20151223final_order_no_33440.pdf

Office of the Secretary
Service Date
December 23,2015
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF PACIFICORP DBA )
ROCKY MOUNTAIN POWER’S )CASE NO.PAC-E-15-09
APPLICATION TO MODIFY THE ENERGY )
COST ADJUSTMENT MECHANISM AND )ORDER NO.33440
INCREASE RATES )
On May 27,2015,PacifiCorp dba Rocky Mountain Power (“Rocky Mountain”or
“Company”)submitted an Application seeking a Commission Order authorizing the Company
to:(1)increase its electric rates by $10.2 million,or 3.9%on average,effective January 1,2016;
and (2)modify the annual Energy Cost Adjustment Mechanism (“ECAM”).The ECAM is
designed to annually adjust Rocky Mountain’s rates upward or downward to reflect the
difference between the Company’s actual power supply costs and those power costs embedded in
base rates.Order No.32216 at 1.On June 11,2015,the Commission issued an Order granting
Petitions to Intervene filed by Monsanto Company (“Monsanto”)and PacifiCorp Idaho Industrial
Customers (“PIIC”).See Order No.33321.
On July 15,2015,the Commission issued a Notice of Modified Procedure,Notice of
Schedule and Settlement Conference.See Order No.33339.The settlement conference was
held on August 11,2015,and was attended by representatives of the Company,Commission
Staff,Monsanto and PIIC (hereafter collectively referred to as “the Parties”).Subsequently,the
Parties agreed in principle to a Settlement Agreement (“Stipulation”or “Settlement”).
On October 15,2015,after several months of mutual negotiation between the Parties,
the Company filed a copy of the executed Stipulation with the Commission.The Settlement
terms include an overall base rate increase of 3.9%with a “stay-out”provision prohibiting the
Company from making any additional base rate changes prior to January 1,2018.
On October 27,2015,the Commission issued a Notice of Proposed Settlement
Stipulation requesting comments on the Settlement.Staff and the Company submitted timely
written comments in support of the Stipulation.Additionally,Snake River Alliance (“SRA”)
submitted a letter expressing its support of the Settlement.In this Order we approve the
Settlement.
ORDER NO.33440 1
THE APPLICATION
A.Net Power Costs (NPC)Update
Rocky Mountain’s current base net power costs (NPC)were established in a general
rate case in 2011,based on 2010 loads.According to the Company,all of the NPC components
have changed,thereby increasing the annual NPC by $129 million.
Rocky Mountain asserted that it is more appropriate for these ongoing and permanent
power costs to be recovered in base rates rather than through the ECAM.Consequently,the
Company proposed to update the level of base NPC consistent with the level reported in the
Company’s Annual Report.The Company insisted that its current base NPC are $1,514 million,
or $93.8 million on an Idaho-allocated basis.This compares to $87.6 million on an Idaho-
allocated basis based upon the 2011 general rate case.In other words,the Company maintained
that the Idaho base NPC should be increased by at least $6.2 million.By updating base NPC and
allowing that level of expense to be included in base rates beginning January 1,2016,Rocky
Mountain argued that the ECAM will be better aligned to track annual fluctuations in NPC rather
than long-term recovery of NPC currently being collected through the annual ECAM surcharges.
The Company stated that its proposed base rate increase of approximately $10.2
million is derived from:(a)$2.8 million associated with updating base system NPC from $1,385
million to $1,514 million total company (or $93.8 million on an Idaho-allocated basis);(b)$6.5
million for renewable energy credits (“RECs”);(c)$0.2 million for renewable energy production
tax credits (“PTCs”);and (d)$0.7 million for the incremental amortization of the unrecovered
investment (depreciation and depletion expense)in the Deer Creek Mine as requested by the
Company in Case No.PAC-E-14-10 (“Deer Creek Mine Case”).
B.Originally Proposed Modfications to the ECAM
Rocky Mountain initially proposed to make the following modifications to the current
ECAM:(1)eliminate the 90/10%sharing band and allow for 100%recovery of prudently
incurred NPC;(2)update the ECAM methodology to reflect retail sales at meter,to eliminate the
need for Staffs base rate over-collection adjustment;(3)eliminate the LCAR;(4)no longer track
DSM costs and S02 sales in the ECAM;(5)include renewable energy production tax credits
(“PTC5”)in the ECAM and treat similar to NPC;(6)include a temporary adder in the ECAM
until the amortization of the Deer Creek Mine unrecovered investment is included in base rates;
ORDER NO.33440 2
and (7)change the deferral period to correspond with the calendar year,and change the filing
date to April 1 with rates effective June 1.
