use the energy
available under the contract. In effect, the Company's modeling, PIIC contends, assumes the
"worst case scenario." In fact, PIIC states, what the Company's GRID modeling assumes simply
does not happen in actual operation. Tr. pp. 1728, 1729. Generally, SMUD uses this resource,
PIIC states, in a maner that is far less costly than assumed by the Company's GRID modeling.
This difference, PIIC contends, occurs because SMUD is not using the same forward
price curves as RMP. Differences in delivery location, transmission constraints, availabilty of
the SMUD's own generation and many other factors wil drive decisions to use the available
energy. In the end, SMUD is interested in serving its own customers at the least possible cost
(subject to its own constraints), PIIC contends, not in maximizing the cost to PacifiCorp. Tr. p.
1730. To correct this problem, PIIC proposes to substitute actual data for normalized data for the
Company's sales contract with SMUD. This adjustment, it calculates, reduces the Company's
system NPC by $1.6 milion.
ORDER NO. 32196 32
2. Black Hils
Monsanto proposes that the Company's wholesale sales contract with Black Hils
Power be modeled based on a four-year average of historical dispatch information. Tr. p. 1549.
The Black Hils contract, Monsanto states, is classified a call option contract in GRID and the
contract terms for energy such as hourly, daily, weekly, monthly and annual take and delivery
points are inputs to GRID. Based on this information and the Company's forward price curve,
GRID dispatches the contract during the highest cost hours based on the assumption that this is
what the purchasing entity would do. Monsanto disagrees with this assumption. It really
depends, it states, on the requirements and assumption of the purchasing entity. In the case of
Black Hils, Monsanto states the actual delivery shape of the sale is much flatter than it is
modeled in GRID. Tr. p. 1547. The Company's assumption results in a higher contract cost in
GRID than occurs on an actual basis. To correct this problem, Monsanto recommends that the
energy shape be modeled using the actual delivery shape. Tr. p. 1548.
RMP in rebuttal states that for normalized purposes, the GRID assumes that the
counterpary - who control the call options on these two contracts - wil maximize the value of
the contracts and take power at the most economical time. GRID, the Company states, assumes
optimization of all flexible resources, while PIIC's and Monsanto's proposals embody an
approach optimizing flexible resources when it lowers NPC and not optimizing flexible
resources when it raises NPC. Tr. p. 961. The proposed adjustments, the Company states, depar
from modeling power cost on a normalized basis. If this type of modeling adjustment were
adopted, then consistency and fairness, the Company contends, require its application to all other
flexible purchase or sales contracts that are modeled in a similar fashion. It is not fair or
consistent, the Company argues, to normalize different contracts using different rules. Use of
any delivery patterns other than the optimized delivery patterns, it states, wil always lower net
power costs for wholesale sales contracts with flexibility such as SMUD and Black Hils
contracts. The opposite is true, it states, for purchased power contracts that give the Company
flexibilty in how the power is taken. Tr. p. 962.
The only valid assumption with call option contracts, the Company contends, is to
assume that all participants in the market are rational and wil exercise their rights to the flexible
contract to lower their costs. Tr. p. 963. RMP recommends the Commission reject the
ORDER NO. 32196 33
adjustments proposed by PIIC and Monsanto on the basis that the adjustments violate the
fairness in the optimization of all flexible resources to reduce NPC. Tr. p. 965.
Commission Findings
PIIC and Monsanto, we find, make persuasive arguments to substitute actual data for
normalized data for the Company's call option contracts with SMUD and Black Hils Power.
The Company's argument that what is proposed violates principles of consistency and fairness
canot justify a GRID modeling assumption that is belied by the options exercised by SMUD
and Black Hils. We find it reasonable for these two call option contracts to use an average of
exercised options. For puroses of the revenue requirement in this case, we find use of the four-
year average recommended by Monsanto to be reasonable. For future cases we wil expect the
Company to use a three-year average.
(d) Other Net Power Cost Adjustments
For the remaining net power cost adjustments proposed by the paries in this case, we
find the Company's rebuttal position to be persuasive. These adjustments include the Idaho
Power PTP contract, reserve shutdowns, Energy Gateway transmission, Cholla 4 capacity,
Morgan Stanley call premiums, Bear River hydro normalization, Naughton 3 outage, Lake Side
outages, Colstrip 4 outages, star up energy valuation, Jim Bridger fuel adjustment, heat rate
adjustments, DC Intertie costs, screening for combined-cycle O&M costs, and the treatment of
non-firm transmission and other costs in GRID.
Included in the Company rebuttal, net power costs are the adjustments accepted for
the Dunlap reserves, part of the APS purchase treatment, GRID commitment logic error and start
up costs and Colstrip planed outages in the spring. Although the Company does not agree with
the reasoning, it has reflected the impact of the Mona Market cap and generation overhaul in the
rebuttal costs. The Company also states it wil review these concepts and address them in the
future.
Like the wind integration costs, the GRID assumptions and components need
additional evaluation. Forus to address greater understanding and modifications to better
reflect reality are encouraged.
C. Rate Base
RMP in its rebuttal case proposed a pro forma rate base of $650,554,859 for its Idaho
jurisdiction. Following accepted test period convention, the Company proposed only the
ORDER NO. 32196 34
inclusion of capital projects over $5 milion that were expected to be used and useful by
December 31, 2010. The change in allocation factors due to the decision related to the Idaho
Irrigation Load Control Program, discussed previously, increases rate base. The Commission
accepts making three adjustments decreasing rate base from the Company's rebuttal case:
A. Populus to Terminal
B. Mine Stripping Caring Costs
C. Coal Pile Inventory
We approve an electric pro forma rate base of $677,562,962,
(1) Populus to Terminal
The Populus to Terminal transmission line is the first of eight proposed new high
voltage transmission segments that wil make up PacifiCorp's Energy Gateway transmission
expansion project. Energy Gateway consists of Gateway West, Gateway South, and Gatewåy
Central. Populus to Terminal is one of three segments that make up Gateway Central. Exh.33.
It is a dual circuit 345 kV, 135-mile long voltage transmission line stretching from Downey,
Idaho to Salt Lake City, Utah. Tr. p. 1947. Rocky Mountain Power was granted a Certificate of
Public Convenience and Necessity authorizing construction of the Populus to Terminal 345 kV
transmission line project in October 2008. Case No. PAC-E-08-03, OrderNo. 30657.
RMP proposes to rate base its $801,530,000 investment in the Populus to Terminal
transmission line. The project was planed to be completed and in service in November '2010.
Exh. 37. The project was online by year-end. The line added significant new incremental
transmission capacity (l,400 MW planed) from southeastern Idaho into Utah and helps
integrate other future planned resources, market purchases, and sales as necessar to help control
energy costs. The investment also improves system reliabilty. Tr. p. 703.
In 2008, the 1,700-mile Energy Gateway transmission project was estimated at over
$4 bilion. In 2010, Energy Gateway is described as a 2,000-mile long project at an estimated
cost of approximately $6.6 bilion. PacifiCorp currently has only $2.2 bilion in transmission
plant in service. Tr. pp. 1947, 1948.
RMP describes the Populus to Terminal transmission segment as a "key element in
Gateway Central," which is described as an essential reliability backbone allowing Gateway
West and Gateway South to operate at a higher reliability and an overall higher capacity. The
Company maintains that the Energy Gateway investment supports design capacity ratings based
. ORDER NO. 32196 35
on WECC and NERC planing stadards and criteria and will support future generation resource
development. Tr. pp. 729, 741.
The additional transmission capacity (1,400 MW planed) of Populus to Terminal,
the Company contends, wil make it possible to better utilze the market price differentials
between the east and west sides of the Company's system, reduces reliance on additional
purchases of transmission from third paries, and improves reliability. Tr. pp. 698-700, 709, 929.
The Company maintains that its decision to add transmission capacity is supported by
its 2008 Integrated Resource Plan (IRP), which states that PacifiCorp's "mandate is to assure, on
a long-term basis, adequate and reliable electricity supply at a reasonable cost and in a maner
consistent with the long-run public interest." The IRP analysis is performed by evaluating loads
and resources over a 20-year period. PacifiCorp's existing transmission system, as well as the
transmission grid across the western region, the Company states, is severely constrained and
numerous regional study groups have identified a need for investment in new transmission
infrastructure. Tr. pp. 702, 738.
The Company also cites its MEHC acquisition commitment in 2006 to increase the
transmission capacity by 300 MW from southeast Idaho to northern Utah. Tr. p. 702.
RMP maintains that the Populus to Terminal line is fully "used and useful" and is the
most prudent approach to meet current system electrical demands and those forecasted in the
future. Tr. p. 729. The fact that a facilty is not fully subscribed, the Company contends, does
not mean that it is not "used and usefuL." The only prudent approach to designing and building
utilty facilities, it states, is to consider both curent and future requirements of that facility. Tr.
p. 731. The Populus to Terminal project, RMP contends, provides immediate reliabilty and
capacity benefits to the system well in excess of the 700 MW suggested by Staff. Tr. p. 730.
RMP disagrees with Staffs reference also to Idaho Code § 61-502A regarding the "used and
useful" standard and the implication that the project includes unecessary capacity. Tr. p. 783.
Staff contends that only 700 MW of the 1,400 MW in planed capacity provided by
the Populus to Terminal line is presently used and usefuL. Commission Staff recommends
therefore that only 50% of the Company's investment in the Populus to Terminal line be rate
based and that the remaining portion be held as plant held for future use. Staff contends that it is
an undisputed fact that the project is oversized and wil not be fully utilzed unless or until
Energy Gateway is completed. Tr. pp. 1953, 1956.
ORDER NO. 32196 36
Monsanto contends that the Gateway Central transmission project is but an initial leg
of a very speculative and massive undertaking. Tr. p. 1468. Monsanto recommends that the
Commission defer the entire amount of the Company's investment in Populus to Terminal to the
next rate case, putting incured expenses to date in plant held for future use with no carrying
charge until such time as the degree of used and usefulness is determined. Tr. p. 140. Gateway
Central, Monsanto contends, only makes sense if Gateway South is built.
PacifiCorp in rebuttal strongly disagrees with the recommendations of both Staff and
Monsanto.
Commission Findings
The Commission has considered the extensive testimony of the parties in this case
regarding Populus to Terminal and finds that the Company has not demonstrated that the line is
presently "used and useful" in its entirety. Idaho Code § 61-502A. The record reflects that the
Populus to Terminal line was built to meet not only present needs but future needs. One need
only look to the transcript to reach this conclusion:
. In response to Commission Staff Production Request the Company stated
"the full benefits of the capacity upgrade wil not be realized until
additional segments are built as par of Energy Gateway." Tr. p. 1953.
. The Company states "the benefits of adding the transmission line are to
meet future load and resource requirements." Tr. p. 697.
. The Company states the purpose of the line is to "integrate with future
Energy Gateway segments." Tr. p. 699.
. The Company states the investment (in Populus to Terminal) wil provide
reliability benefits to future planed high voltage transmission additions."
Tr. p. 701.
. The Company states "the Populus to Terminal transmission line segment
is designed. . . to meet future customer energy service requirements." Tr.
p.703.
. The Company's 2008 analysis of the Populus to Terminal project shows
that "the project and its planed capacity are required in the future." Tr. p.
719.
. The Company states "in the future, (the Populus to Terminal line ) wil also
provide incremental capacity." Tr. p. 753.
ORDER NO. 32196 37
Of the 1,400 MW of additional capacity that the Populus to Terminal line provides,
we note that the record reflects the Company can only presently use between 1,000 MW
(rebuttal) and 1,040 MW (surebuttl). Rather than rate basing 100% of the Company requested
$801.530 milion, we find that only 73% of the Company's investment represents plant that is
currently "used and usefuL." We find it reasonable to place $216.413 milion or 27% of the
Company's Populus to Terminal investment in plant held for future use. From a capacity
standpoint this represents 1,022 MW of the total 1,400 MW that Populus to Terminal can
ultimately provide. We find that the remaining 27% may not be fully used and useful until the
other Energy Gateway segments are completed. The Energy Gateway project segments, we find,
continue to change in scope and timing. Idaho, we find, wil pay its fair share to meet the
Company's system load and transmission requirements but we will not allow full ratebasing of
investment in Populus to Terminal prematurely and we wil not require Idaho customers to
assume and pay for unused capacity. The "used and useful" issue raised by the paries is
perceived by this Commission on the facts of this case to be one of operational and regulatory
timing.
(2) Mine Stripping Carrying Costs
In Case No. PAC-E-09-08 (Order No. 30987), the Commission authorized RMP to
record, as a regulatory asset, the costs associated with removal of overburden and waste
materials at its affiliate coal mines. In this case the Company seeks to recover its removal costs
together with a related carring charge for inclusion in base rates. Tr. p. 1166.
Staff argues that because the regulatory asset was created as a result of an accounting
procedural change, it would be inappropriate for the asset to accrue a carying charge. Staff
removed the caring charges from rate base ($1,169,114), decreasing the Idaho revenue
requirement by $6,133. Tr. p. 2031.
RMP in rebuttal contends that Staffs adjustment unfairly penalizes the Company for
an attempt to reduce the disparity created by timing difference between incurring the stripping
costs and the time when the uncovered coal is actually extracted. As approved by the
Commission, stripping costs are now deferred to a regulatory asset rather than immediately
included in fuel stock inventory and amortization is matched with coal extraction. Without the
deferred accounting treatment, the Company is required to reflect stripping costs as variable
production costs during the period the stripping costs are incurred. Tr. p. 1202.
ORDER NO. 32196 38
Commission Findings
In our Order No. 30987 authorizing creation of a regulatory asset, we deferred a
decision regarding the propriety of the deferred coal stripping costs until the Company requested
recovery of such costs through rates. It was noted in our Order that the Company's application
did not include a request to ear a retur on the regulatory asset. Staff nevertheless, we noted,
expressed its opinion in that case that such a return was inappropriate. We find it reasonable to
approve Staffs adjustment removing carrying charge costs associated with the regulatory asset.
Typically this Commission has not allowed carring charges for deferrals. There is no
compellng reason here to depar from this practice. Absent a Commission Order authorizing a
regulatory asset, RMP would have to expense these costs. Inclusion of the base deferrals, absent
a carrying charge, is the appropriate ratemaking treatment. The revenue requirement impact of
this adjustment is ($8,267) Idaho.
(3) Coal Pile Inventory
The Company increased coal fuel stockpile in Account 151, Fuel Stock, by
$24,644,591 on a system basis with $1,581,176 allocated to Idaho. Tr. p. 1976. The Company
states this increase was due to the cost of coal and the number of tons stored at each site. Tr. p.
1165.
Staff contends the Company provided no acceptable explanation or justification for
significant changes in the stockpile tonnage at the different plant sites. Tr. p. 1977. Commission
Staff proposes to limit the coal inventory for each plant site to no more than the actual tons as of
December 2009. This adjustment removes $15,970,759 (system) from rate base. Tr. pp. 1974,
1978; Conf. Exh. 102.
RMP contends that Staff adjusted inventory levels in Utah without considering the
inter-relationship between stockpiles and the economic benefits of the higher stockpile levels in
Utah. Further, the Company contends that Staffs analysis ignores the supply risks associated
with maintaining adequate inventory levels, paricularly in Wyoming. Tr. pp. 682, 683. The
Company states there are no plans to reduce plant inventory levels below test period ending
balances. Tr. p. 683. The Company recommends that Staffs proposed adjustment be
disallowed.
ORDER NO. 32196 39
At the hearing, Staff witness Leckie accepted the need to consider the inter-
relationship with the Utah plants. He corrected his adjustment down to $9,204,118 (system) to
reflect this relationship.
Commission Findings
The Commission finds that the record does not demonstrate a reasonable and
persuasive explanation for the increase in stockpile tonnage at the different plant sites. The
contracted study performed for the Company analyzed inventory levels for the Company's
Wyoming coal plants only, not Utah. Tr. p. 682. We appreciate that the Company intends to
seek opportunities to manage its fuel cost and quality through inventory management and may
revise its inventory targets in Utah. Tr. p. 683. We invite the Company to come back once it
completes its study. We find it reasonable in this case to accept Staffs adjusted fuel stockpile
adjustment of $9,204,118. We also find it reasonable to transition the stockpile increases over
three years. This transition would allow an additional stockpile amount of $3,068,039 or a net
adjustment of $6,136,079 in this case. The revenue requirement impact of this adjustment is
($45,556) Idaho.
(4) Other Rate Base Adjustments
As noted previously, in its rebuttal adjustments the Company accepted the rate base
adjustments associated with the Bridger Unit 2 overhaul liquidated damages and major plant
additions update. The associated taxes, depreciation expense and depreciation reserve were also
reflected in the rebuttal numbers.
We accept the Company's position on the remaining rate base issues including the
cost-effectiveness of including the entire Dunlap Ranch property.
Cash working capital using the 2007 lead-lag study is accepted for this case. Usually
we wil utilze the balance sheet approach where there is a showing of who provides the funds.
The Company states it updates the lead-lag study every five years. We believe the Company
should show how the lead-lag study can be used while appropriately considering who provides
the funds in its next rate case.
Summary of Adjustments to Test Year Revenues, Expenses and Rate Base
Considering all the evidence presented, and including all adjustments, the
Commission finds just and reasonable Idaho jurisdictional expenses for the test year in the
amount of $222,670,703, and Idaho jurisdictional operating revenues in the amount of
ORDER NO. 32196 40
$268,177,671. The after tax Idaho revenue requirement increase is $13,755,728. After all
adjustments, we find a total Idaho jurisdictional rate base amount of $677,562,962 to be just and
reasonable.
Calculation of Revenue Deficiency
Rate Base
Rate of Retur
Total Revenue Requirement
Operating Income
Income Deficiency
Conversion Factor
Revenue Requirement Deficiency
$677,562,962
7.98%
$54,022,366
$45,506,968
$8,515,398
1.615
$13,755,728
Revenue Requirement
The Commission in this case approves a base revenue requirement of $54,022,366
(Idaho), an increase in electric base rates of$13,755,728, or 6.78%.
III. JURISDICTIONAL ALLOCATION, COST OF SERVICE,
REVENUE SPREAD AND RATE DESIGN
A. Jurisdictional Allocation - Revised Protocol
PacifiCorp is an electrical corporation and public utilty and provides electric service
in Idaho and five other western states. PacifiCorp owns substantial generation and transmission
facilities. Augmented with wholesale power purchases and long-term transmission contracts,
these facilties operate as a single system on an integrated basis to provide service to all
customers. PacifiCorp recovers costs of owning and operating its generation and transmission
system in retail prices established from time-to-time in state regulatory proceedings.