Rocky Mountain proposed to eliminate the 90/10 sharing band in the ECAM because
it already proactively manages NPC.The Company believes that the sharing band is not an
appropriate incentive because the Company has little to no control over the volatility and
unpredictable nature of these costs.The Company believes that it has historically been penalized
by the sharing band because the sharing bands and dead bands have been eliminated in almost all
other states.
The Company proposed to add the incremental Deer Creek Mine depreciation
expense that was collected through the ECAM into base rates with no sharing.This proposal is
consistent with the Company’s request in the Deer Creek Mine Case (PAC-E-14-10).It would
allow the Company to continue to collect depreciation expense related to the Deer Creek Mine
through its remaining depreciable life.
Rocky Mountain also argued that its resource mix has changed since the approval of
its last ECAM in Case No.PAC-E-14-01.See Order No.3300$at 15.The Company has
become increasingly reliant on short-term market purchases due to more intermittent energy
from the addition of QFs on the Company’s system and other owned and contracted generation
that serve its load,exposing the Company to the market and increased NPC volatility.
Intermittent energy is highly dependent on the weather,which is entirely out of the Company’s
control,making NPC more unpredictable.
The Company believes that its new hedging policy also supports modifications to the
ECAM.The Company updated its hedging policy:(1)by incorporating guidelines that allow a
reasonable percentage of natural gas and power requirements to remain open to short-term
market price exposure and (2)for operational flexibility.
Rocky Mountain proposed to change the ECAM’s differential calculation method so
that it is based on retail sales at the meter,eliminating the need for the method developed by
Staff,known as the “base rate over-collection adjustment.”The Company also proposed to
eliminate tracking the LCAR,S02 sales,irrigation load control and DSM costs from the ECAM.
The LCAR should be eliminated because it is asymmetrical in that it only considers changes in
loads (or sales going forward)but ignores changes in the actual underlying costs.Irrigation load
control and DSM costs were included in the ECAM as stipulated in the 2011 general rate case
ORDER NO.33440 3
due to the uncertainty of the jurisdictional treatment of the irrigation load control program by the
Multi-State Protocol (“MSP”)committee.MSP now dictates that DSM costs are situs assigned,
thus eliminating the need to track these cost in the ECAM.The Company said that it has
modified the DSM program to make it more cost-effective and aligned with the benefits
received.The DSM program cost should not be part of the ECAM.
Rocky Mountain believes that revenues from S02 sales have become immaterial and
irrelevant,citing that the 2015 ECAM Idaho SO2 sales amounted to a $71 credit to customers.
The Company proposed tracking renewable energy production tax credits in the ECAM because
the credits are directly tied to the energy production of the qualifying renewable generation
facilities,which can vary significantly from year to year.
The Company proposed to change the ECAM deferral period to coincide with the
calendar year (January to December)as opposed to the current December through November
deferral period.The Company believes this change and the filing date change will make the
ECAM easier to audit and align the deferral period with that used in all the other PacifiCorp
jurisdictions.
C.Miscellaneous
Rocky Mountain stated that it provided notice of its Application to its customers
through the issuance of a press release sent to local media organizations and bill inserts included
in customer bills beginning in June.Copies of the Application were provided to many of the
Company’s major customer representatives.In accordance with Rule 121(e),(f),and (g),Rocky
Mountain represented that the Application,testimony,exhibits and workpapers support the costs
the Company seeks to recover.
SETTLEMENT STIPULATION
After engaging in lengthy and comprehensive negotiations,the Parties reached an
agreement to resolve all of the outstanding issues in the case.The following is a summary of the
relevant terms of their Stipulation filed with the Commission on October 15,2015.See Order
No.33403.
1.The Parties agree that Idaho retail revenues should increase by $10.2
million (3.9%)effective January 1,2016.The Parties further agree this
increase will apply to all rate schedules as set forth in Exhibits 4 and 6.
2.The Parties agree that the $10.2 million increase above current base rates
will consist of:(a)a $3.2 million increase after removing Deer Creek
ORDER NO.33440 4
depreciationldepletion expense from NPC currently approved in base
rates,with Idaho base energy at meter of 3,483,480 megawatt hours,or
$27.21 per megawatt-hour;(b)a $6.5 million increase associated with a
reduction of the revenue credit from the sale of RECs;(c)a $0.2 million
change in tax affected production tax credits (“PTCs”);and (d)$0.3
million incremental increase in exchange for the Company agreeing not to
file a general rate case with rates effective prior to January 1,2018.
3.Base rates and base NPC should be updated effective January 1,2017.
The updated base NPC will be the amount reported in the 2015 annual
results of operations report,after appropriate pro forma adjustments.For
the rate spread and rate design of the update to base rates,the Company
will use an equal cents per kWh approach.Rocky Mountain Power will
file an application no later than September 1,2016.