Because all of the Company's generation and transmission resources are deemed to
be used to serve the Company's customers in all of its state jurisdictions, the Company contends
it is necessary to determine what portion of the costs associated with each of the rate based
resources ought to be allocated to customers in the state for which prices are being established.
To allocate system generation, transmission and distribution costs in its multiple jurisdictions an
Inter-jurisdictional Cost Allocation methodology was established. That methodology is
presently set fort in what is identified as the Company's "Revised Protocol." The Revised
Protocol was approved by the Commission on February 28, 2005 (Order No. 29708, Case No.
ORDER NO. 32196 41
PAC-E-02-3) for allocation of costs in Idaho, subject to the terms of the fied Stipulation and
Agreement.
Importantly as noted by the Commission, "the Revised Protocol does not prejudge
issues of prudence, rate spread, rate design or cost recovery. Each state Commission continues
to establish fair, just and reasonable rates." Order No. 29708, p. 10.
Commission Findings
It is in accordance with the Revised Protocol methodology that the Company has
filed this rate case. It is pursuant to the power reserved to this Commission that we have
determined that costs associated with the Idaho Irrigation Load Control Program should be
allocated as system costs and not Idaho or situs costs. In doing so, we have determined that
continued treatment of such costs as a DSM-1 resource and as an Idaho situs cost no longer
produces results that are fair, just and reasonable and in the public interest.
B. Cost of Service
Once Idaho jurisdictional test year costs are determined with the Company's Revised
Protocol Jurisdictional Cost Allocation methodology, the next step is to allocate the adjusted
costs or the revenue requirement to a series of fuctional costs and then to the different customer
classes served by RMP in accordance with recognized principles and generally accepted
procedures in order to obtain an indication of relative cost responsibilities of each class of
customers. This allocation is done in two parts. First, a class cost of service (COS) study is
conducted that identifies what the revenue allocation for each class would be at full COS.
Finally, if some increases are considered to be too large, a maximum increase cap is established
and unecovered revenue is spread to other classes.
RMP's cost of service methodology in this case is set forth in Exhibits 47, 48 and 49.
The methodology presented by the Company is the same basic methodology used in the Revised
Protocol jurisdictional allocation process. It is also the same methodology accepted by the
Commission in recent general rate case decisions for the Company. Tr. p. 2130.
Keeping the methodology the same, Staff contends, simplifies the case and allows
the class cost of service results to be driven by class energy, demand and customer characteristics
and changes in Company costs. When the methodology is changed, COS results for customer
classes, Staff states, may change significantly without any change in customer usage
characteristics or underlying service costs. Tr. p. 2130.
ORDER NO. 32196 42
PIIC recommends that the demand allocation factors used in the Company's cost of
service study be modified to more accurately assign demand-related costs. PIIC recommends the
class demand allocation factor be based on the comparable jurisdictional peak hour with a more
up-to-date irrigation class demand. The Company's 12 monthly coincident peak factor (12 CP)
for assigning generation and transmission-related demand costs, PIIC contends, should be
replaced with a winter/summer peak factor (W/S CP) using the peak load months of July and
December. The weighted 12 monthly peak factor used by the Company for distribution related
demand costs, PIIC contends, should be replaced with the class maximum peak demands (1
NCP) to more accurately assign distribution costs responsibility. PIIC supports a cost based rate
spread approach but recommends that it be done using the results of its cost of service study. Tr.
pp. 1685, 1686.
Monsanto contends that a proper valuation of Monsanto's curtailment should reflect
the avoidance of capacity and energy. Without a valuation of Monsanto's interrptibilty, the
cost of service study results provided by the Company and treatment of Monsanto's load as "all
firm," it states, are incomplete. Tr. pp. 1592, 1602.
PacifiCorp in rebuttal criticizes PIIC's proposed use of a 2 CP method. Such a
method, the Company states, fails to recognize how the Company plans and operates its
generation and transmission systems; is inconsistent with inter-jurisdictional allocations; has the
potential to shift customer costs creating rate volatility; and violates the principle of gradualism
which is generally viewed as an important consideration in determining class cost causation. In
addition, the Company states that PIIC provides no significant analysis to support its
recommendation. PIIC's recommended 1 NCP allocation method, the Company contends, is not
appropriate because it ignores the cost causing basis for these facilities, i.e., customers load
diversity. Tr. p. 1293.
C. Revenue Spread
Revenue spread is the determination of the revenue amount that needs to be collected
from each customer class. It is driven primarily by class cost of service (COS) results. Tr. p.
2131.
RMP proposes to move all customer classes to nearly full COS except the Street and
Area Lighting class (Schedules 7, 11, 12) that would receive a rate reduction in a full COS move.
The Company proposes no change in the lighting revenue requirement and to respread the
ORDER NO. 32196 43
lighting decrease, that would otherwise occur, to all other customer classes to achieve the
recovery of the full revenue requirement. Tr. p. 2131.
Staff proposes to use the same methodology presented by the Company with one
difference. Staffs proposal is to allow no class revenue requirement decreases while moving
customer classes requiring increases toward full cost of service with uniform percentage offsets
to balance the revenue requirement for the lighting class reduction not given. Staff would also
assign residential customers taking service under Schedules 1 and 36 an equal percentage
increase. Tr. pp. 2131,2132.
Commission Findings
The Commission acknowledges the Company's cost of service study as reasonable
and recognizes its use in the Revised Protocol and our use of the study in prior Company rate
cases. We find no reason to abandon its use despite the recommendations of other paries.
Cost of service modeling is not an exact science. A cost of service study is not a
perfect tool for assigning system and service costs to customer classes. Accepting the COS
results as a staring point, we must then determine the appropriate revenue requirement to be
recovered in the rates of the different system customer classes. In doing so, we strive to achieve
an equitable apportionment of the revenue requirement among the customer classes. We find it
reasonable in this economy that the Street and Area Lighting class receive no COS adjustment
and that the difference offset the increase to other classes. We also find good cause to limit the
COS increase to Monsanto in this case to under 10%. These changes are reflected in the rates we
approve. We find the recommendation of Staff to assign residential customers taking service
under Schedules 1 and 36 equal percentage increases to be reasonable. Comments and testimony
of customers under the two residential service schedules, we note, reflect that they do not
understand why the Company proposes separate treatment for Schedules 1 and 36. The revenue
increase allocated to each class is depicted in Attachment A.
D. Rate Design and Electric Rates
Schedule 1 - Residential
RMP
For Schedule 1 residential customers, RMP proposes a two-tiered inverted block
pricing structue for energy use and a $12 fixed monthly customer service charge. Curently,
ORDER NO. 32196 44
customers served on Schedule 1 pay a flat seasonally differentiated energy charge applied
equally to all kilowatt hours. In addition, a monthly minimum charge can apply. Tr. p. 1326.
Under the Company's proposed revisions, seasonal rates will continue to apply and
two energy blocks wil be implemented in the two biling seasons. The first energy usage block
in each season wil apply to usage for the first 800 kWh per month. All additional kWh wil be
biled at the higher second tier price. The Company chose to terminate the first block at 800
kWh in order to reflect curent average usage on Schedule 1 (839 kWh per month). Average
Idaho residential customers on Schedule 1 would experience an increase well below the average
increase in the Company's case. Larger users with more usage would see substantially larger
increases. Tr. p. 1326.
The proposed inverted rate design for residential Schedule 1 is submitted by the
Company consistent with the terms of the Stipulation approved by the Commission in the
Company's 2008 Idaho general rate case (PAC-E-08-07). Tr. p. 1327.
The Company proposes that the curent monthly minimum charge for Schedule 1
customers ($10.64) be eliminated and replaced with a proposed fixed monthly customer service
charge of $12. A customer service charge that achieves a high level of recovery of the fixed
costs of serving customers, the Company contends, wil more appropriately assure that each
customer pays its fair share of costs and wil allow the Company a better opportunity to recover
the fixed costs of serving customers. Tr. p. 1327. The Company contends that recovery of all
fixed costs related to Schedule 1 service would result in a monthly customer service charge of
approximately $29.86 per month. Tr. p. 1328; Exh. 53.
Commission Staff
Commission Staff supports retaining the current seasonal differentiation, but proposes
that different tiered rate block thresholds apply in sumer and winter - the first block would be
comprised of the first 700 kWh in the sumer and the first 900 kWh in the winter. Staff
maintains that rate design should be based on sending cost-based price signals that promote
efficient consumption of energy. Tr. p. 278. Tiered rate design and time-of-use rates, Staff
contends, both reflect the variable cost to serve. Tr. p. 288.
When promoting tiered rates, Staff states, one must not lose sight of the general rate
design principles: rate equity, rate stabilty, and opportunity for the utilty to recover its
approved costs. Tr. p. 289.
ORDER NO. 32196 45
Staff supports the Company's proposed removal of the minimum charge and
establishing a monthly customer charge for Schedule 1 customers. Staff believes, however, that
the $12 Company-proposed minimum charge is too high. Staff proposes a lower $5.00 monthly
charge for Schedule 1 customers. This amount, Staff contends, suffciently provides recovery of
the Company's meter reading and biling costs. Recovery of meter reading and biling costs is
the traditional basis promoted by Staff in setting customer charges. Tr. p. 290. A $5.00
customer charge would be no higher than that approved for both Idaho Power and A vista.
Idaho Power, Staff notes, has a three-tiered rate structure for residential and
commercial customers during the summer and non-summer seasons. A vista has a two-tiered rate
strcture for residential customers.
ICL
ICL proposes a three-block inverted residential rate design and proposes different
energy charge blocks in both the summer and winter months. Tr. p. 1336. In the summer ICL
proposes the following blocks: 0 to 700 kWh, 701 to 1800 kWh and greater than 1800 kWh. In
the winter it proposes the following blocks: 0 to 1000 kWh, 1001 to 3000 kWh, and greater than
3000 kWh. ICL proposes the same rates in each of the three tiers regardless of season.
RMP believes that the seasonally differentiated tiers proposed by Staff are
unecessar and wil have little meaningful impact on customer usage. In fact, the Company
believes the rate design may increase customer confusion, paricularly during the transition from
the existing flat rate to an inverted rate. The Company maintains that the proper way to
implement a transition to an inverted rate is to implement a single year-round tier with the
seasonally differentiated prices. Tr. p. 1337.
ICL's proposed three-tier rate design, the Company contends, greatly increases rate
complexity and volatilty and the Company does not support it. ICL's proposal, the Company
contends, wil introduce even more rate complexity than does Staffs proposaL. The Company
recommends that it be rejected.
Schedule 36 - Time-of-Use Residential Service
RMP
The Company proposes to retain the existing time-of-use residential rate structure and
to apply increases to both the customer service charge and to the on- and off-peak energy
ORDER NO. 32196 46
charges. Even with these changes, the Company contends that customers on Schedule 36 wil
continue to benefit from the time-of-use rate design. Tr. p. 1329.
Commission Staff
Staff supports the Company's proposal to maintain the on-and off-peak differentials
for Schedule 36 customers. Staff contends that a flat rate design, in which kilowatt-hour rates
are based on average costs and do not var based on timing or level of consumption, do not
reflect the disparity in costs to serve load during peak demand and off-peak period. Tr. p. 288.
The Schedule 36 time-of-use rates, Staff contends, are both aggressive and fair. Tr. p. 287.
ICL
ICL proposes to lower the customer charge under TOU Schedule 36 from its curent
level and to eliminate the curent seasonal differentiaL.
RMP criticizes ICL's proposal as "turing back the clock." Idaho TOU customers,
the Company states, have paid a higher customer charge than ICL proposes, and they have paid
seasonally differentiated energy charges for more than 20 years. The Company believes that
durng a time of rising costs, ICL's proposal to reduce the curent TOU customer charge is
unacceptable. It is not cost-based, the Company contends, does not reflect the curent cost
environment, and sends an incorrect price signal to time-of-use customers. RMP recommends
that ICL's proposal be rejected. Tr. p. 1339.
Commercial and Industrial -
Schedules 6 and 6A (General Service - Large); 9 (General Service - High Voltage);
10 (Irrigation)
For general service and irrigation rate design, the Company proposes slightly greater
increases to demand rates than to energy rates. Such a result is supported, it contends, by its
class cost of service results. Tr. p. 1330.
Schedules 19,23, 23A, 400 (Monsanto) and 401 (Agrium)
The Company's proposes rate design changes for Schedules 19, 23, 23A, 400
(Monsanto), 401 (Agrium) is a uniform percentage increase to all biling elements. Tr. p. 1330.
Staff supports the Company's proposal to increase all biling components on an equal
percentage basis for large industrial customers. Tr. p. 286. Equally spreading the revenue
increases to all biling determinants, Staff contends, stil provides a significant level of fixed
ORDER NO. 32196 47
customer recovery while sending customers a strong price signal through relatively higher
energy rates. Tr. p. 287.
Commission Findings
The Commission finds the two-tiered residential RS-1 rate structure proposed by
Staff to be a fair, more reasonable and more equitable rate design for sending cost base price
signals and encouraging conservation than the other options proposed by ICL and RMP.
Recognizing the seasonal energy use data and all-electric heating equipment of many RMP
customers, we find it reasonable to establish two seasonal rates for May to October and for
November to April with the first tier block capped at 700 kWh for May-October and 1,000 kWh
for November-ApriL. We find the Company's proposal to eliminate the Schedule 1 minimum
charge and replace it with a fixed monthly customer charge to be reasonable; however, we accept
Staffs $5.00 proposal to be a more reasonable charge and consistent with customer charges
approved for Idaho Power ($4.00) and Avista ($5.00).
The rate structue and electric rates we approve as just and reasonable are set out in
Attachment B. Idaho Code § 61-502. They include a two-tiered, seasonal rate structure for
residential customers with an average rate increase of 6.8%. We approve a monthly customer
charge of $5.00 for Schedule 1 (Residential) customers and $14.00 for Schedule 36 (Residential
Time-of-Use) customers. This increase in rates wil be accompanied by a reduction in the
Customer Efficiency Services rate from 4.72% to 3.40%. This reduction in the tariff rider
percentage results from our decision to treat the Idaho Irrigation Load Control Program as a
power supply cost.
iv. ECONOMIC VALUATION OF MONSANTO'S INTERRUPTIBLE CREDIT
Monsanto is a special contract customer of RMP receiving electric service under taiff
Schedule 400 with a total load of approximately 182 MW. Tr. p. 2874. The curent Electric
Service Agreement (ESA) between RMP and Monsanto contains three distinct interrptible
products provided by Monsanto to RMP. These products include the following: (1) a Non-
Spinning Reserve Product that allows RMP to interrpt Monsanto's service, upon 10 minutes'
notice, for a total of 95 MW and 188 hours per year; (2) an Economic Curtailment Product
allowing RMP to interrupt Monsanto, upon two hours notice and for any reason, for a total of 67
MWand 850 hours per year; and (3) a System Integrity Product that permits RMP to interrpt
electric service to Monsanto for a total of 162 MW and 12 hours per year. Tr. pp. 2653, 2654.
ORDER NO. 32196 48
The System Integrity Product is available, without notice to Monsanto, only if a "double
contingency event," defined in the paries' contract as two or more forced outages of RMP's
generation assets, happen to occur within a 48-hour period. Tr. p. 2654.
Mandatory reliabilty standards require that an electric utilty hold 5% of its hydro-
generation capacity and 7% of thermal generation capacity in reserve. Tr. p. 2928. One half of
this capacity held in reserve can be used to meet its spinning reserve requirements and the other
half can be utilized to meet its non-spinning reserve requirements. Tr. p. 2928. The spinning
reserve requirement can be met with resources that can be applied immediately and ramp up
within 10 minutes. Non-spinning reserves must be capable of being applied within 10 minutes
of being called upon to meet load. Tr. p. 2928. Western Electricity Coordinating Council
(WECC) standards dictate that interrptible loads, like the one Monsanto provides, can only be
used to satisfy non-spinning reserve requirements. Tr. p. 2929.
RMP
As an initial premise, RMP believes that "a definition of 'value' is the price at which
two parties are wiling to enter into an agreement." Tr. p. 2629. Nonetheless, the Company
conducted a fairly extensive analysis of Monsanto's Economic Curailment, Non-Spinning
Operating Reserves, and System Integrity Products, utilizing its recent IRP studies, GRID and
Front Office (FO) models as the appropriate methods for establishing a value. Tr. p. 2630.
RMP asserts that its most recent IRP studies demonstrated that the "removal of Monsanto
interrptible product as a firm resource. . . did not create the need for a new resource" or "avoid
the acquisition by the Company of generation resources." Tr. p. 2631.
RMP arived at a value for Monsanto's 12 hours of system integrity interrption by
utilzing its FO Model to calculate the average on-peak price for the calendar years of 2011,
2012 and 2013. Tr. p. 2670. RMP's valuation of the System Integrity product is partially
premised on the notion that Monsanto, with or without its ESA, is subject to interrption just
like any other customer on RMP's system. Tr. p. 2638. Additionally, RMP believes that the
likelihood of the occurrence of a double contingency event triggering an interrption in order to
maintain system integrity is relatively constant throughout year. Tr. p. 2638. Thus, according
to RMP, it is highly unlikely that every interrption to maintain system integrity would, as
Monsanto claims, occur when the price for electricity is at the market cap of $400 per MWh.
Tr. pp. 2637, 2638.
ORDER NO. 32196 49
For the Economic Curailment and Non-Spinning Reserves Products, the Company
used the average of its FO and GRID model runs for that same time period, 2011-2013. Tr. pp.
2662-2664, 2668-2669. According to the Company, the FO amount for the Economic
Curilment Product is equal to the market value of the energy during the highest priced hours.
Tr. p. 2668. For the Non-Spinning Reserve Product, the FO amount is determined by what it
would cost to replace the product provided by Monsanto with its existing resources. Tr. p.
2662. The Company's GRID model is ru with the Non-Spinning Reserves and Economic
Curailment Products present in the model and then later without these products in the modeL.
Tr. pp. 2662-2663, 2666, 2668. The value of the Monsanto credit for each of these products is
the difference between each of these rus of the GRID modeL. Id.
In its testimony, RMP cites Appendix D of the Multi-State Revised Protocol (RP).
Tr. p. 2601. The RP demands that electric service provided from a utilty to special contract
customers like Monsanto should be "viewed as two transactions." Tr. p. 2602. Revenues from
these customers are calculated as if no interrption occurred and then assigned to the State
where the customer is located. Id. The second transaction is for the ancilar service, in this
case interrptibilty, and "allocated among all states on the same basis as other system
resources." Id.