4.Base rates established by this Stipulation will,in conjunction with the
ECAM,result in reasonable rates for the period January 1,2016 through
December 31,2017 (the “Stay-out Period”).During the Stay-out Period
the Parties will not request the establishment of new regulatory assets or
liabilities,which have not been previously approved by the Commission,
except under unique or unforeseen circumstances.Unforeseen
circumstances include natural disasters or emergencies.
5.The current ECAM will be modified for deferrals on and after January 1,
2016,to reflect that the ECAM will be measured on a dollar per
megawatt-hour basis using load at the meter rather than the load at the
generator.
6.The entire amortization expense associated with the unrecovered Deer
Creek mine investment will be recovered through the ECAM as a separate
line item,without application of the sharing band,until fully amortized.
7.The Customer/Company sharing band will remain at 90/10%respectively
for all ECAM components with the exception of:PTCs,amortization of
the unrecovered Deer Creek mine investment,RECs and the Lake Side 2
resource adder.
8.The load change adjustment rate (“LCAR”)will be updated to reflect base
loads (at sales)corresponding to the period used to set base rates.The
2016 LCAR is summarized in the following table:
ORDER NO.33440 5
LOAD CHANGE ADJUSTMENT RATE CALCULATION
PAC-E-10-07 PAC-E-15-09
Description Current Amount Update Amount
1.Production -Return on Investment $33,083,414 833,083,414
2.Production -Expense 2,173,162,370 2,173,162,370
3.Production -NPC Expenses
Production Revenue (1,748,001,871)(1,748,001,871)
4.Requirement (Excluding NPC)1,258,243,913 1,258,243,913
5.System Load 57,460,901 57,460,901
6.Production $per MWH 21.90 20.89
7.Energy %(Demand &Energy)25%25%
8.5.47 5.22
9.
10.Idaho Energy @ Input 3,691,675 3,786,584
1 1.Idaho Production RR 20,193,462 19,776,001
12.Idaho Energy Meter 3,328,058 3,483,480
13.LCAR Meter 6.07 5.68
9.Effective January 1,2016,S02 revenues and demand side management
costs will no longer be tracked in the ECAM.
10.The 2016 ECAM Deferral Period will include 13 months (December 1,
2015 to December 31,2016),and all subsequent ECAM filings will be
based on calendar year deferrals.The Company’s ECAM applications
will be filed annually on April 1,with a rate effective date of June 1.
11.The Company and Monsanto agree to extend the current terms of the
existing Electric Service Agreement governing curtailment products and
payments through December 31,2017.
Finally,the Stipulation acknowledges that the obligations of the Parties are subject to
the Commission’s approval of the terms and conditions of the Stipulation and,if any judicial
review is sought,upon such approval being upheld on appeal by a court of competent
jurisdiction.
STAFF COMMENTS
Staff reviewed the Application,workpapers,results of operations,Idaho ECAM
filings and net power supply expense (NPSE)adjustment filings in other jurisdictions to establish
a position in this case.Staff believes that the Stipulation represents a reasonable compromise of
NPSE recovery issues resulting in limited customer impact and rate stability through January 1,
201$.
ORDER NO.33440 6
Staff remarked that the Stipulation addresses a variety of power supply expense issues
and how they are recovered by the Company through rates.A summary of the Parties’
Stipulation precedes this section and will not be included here.However,Staff noted that the
elimination of the load change adj ustment (LCAR)and ECAM sharing percentages,proposed by
the Company in its Application,were not accepted nor included in the Stipulation.
Staff explained that the expenses addressed in the Stipulation are all part of net power
supply expense (NPSE)subject to either ECAM recovery,base rate recovery or a combination of
the two.The vast majority of the base rate increase proposed in this Stipulation is due to shifting
NPSE currently recovered through the ECAM to base rate recovery at 100%.As NPSE in base
rates increase,customers will pay more costs upfront and fewer costs through the ECAM later.
1.Base Rates.The source of the base rate increase contemplated in the Stipulation
breaks down into two sets of costs:(1)a $3157 million increase in net power cost (NPC)subject
to 90/10 customer sharing;and (2)an increase of $7.023 million in NPSE (defined as all costs
and revenues tracked through the ECAM)not subject to sharing.
The $3157 million NPC base rate increase is actually the net of several different
expense changes,including:(1)a $2.88 million increase in general power supply expenses;(2)
shifting $684,000 in Deer Creek Mine depreciation from base rate recovery to 100%ECAM
recovery;and (3)an additional $965,000 NPC base rate increase in exchange for a two-year rate
case stay-out.The actual customer impact of the $3.157 million NPC base rate change is
approximately $384,000 per year or the 10%sharing that would have occurred had the $3.84
million ($2.88 million and $965,000)been recovered through the ECAM.