RMP's Application states that it treats Monsanto's credit for the provision of
interrptible products to the Company as a net power cost and values them at the curent 2010
contract amount. Tr. pp. 2650-2651. The Company states that it follows a "customer
indifference approach" when valuing interrptible products offered by its industrial customers -
paying those customers what they would pay if they were to acquire the same products from the
market or by virtue of their own existing resources. Tr. p. 2651. The cost of Monsanto's
interrptible products is then allocated on a system-wide basis. Id.
RMP agrees with Monsanto that "the Monsanto interrptible products defer resources
of some type." Tr. p. 2675. However, the Company does not agree with Monsanto's assertion
that if it were no longer to provide interrptible service to the Company it would necessitate the
construction of a new simple-cycle combustion turbine (SCCT). Id. In 2010, RMP believes
that it would only have to replace 37% of the operating reserve product provided by Monsanto
and that it could accomplish this with its existing generation resources. Tr. pp. 2629-2630.
ORDER NO. 32196 50
RMP responded to Monsanto's assertion that the value of its ESA should be based
primarily on the avoided cost of a new SCCT by stating that a SCCT is simply "more valuable
than the Monsanto interruptible products." Tr. pp. 2631, 2677. According to the Company, a
SCCT provides more services than Monsanto interrptible products, including automatic
generation control, load following, and spinning reserves. Tr. pp. 2632-2633, 2677-2678.
Combustion turbines also operate more frequently than interrptible products. Tr. pp.
2633-2634. A SCCT is available in excess of 8,000 hours per year as opposed to the roughly
thousand hours of curtailment available from Monsanto. Tr. p. 2679. RMP argued that it can
curtail a maximum of 116MW of Monsanto's load during approximately 2% of the total hours
of the year. Tr. p. 2613. Moreover, RMP has complete control over when a combustion turbine
is used. Tr. p. 2635. In contrast, the Company states that it only has control over when
economic curtailment occurs, as opposed to the system integrity or operating reserve products.
Id.
Fundamentally, the Company believes that the value of its operating reserves should
be determined by the "value that could be received for that same megawatt if it were not set
aside for operating reserves and instead sold to the market." Tr. p. 2655. RMP goes on to cite
the profit that its existing fleet of resources would actually generate when those resources are
not providing a reserve product as the appropriate measuring stick. Id. For a gas plant, the
margin is the price of natural gas and the price of energy, the "spark spread," less variable
operating costs. Id.
RMP believes that it is unecessary to add an incremental capacity value to the
operating reserve product because the Company's method already adds an implied capacity
value for the 2011-2013 time period by including "recent market price curves for firm energy
products. . . ." Tr. p. 2640. Additionally, RMP believes that Staffs valuation is flawed because
Staffs proposed surrogate, the Curant Creek facilty, adds more value to the system than just
the provision of operating reserves. Tr. p. 2641. The Company argues that it is incorrect to
assign 100% of the capacity cost of a resource to the non-spinning operating reserve product
because it inevitably leads to the overvaluation of that product. Tr. p. 2643. RMP argues it is
more appropriate to allocate a percentage of the capacity cost of multiple units reflecting the
percentage of time these units are called upon in order to meet RMP's non-spinning operating
reserve requirements. Tr. p. 2643. RMP claims that a ru of its GRID model demonstrates that
ORDER NO. 32196 51
its Gadsby and Curant Creek units are utilzed, on average, 46.2% of the time to meet Non-
Spinning operating reserve requirements. Tr. p. 2643.
The Company countered Monsanto's comparison of its ESA with that ofRMP's other
two special contract industrial customers in Utah by noting that Monsanto only compared their
base retail rates with those other special contract customers and failed to compare the operating
reserve product. Tr. p. 2639. RMP's contracts with its QF parners can also be distinguished.
Those contracts have availabilty guaantees, liquidated damages for non-performance and other
terms not included in Monsanto's contract with RMP. Tr. p. 2636.
RMP argued that any comparison of the Monsanto-RMPESA to its Idaho Irrgation
Load Control Program is also inapt. Tr. p. 2548. Monsanto relied "solely on peaker units" in its
analysis ~f the credit while RMP included "both peakers and market purchases in the evaluation
of the Irrgation Load Control Program." Id Moreover, the Company mentions that the
Irrigators' credit for paricipation in the program is discounted by 59%. Id RMP argues that
Monsanto's reliance on peaker units is misplaced because the Company's resource procurement
process and the IRP process have shown that "they are not least cost." Tr. p. 2549.
RMP remarked that Monsanto can be interrpted for a total of 1038 hours (12%) in
any given year. Tr. p. 2613. For the remaining hours of the year, 88%, RMP must serve
Monsanto without interrption. Id The ESA is also strctured to provide Monsanto with some
flexibilty by assigning the curailment products to different fuaces. Id.
Finally, should the Commission adopt Staffs method of valuation, RMP proposes
two substantive modifications. Tr. pp. 2642-2645. First, RMP argues that the Commission
.. should make an adjustment to include the cost of other units besides the Curant Creek facilty;
and, second, the Commission should enter an adjustment to account for the fact that combustion
turbines provide other valuable products besides the non-spinning reserve product. Tr. p. 2642.
Staffs method must be altered to utilze the capacity costs of multiple resources used by the
Company to provide non-spinning operating reserves instead of just Curant Creek, as well as
account for the fact that these resources provide other resources besides operating reserves. Id
Monsanto
Monsanto's testimony confirmed its strong desire to achieve "price certainty and
stability" going forward. Tr. p. 2763. Monsanto is a long-term, 60-year, customer of RMP
receiving interrptible service. Tr. p. 2824. Monsanto believes that RMP's use of the GRID and
ORDER NO. 32196 52
FO models for the test year used in the curent rate case "reflect only short-term considerations"
and "ignore the long-term resource costs that the Company has avoided, and continues to avoid,
due to Monsanto's long-term interrptibility." Tr. p. 2826.
Monsanto's assessment of the electrical service it receives differs substantially from
RMP. Monsanto asserts that only 9 MW of its load is "served at firm energy and demand rates."
Tr. p. 2874. The remaining portion of its load, approximately 173 MW, is "interrptible and
biled under interrptible demand charges." Id. Monsanto points out that the interrptible
service it provides to the Company is recognized as a Class 1 DSM resource in RMP's 2008 IRP.
Tr. p. 2821. According to Monsanto, if it ceased to provide that interruptibilty, RMP would
need to acquire a firm energy resource, a new SCCT unit, to replace the Economic Curailment
and Operating Reserve Product and market purchases for the System Integrity Product if a
double-contingency event occurs. Tr. pp. 2816.
Monsanto argued that RMP and Staffs valuation of its System Integrity product is
too low. Among other reasons, the valuation is not appropriate because when an interrption is
necessary due to a double contingency event market prices for electricity, if it is available at all,
are likely to be much higher than the annual average market price. Tr. p. 2819. Specifically,
Monsanto bases its valuation of this product on both the $400/MWh WECC price cap and the
$l,OOO/MWh California Independent System Operator's (CAISO) energy bid cap. Tr. p. 2811.
Monsanto intimated in its testimony that it would likely reconsider inclusion of this product from
a future ESA with RMP if it could not recover more than the credit proposed, $ 0.1 millon, by
RMP and accepted by Staff "for being the first one in dark" if a double contingency event
occurs. Tr. p. 2833.
Monsanto bases its valuation of the Economic Curailment product on the energy and
capacity cost of a newly constructed SCCT unit. Tr. p. 2801. According to Monsanto, RMP
uses the interrptibilty provided in the ESA in much the same way that it utilizes a combustion
turbine. Id. Monsanto's "avoided peaker analysis" is appropriate because a SCCT unit has a
lower construction cost ($25.5 milion vs. $28.4 milion) than a combined cycle unit. Tr. p.
2830. The quick start capability of a SCCT makes them the ideal replacement for an
interrptible customer. Id.
Monsanto attempts to rebut RMP's argument that a CT unit offers more products than
Monsanto by asserting that a CT unit does not start 100% of the time. Tr. p. 2832. Therefore,
ORDER NO. 32196 53
according to Monsanto, its service is plainly more reliable than a CT unit. Id. Moreover,
Monsanto's Interruptible Products should be valued much higher than the curtailment provided
by RMP's Irrigation Load Control Program (ILCP) paricipants because ILCP participants offer
only 52 hours of interrption during the summer irrigation season while Monsanto offers more
than twenty times that amount (1050 hours) with no seasonal limits. Tr. p. 2837.
Monsanto arived at the value for the non-spinning reserve product by averaging the
avoided energy and capacity costs of two SCCT Aero-derivative units. Tr. pp. 2800-2804. The
capacity costs include a 12% planing reserve. Tr. p. 2804. Monsanto believes that the amount
it requests for this product is supported by the current 20 year levelized rate for Qualifying
Facilities (QFs) ordered by the Public Service Commission of Utah. Tr. p. 2810.
Staff
Staff accepted the values presented by RMP for Monsanto's System Integrity and
Economic Curailment Products. Tr. pp. 2924-2927. For the Non-Spinning Reserve Product,
Staff believes that RMP has "reasonably estimated the energy value," but an additional
incremental capacity value must also be included in order to equitably "value the product." Tr.
p. 2928. Staff recommends that the Commission add a yearly capacity value to the Monsanto
Non-Spinning Operating Reserve Product. Id.
Staff proposes that the Commission use a surrogate resource as a guide to determine
the capacity value. Tr. pp. 2931-2932. Staff explain that its analysis led to the examination of
the capacity costs of RMP's Gadsby Units 4, 5, 6 (SC aero-derivative units that can provide
Non-Spinning Operating Reserves even when cold) and its Current Creek facilty (CCCT). Id.
Staff noted that these units have some of the lowest capacity costs of any of the resources in
RMP's generation fleet. Tr. p. 2931. According to Staff, the Currant Creek facility is the most
useful surrogate for establishing the capacity value of the non-spinning product because RMP's
own studies reveal that, absent the Monsanto contract, Currant Creek would pick up a larger
percentage of the displaced reserve requirement than the Gadsby units. Tr. p. 2933.
Commission Findings
The following table demonstrates the value/credit each of the paries would award to
Monsanto for the provision of the aforementioned Interrptible Products:
ORDER NO. 32196 54
Monsanto Interruptible RM Monsanto Staff RMP Modifications to
Product Stafls Position
System Integrity
1 Year Credit (milion $)0.1 0.1
2 Year Credit (millon $)0.1 0.1
3 Year Credit (milion $)0.1 0.1
Single Credit Amount (milion $)0.8
Economic Curtailment
1 Year Credit (milion $)3.6 3.6
2 Year Credit (milion $)4.0 4.0
3 Year Credit (milion $)4.2 4.2
Single Credit Amount (milion $)11.2
Non-Spinning Operating Reserves
I Year Credit (millon $)2.4 9.7 5.4
2 Year Credit (milion $)3.0 10.3 6.0
3 Year Credit (milion $)3.3 10.6 6.3
Single Credit Amount (milion $)14.3
Total i Year Credit 6.1 13.4 9.1
Total 2 year Credit 7. I 14.4 10.1
Total 3 Year Credit 7.6 14.9 10.6
Two Year Avg. Credit 13.9 9.6
Three Year Avg. Credit 14.2 9.9
Single Credit Amount (milion $)26.3
The valuation of Monsanto's Interrptible Products is an issue the Commission has
confronted at various times in the past. Rate design generally follows principles of cost
causation and cost allocation but it is not an exact science or a mathematical exercise. Arriving
at a specific value for the Monsanto credit is "at least as much art as science." Tr. p. 2954. "The
cost of service for firm load customers is an imprecise science and establishing the cost of
service for an interrptible load is even more difficult, requiring considerable judgment." Order
No. 29157, p. 12.
As the paries have acknowledged in their testimony, the Commission has not
previously settled upon a definitive methodology for valuing Monsanto's interrptible service.
Tr. p. 2833. Indeed, in our Order adopting the settlement reached by the paries following
RMP's last general rate case, PAC-E-07-05, we wrote: "The curtailment valuation for Monsanto
ORDER NO. 32196 55
is based on a 'black box' determination with no party accepting a specific methodology for
setting this valuation." Order No. 30482, p. 8.
The Commission finds that the ability to curail Monsanto load, one of PacifiCorp's
largest, provides a direct benefit to PacifiCorp's system as a whole. Similarly, we find that while
PacifiCorp might replace the interrptible services currently purchased from Monsanto using its
other existing resources in the short term, the long-term costs to the system would be higher.
PacifiCorp's 2008 IRP recognizes Monsanto interrptibility as a firm capacity resource. If it
were not recognized in such a maner, the Company would have significantly larger capacity
deficits in 2011,2012 and 2013. Tr. p. 2841.
Consequently, we find that the value of Monsanto interrptibilty must consist of
forecasted energy prices and, where appropriate, the capital cost of capacity. Our decision
regarding the valuation of each interrptible product is set out below.
A. Non-Spinning Reserve Product
The Commission finds that the Non-spinning Operating Reserve product has energy
and capacity value. The Commission believes that the energy value is most accurately
established using the average of the GRID and Front Office Model rus as proposed by the
Company and supported by Staff. The Commission finds this value to be _ per year.
The Commission finds the capacity value of Non-spinning Operating Reserve to be
$9.3 milion per year. The capacity value was the subject of a considerable difference of opinion
among the paries. The Company's position was that its market valuation using the GRID and
FO models captured implied capacity values along with the energy value. Therefore, the
Company proposed no additional capacity value. The Commission believes that Monsanto's
interrptibilty is a long-term resource and that any implied capacity values included in market
prices are not nearly enough. Monsanto proposed a long-term view that capacity values be
established based on the averaged costs of two new SCCT's from the Company's 2008 IRP. The
two units were an Aero-Derivative unit and a Frame unit. Staff proposed that the capacity value
be based on the cost of an existing unit because analysis indicated that no new resources were
needed at this time to supply these reserves. Staff proposed that the Currant Creek CCCT plant
be used as a surrogate to represent the capacity value of all resources held over the course of a
year for Non-spinning Operating Reserves.
ORDER NO. 32196 56
The Commission elects to average the capacity costs of Currant Creek and the Aero-
derivative unit proposed by Monsanto (excluding increased planning reserves). The Commission
finds that this value properly blends the current condition with the longer term capacity view that
corresponds with Monsanto's demonstrated long-term interrptible commitment. The
Commission notes that Non-spinning Operating Reserves must be held at all times and,
therefore, has not chosen to reduce the value of its chosen resources by the percent of time any
one resource is held for reserve purposes.
This approach is also consistent with our desire and expectation that the parties will
execute a five-year contract as opposed to the three contracts that have been the norm for the
paries in the recent past. In addition to promoting greater price certainty and stability for
Monsanto, a large industrial customer and employer in southeast Idaho, it would also allow the
Company to plan more effectively into the future. Therefore, the Commission finds that an
extended contract period would serve the public interest.
B. Economic Curtailment Product
The Commission finds that the value proposed by RMP, _, and accepted
by Staff is fair, just and reasonable. See Attachment C. The Commission is persuaded that this
value is best established in the energy markets. The differences in GRID and FO Model runs,
with and without Monsanto Economic Curailment, fairly estimate this value. The fact that
Monsanto can and often does buy through Economic Curtailment at market prices supports this
valuation. The Commission does not believe that an additional capacity value as proposed by
Monsanto, and opposed by RMP and Staff, is appropriate.
C. System Integrity Product
The Commission finds the value of Monsanto interrptibilty to maintain system
integrity to be _. RMP and Staff argued for $0.1 milion while Monsanto presented
values of $0.8 milion and $2.0 millon. Our finding of a value of $0.2 milion is a compromise
that blends our knowledge that all customers are subject to interrption to preserve system
integrity, without reimbursement, with an understanding that interrption of a single large load
customer like Monsanto in an emergency brings benefit to RMP and other customers. The
Commission has also considered the fact that this type of interrption is rare.
ORDER NO. 32196 57
V. OTHER ISSUES
A. Energy Cost Adjustment Mechanism
The base net power costs (NPC) we establish in this case for the Company's Idaho
Energy Cost Adjustment Mechanism (ECAM) is $1,023,706,616. The ECAM approved for
RMP in Idaho defers the difference between base net power costs set during a general rate case
and collected from customers in their retail rates and actual net power costs incurred by the
Company to serve its retail customers. The ECAM addresses only power cost expenses and does
not include any costs associated with fixed cost recovery (i.e., capital investment in rate base).
Case No. P AC-E-08-08 (ECAM methodology), Order No. 30904. Net power supply costs
represent a large part of the Company's total revenue requirement and are subject to a high
degree of volatilty largely outside of the Company's control. The ECAM rate is calculated
annually to credit or surcharge to customers the accumulated deferral balance (the difference
between the base NPC embedded in rates and actual system NPC).
B. Prudency of DSM Expenditures
RMP offers seven demand-side management (DSM) programs in Idaho as the least
cost alternative to the acquisition of supply-side resources. These programs encompass all major
customer class factors including residential and low-income, commercial, industrial, and
irrigation. Additionally, the Company contributes to the Northwest Energy Efficiency Allance
efforts to transform energy markets in the region. All of the costs associated with programs are
eligible for recovery through the Customer Effciency Service Rate Adjustment (Schedule 191)
tariff with the exception of the Irrigation Load Control Service Credits which are recovered
through base rates. Tr. pp. 2116, 2117.
RMP contends in this case that its DSM expenses and efforts for 2008 and 2009 were
prudently incurred. Tr. p. 2116. Annual expenditures for each program derived from the
Company's 2008 and 2009 DSM reports are shown below.
Program
Irrigation Load Control (includes paricipation credits)
Low-Income Weatherization
Refrigerator Recycling
Home Energy Savings
Energy FinAnswer
FinAnswer Express
Agricultural Energy Services
2008
Expenditures
$ 8,908,216
164,578
113,296
490,101
121,192
1,302,858
268,068
ORDER NO. 32196 58
2009
Expenditures
$11,140,894
197,819
108,126
593,564
358,426
263,904
807,238
Northwest Energy Effciency Alliance
Totals
317,339
$11.685.648
287,190
$13.757.163
Energy efficiency programs are evaluated using a cost and benefit analysis viewpoint
and cost-effectiveness calculations from four major perspectives. These perspectives include the
Paricipant, Ratepayer, Utility and Total Resource Cost. The results of each perspective are
expressed in several ways including a cost!enefit ratio and net present value of program impacts
over the lifecycle of the energy efficiency measures. Tr. p. 2118. Evaluation results are used to
refine pre-program estimates of cost-effectiveness from all perspectives and to find ways to
fuher improve programs as they mature. Tr. p. 2119.
On October 5, 2009, Commission Staff convened a workshop with RMP and other
utilities to fully vet the issues of DSM evaluations and cost-effectiveness expectations. The
result of the workshop was a Memorandum of Understanding (MOU) signed by all utilties
agreeing to formally evaluate all of their programs on regular multiple cycles and to report the
results of these evaluations in their anual DSM reports fied with the Commission. In exchange
for the utility commitments, Staff agreed that if the evaluation and reporting commitment are
fulfilled and if there is no evidence of imprudence, then, when requested by the utilties, Staff
would recommend that DSM expenditures be found prudent by the Commission. Tr. pp. 2119,
2120. Although RMP has not yet achieved all of the established goals as outlined in the MOU,
Staff is satisfied that the Company has made significant progress. Tr. p. 2120.
After review and verification of all available program results and the Company's
progress in satisfying MOU guidelines, Staff concludes that RMP's DSM programs and efforts
in 2008 and 2009 were generally prudent and cost-effective. Tr. p. 2120.
Commission Findings
The Commission recognizes the Company's DSM Memorandum of Understanding
commitments and its compliance efforts; accepts Staffs analysis of the Company's 2008 and
2009 DSM programs and related expenditures; finds the expenditures to be just, reasonable and
in the public interest; and finds the costs to be prudently incurred and appropriate for recovery in
the Company's Schedule 191 (Customer Efficiency Services Rate Adjustment) tariff.
C. Tax Issues
The Company and Staff discuss accounting changes related to the deductibility of
capital repairs for tax puroses and the normalization of income tax expense. We accept the
ORDER NO. 32196 59
proposal to establish a regulatory asset or liability account for changes in taxes associated with
the repair deductions. The IRS has yet to review the deductions, making it reasonable to track it.
We accept Staffs recommendation that interest received or charged not be included in the
regulatory accounts.
The Company also requests approval to move to full normalization treatment of
income taxes for puroses of setting rates. Staff supports this recommendation. We accept the
Company's recommendation to fully normalize the repairs deduction and all other temporar
book-tax differences, with the exception of the equity allowance for fuds used during
construction ("equity AFUDC").
D. Low-income Weatherization Assistance (LIWA)
Rocky Mountain Power's Low-Income Weatherization Program is set out in tariff
Schedule 21. The program is intended to increase conservation thereby reducing electricity
consumption in the homes of low-income residential customers. Weatherization services are
provided at no charge to eligible households.
In 2005, the Commission authorized an increase In Low-Income Weatherization
Assistance (LIW A) annual funding from $100,000 to $150,000 (Case No. PAC-E-05-0 1; Order
No. 29837). In 2007, tariff Schedule 21 was revised to expand the scope of allowed
weatherization measures (Case No. PAC-E-06-10). Pursuant to Stipulation in that case, allowed
conservation measures include all cost-effective measures approved by the U.S. Deparment of
Energy (DOE) with a "savings to investment ratio" (SIR) greater or equal to 1.0 for electrically-
heated homes. The paries also agreed to increase RMP's weatherization sharing percentage
from 50% to 75% of the total cost of the approved weatherization measures.
As par of the Stipulation in Case No. PAC-E-06-10, CAP AI agreed that it would not
intervene or otherwise participate in any future proceedings to modify Schedule 21 or other RMP
weatherization programs from April 1, 2007 to March 31, 2009. F or its part, RMP agreed to
conduct a study to determine the cost-effectiveness of its Weatherization Program after March
31, 2009, and to submit the results of its study to the Commission. RMP's overall anual
spending amount for Schedule 21 was to remain unchanged at $150,000. Reference Order No.
30239, Case No. PAC-E-06-10.
In this case, CAP AI requested an increase in annual LIW A funding from $150,000 to
$4.08 per residential customer (approximately $231,000) and proposed eliminating the 75%/25%
ORDER NO. 32196 60
matching requirement. Tr. pp. 1902, 1903, 1917. RMP's program requires 75% of each dollar
of LIWA come from a non-utilty source. RMP opposed any change stating that the Company's
weatherization cost-effectiveness study had not been completed and would not be completed and
evaluated until early 2011.
Commission Staff agrees that the funding for low-income services should be
increased and recommends an annual funding level of $300,000. Staff agrees that both
SEICAA (Southeastern Idaho Community Action Agency) and EICAP (Eastern Idaho
Community Action Parnership) maintain waiting lists of eligible clients needing weatherization
services. Tr. p. 2105. Of those eligible clients who have electric space heating and are served by
RMP, SEICAA identified 741 customers and EICAP identified 233 customers. In 2007, 52
homes were weatherized, while a total of 205 homes were weatherized in 2008 and 2009 due to
the availabilty of American Reinvestment and Recovery Act (ARR) funding. The expected
loss of ARR fuds in March 2011 wil decrease the ability of SEICAA and EICAP to leverage
utilty fuds with other sources.
It is clear to Staff that utility funding alone is unlikely to fully meet the need for low-
income weatherization services. Increasing the annual fuding level to $300,000, Staff contends,
will assist SEICAA and EICAP's efforts to sustain their existing capacity to weatherize homes
and will prevent the number of homes weatherized from declining to the pre-ARR levels of
about 50 homes per year.
Staff recommends that the current cap the Company wil pay on a home
weatherization project be increased from 75% to 85% of the installed costs for approved
measures. Staff notes that in Case No. PAC-E-06-1O, the Company argued that removing the
spending cap would reduce the number of homes weatherized and decrease the cost-effectiveness
of the program. This issue was to be addressed by the Company's impact evaluation study.
Staffs recommendation to increase the cap to 85% is consistent with Idaho Power's curent cap.
This change would increase the amount of RMP funds that would be available for each project.
Tr. p. 2107.
Commission Findings
Addressing the continued needs in RMP's Idaho service territory of the low-income
sector, we find that the record reflects there is a five-year backlog of homes that need and are
eligible for weatherization in Idaho. We find that RMP does not dispute the cost-effectiveness of
ORDER NO. 32196 61
its Schedule 21 weatherization program for low-income customers. We find it reasonable to
increase RMP's curent anual fuding level for low-income weatherization in this case from
$150,000 to $300,000 and increase the dollar amount ofRMP funds available for each individual
project from 75% to 85% of total eligible costs. The Company indicated that an impact
evaluation of the LIWA program would be completed by year-end 2010, and the results provided
to the Commission in early 2011. This study wil provide information that may be used to
propose furher changes to the program in the future.
E. Miscellaneous Consumer and Customer Service Issues
(1) Disconnect Policy
RMP engages in a practice when a customer account is terminated and a premises is
vacated of not physically disconnecting service until metered usage exceeds 1,000 kWh. To
reduce unbiled usage between tenants and avoid wasted energy, RMP is directed to change its
disconnect policy. RMP is directed to work with Staff to develop an acceptable protocol.
(2) Estimated Bils
RMP is directed to work with Commission Staff to devise a plan to reduce the
number of estimated bils that it currently generates.
(3) Tenant Notice
RMP is directed to follow through on its rate case commitment to send a postcard to
customers (tenants) when service is initiated by a customer's landlord.
(4) Rebillng Policy
RMP is directed to meet with Commission Staff to discuss the Company's rebillng
policy and explore any possibilties for improvements.
(5) Moratorium and Winter Payment Plan
RMP is directed to follow through on its rate case commitment to revise its brochure
on Moratorium and Winter Payment Plan to convey a more effective message to customers.
F. Miscellaneous Company Rebuttal Proposals
RMP in rebuttal recommends that "the Northwest Energy Effciency Allance
(NEEA) program for market transformation and the Agricultural Energy Saver Program be
discontinued in Idaho effective January 1, 2011." Tr. p. 597. The Company admits that the
Agricultural Energy Saver Program is cost-effective. Tr. p. 592.
ORDER NO. 32196 62
RMP in rebuttal proposes changes to the Irrigation Load Control Program to reduce
costs and increase effectiveness. Tr. pp. 595-597.
Commission Findings
The above changes proposed by RMP and the late timing of same in this case, we
find, preclude any meaningful opportunity for public notice and participation by interested
parties. The Company's proposals wil therefore not be considered in this case.
VI. INTERVENOR FUNDING
Intervenor funding is available pursuant to Idaho Code § 61-617 A and Commission
Rules of Procedure 161 through 165. Section 61-617 A(1) declares that it is the "policy of this
state to encourage participation at all stages of all proceedings before this Commission so that all
affected customers receive full and fair representation in those proceedings." The statutory cap
for intervenor funding that can be awarded in anyone case is $40,000. Idaho Code § 61-
617 A(2). Accordingly, the Commission may order any regulated utility with intrastate anual
revenues exceeding $3.5 milion to pay all or a portion of the costs of one or more paries for
legal fees, witness fees and reproduction costs not to exceed a total for all intervening parties
combined of $40,000.
Petitions for Intervenor Funding were filed by Community Action Parnership
Association of Idaho ($16,975.75), the Idaho Irrigation Pumpers Association ($86,855.32), and
Idaho Conservation League ($21,890).
Rule 162 of the Commission's Rules of Procedure provides the form and content
requirements for a petition for intervenor fuding. 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 utilty users or customers; and (7) a statement showing the class
of customer on whose behalf the intervenor appeared.
Community Action Partnership Association of Idaho (CAPAI)
ORDER NO. 32196 63
CAP AI is a non-profit corporation overseeing a number of agencies that assist with
issues related to the causes and conditions of poverty in Idaho. CAP AI receives funding from a
variety of sources, including governental. Its fuding sources are unpredictable and impose
conditions or limitations on the scope and nature of work eligible for funding. CAP AI contends
that even with intervenor funding, participation in this case constitutes a significant financial
hardship.
In this case, CAPAI addressed the funding level of the Company's Low-Income
Weatherization Assistance (LIWA) program, the funding eligibility limit for individual LIWA
projects and the Company's proposed rate design for residential customers.
Idaho Irrigation Pumpers Association, Inc. (IIPA; Irrigators)
IIP A is a non-profit corporation representing farm interests in southern and central
Idaho. The Irrigators rely solely upon dues and contributions voluntarily paid by members based
on acres irrigated or horsepower per pump. IIP A reports that member contributions have been
falling and attributes this to the current depressed economy, increased operation costs and threats
related to water right protection issues. IIP A contends that as a result of financial constraints its
paricipation in this case constitutes a financial hardship.
The Irrigators in this case addressed the Company's weather normalization process,
the energy allocation factor used to assign cost responsibilty to the Idaho jurisdiction, the
treatment of irrigation load control programs in the Company's jurisdictional allocation model,
the impact of the declining load in the load growth adjustment rate (LGAR) used in the
Company's Energy Cost Adjustment Mechanism (ECAM), the Company's cost of service study
for the irrigation class and the Company's proposed changes to the irrigation load control
program.
Idaho Conservation League (ICL)
ICL is a non-profit member organization working to protect Idaho's clean water,
clean air and wilderness. The organization advocates for public values and addresses energy
issues including energy effciency and renewable energy. The organization is funded by
charitable donations. In this proceeding ICL advanced a residential Schedule 1 three-tier rate
design and rate spread specifically intended to incentivize energy efficiency and conservation.
The organization also addressed irrgation load control and pollution control cost issues.
ORDER NO. 32196 64
Commission Findings
Submitted for Commission consideration are the Petitions for Intervenor Funding
filed by Community Action Partnership Association of Idaho ($16,975.75), the Idaho Irrigation
Pumpers Association, Inc. ($86,855.32), and the Idaho Conservation League ($21,890). The
Commission has reviewed the Petitions, the post-hearing brief of CAPAI, RMP's response, and
the record of proceedings including the testimony of Petitioners and Commission Staff.
Intervenor funding is available pursuant to Idaho Code § 61-617 A and Commission
Rules of Procedure 161-165. Rule 162 of the Commission's Rules of Procedure provides the
form and content requirements for a petition for intervenor funding.
Idaho Code § 61-617 A includes a statement of policy to encourage paricipation by
intervenors in Commission findings. The Commission determines an award for intervenor
fuding based on the following considerations:
(a) A finding that the participation of the intervenor has materially
contributed to the decision rendered by the Commission; and
(b) A finding that the costs of intervention are reasonable in amount and
would be a significant financial hardship for the intervenor; and
(c) The recommendation made by the intervenor differed materially from
the testimony and exhibits of the Commission Staff; and
(d) The testimony and paricipation of the intervenor addressed issues of
concern to the general body of users or consumers.
Idaho Code § 61-617A; IDAPA 31.01.01.165. We find that the Petitions for Intervenor Funding
fied by CAPAI, IIPA and ICL comport with the procedural and technical requirements set forth
in Rules 161-165 of the Commission's Rules of Procedure.
CAP AI is a non-profit corporation that regularly participates in RMP's rate cases. It
addresses tariff and program issues related to causes and conditions of poverty in Idaho. It is
important given the economic conditions that prevail in RMP's service territory for low-income
customers to have an effective advocate for their interests. The Company in reply brief at page 3
states "RMP did not propose any changes to LIW A and, therefore, did not have any burden to
address the existing low-income programs or tariffs."
CAPAI's request for intervenor fuding in this case is comprised of the following
elements: Attorney fees, $15,080; Expert Witness fees, $1,750; and $145.75 in office and
ORDER NO. 32196 65
postage for total itemized expenses of $16,975.75. We find that the Petition of CAPAI satisfies
the substantive findings we are required to make to justify an award. IDAPA 31.01.01. 165.01.a-
e. We make a small adjustment in authorized expenses and find it fair, just and reasonable to
approve funding for CAPAI in the amount of $16,400. In awarding nearly the full amount
requested, we find that the public is well served by such an award. We find that the costs for
CAP AI should be assessed for later recovery to the residential Schedule 1 and 36 customer
classes. We find the itemized costs of CAPAI to be reasonable and recognize that the cost of
CAP AI paricipatìng in these proceedings constitutes a significant financial hardship to the
organization. We find that CAPAI was professional and economical in the marshaling of its time
and efforts.
IIP A is a non-profit corporation representing farm interests and a regular paricipant
in RMP's rate cases. We appreciate the paricipation of the Irrigators in this case and recognize
their contribution to the ultimate resolution of issues. The Irrigators have submitted an
accounting of costs totaling $86,855.32 comprised of Attorney fees, $22,644; Expert Witness
fess, $60,625; and $3,586.32 in offce, lodging, postage, transportation and meals. IIPA claims
entitlement to an award of costs in the maximum amount allowable. We provide no comment as
to the overall reasonableness of the submitted accounting by IIP A. As the Irrigators recognize,
we are limited in the amount we can award.
ICL is a non-profit corporation addressing energy, conservation and environmental
issues. We appreciate their participation. In this case, ICL has requested $21,890 in intervenor
funding comprised of$13,460 in Expert Witness fees and $8,430 in Attorney fees.
We find that the Petitions ofIIPA and ICL satisfy the substantive findings that we are
required to make to justify an award. IDAPA 31.01.01.165.01.a-e. We find that the
paricipation and presentation of each, as reflected in their respective testimonies materially
contributed to the Commission's decision. Both add informed perspectives to the hearing record.
We find that the recommendations and perspectives of each differed materially from the
testimony and exhibits of Commission Staff and contributed to our decision. We find it fair, just
and reasonable to split the remaining amount of available intervenor fuding between IIP A and
ICL, and award $11,300 to each. We find that the costs for IIPA should be assessed for later
recovery to the Company's irrigation class; and that the cost for ICL be assessed to the
residential Schedule 1 and 36 customer classes.
ORDER NO. 32196 66
The Commission finds that the intervenor funding awards to CAP AI, IIP A and ICL
are fair, just and reasonable and will further the purpose of encouraging "paricipation at all
stages of all proceedings before the commission so that all affected customers receive full and
fair representation in those proceedings." Idaho Code § 61-617 A(1).
CONCLUSIONS OF LAW
The Idaho Public Utilties Commission has jursdiction over PacifiCorp dba Rocky
Mountain Power, an electric utilty, its Application in Case No. PAC-E-1O-07 and over the issues
raised in these proceedings pursuant to Idaho Code, Title 61, and the Commission's Rules of
Procedure, ID AP A 31. 01. 01. 000 et seq.
ORDER
In consideration of the foregoing and as more paricularly described above, IT is
HEREBY ORDERED that the tariffs fied in conformance with Interlocutory Order No. 32151
(with Errata) and approved by Minute Order dated December 28, 2010, for effective date
December 28, 2010 and January 1, 2011 (Schedules 400 (Monsanto) and 401 (Agrium)) are
reaffrmed and authorized for continued service. For Monsanto the Schedule 400 interrptible
credit (as more paricularly described above and detailed in Attachment C) is changed to .
_ for an effective date March 1, 2011. Rocky Mountain Power is directed to file a
conforming Schedule 400 tariff to be effective on March 1, 2011 for service rendered on and
after that date. The authorized rates are set forth in Attachment A.
IT is FURTHER ORDERED and Rocky Mountain Power is directed to increase its
annual funding level for Schedule 21 low-income weatherization assistance in Idaho to $300,000
and increase the dollar amount of RMP funds available for each individual project from 75% to
85% of total eligible costs.
IT IS FURTHER ORDERED that the Commission provides the foregoing guidance
regarding the valuation of Monsanto's interrptible products. In order to assist the paries in
preparing a new Energy Sales Agreement (ESA), the Commission establishes a total interrptible
product value of and shows the components and some of the calculations in
Attachment C. Furher, the Commission expects the paries to craft an agreement that establishes
a value for Monsanto's interrptible products that extends for a period of five years.
IT IS FURTHER ORDERED and the Petitions for Intervenor Funding are parially
granted in the amounts of $16,400, Community Action Parnership Association of Idaho;
ORDER NO. 32196 67
$11,300, Idaho Conservation League; and $11,300, Idaho Irrigation Pumpers Association, Inc.
Reference Idaho Code § 61-617 A. Our Interlocutory Order No. 32151 and direction to the
Company in this regard is reaffrmed.
Rocky Mountain Power shall include the cost of the awards of intervenor fuding to
CAPAI and ICL as an expense to be recovered in the Company's next general rate case from the
residential customer class. Idaho Code § 61-617 A(3).
Rocky Mountain Power shall include the cost of the award of intervenor fuding to
IIPA as an expense to be recovered in the Company's next general rate case from the irrigation
customer class. Idaho Code § 61-617A(3).
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 Utilties Commission at Boise, Idaho this ;ig#l
day of February 2011.
~L1~
MARSHA H. SMITH, COMMISSIONER
~~-
ATTEST:
~~ommission Secretar
blslN:PAC-E- 10-07 _swl I_final_Confidential
ORDER NO. 32196 68
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ATTACHMENT C