The $7.023 million base NPSE increase not subject to sharing includes:(1)a
renewable energy credit (REC)reduction of approximately $6.5 million (this reduction is
currently tracked through the ECAM at 100%);(2)a $215,000 base rate increase for a PTC
decrease (not currently included in NPSE or tracked through the ECAM);and (3)an additional
$289,000 increase in exchange for the two-year stay-out.
Staff believes there is no customer impact from the NPSE base rate reduction in
RECs because this reduction is currently tracked through the ECAM at 100%.The PTC base
rate change of $215,000 reflects a reduction associated with generation at Company-owned
renewable facilities.The final base rate increase of $289,000 in non-power supply expense
results from a compromise between the Parties and is a cost of the stay-out provision.This base
ORDER NO.33440 7
rate increase does not otherwise track through the ECAM and is recoverable from customers at
100%.The combined net customer impact of all base rate changes is approximately $889,000
per year or about 0.34%more than what customers would pay through current base rates and the
ECAM.
2.ECAM.Staff supported several changes to the ECAM proposed in the
Stipulation.The first change is ECAM tracking and 100%recovery of approximately $1.3
million in annual Deer Creek Mine amortization expense.This provision removes $684,000 of
mine depreciation expense currently included in base rate NPSE and combines it with an
additional $617,000 in amortization expense to track through the ECAM until unrecovered Deer
Creek Mine capital costs are fully amortized in 2020.Staff noted that the Commission approved
full amortization of unrecovered Deer Creek Mine capital costs in Order No.33304 (PAC-E-14-
10).
Staff supported removal of DSM expense and S02 revenue tracking.S02 revenue
tracking has become very small over time and does not change significantly from year to year.
Staff believes these changes will not affect base rates and will have minimal effect on future
ECAM deferral balances.
Staff approved of PTC changes in actual NPSE tracked at 100%in the ECAM
deferral balance.Staff believes PTCs legitimately affect power supply expense from year to year
as energy generated from Company-owned renewable resources change.Staff analyses revealed
that significant reductions are expected to occur beginning in about 2018 as credits associated
with generation are eliminated.
Staff supported all of the ECAM modifications found in the Stipulation.According
to Staff the new deferral calculation methodology eliminates the need for the “Base-rate-Over
Collection Adjustments”that have been applied to the Company’s proposed deferrals and
approved by the Commission in the last two ECAM cases (Order No.33008 in PAC-E-14-0l;
Order No.33265 in PAC-E-15-01).When the adjustments approved by the Commission in the
prior cases are applied to the Company’s current deferral calculation methodology,it is
equivalent to the ECAM methodology changes proposed in this Stipulation.The proposed
changes effectively eliminate line-loss bias identified as a major source of inaccuracy in
determining the over or under recovery of ECAM related cost embedded in base rates;thus
ensuring that customers pay no more and no less than actual cost,minus sharing.The calendar
ORDER NO.33440 8
year ECAM period better aligns ECAM expense deferral with Company calendar year results of
operations.
3.Rate Spread and “Stay-Out”Provision.While the overall base revenue increase
will be approximately 3.9%,the revenue impact on each customer class will vary due to the
uniform increase of 0.292 cents-per-kWh applied to all energy used within the class.The table
below shows the increase in revenue for each class and the corresponding percentage:
Customer Class Present Proposed Change ($)Change (%)
Revenue Revenue
Total Residential (Sched.I &36)$70,109 $72,090 $1,981 2.8%
Large General Service (Sched.6 &6A)$25,308 $26,283 $975 3.9%
Irrigation (Sched.10)$52,555 $54,316 $1,761 3.4%
General Service (Sched.23 &23A)$17,742 $18,289 $547 3.1%
Special Contract 1 $82,747 $86,967 $4,220 5.1%
Special Contract 2 $5,950 $6,264 $314 5.3%
Total (All Classes)S263,3 15 $273,496 $10,181 3.9%
(Revenue shown in S 1,000’s)
While customers will see an increase in base rates on January 1,2016,they will see
an almost equal reduction in the ECAM in 2017.Given that the base rate increase primarily
recovers variable energy costs that would otherwise be recovered through the ECAM on an equal
cents-per-kWh basis,Staff believes it is reasonable to increase base rates on an equal cents-per
kWh basis.Beyond the base rate increase proposed to take effect on January 1,2016,the
Stipulation provides for a review of actual 2015 power supply expenses and an additional base
rate NPC adjustment effective January 1,2017,if necessary.Again,any NPC paid by customers
through base rates,will not be subject to recovery through the ECAM.
Staff pointed out that it is also possible that a review of 2015 power supply expenses
could result in a decrease in base rate NPC.Regardless,Staff believes it is reasonable for
purposes of settlement in this case to update base rate NPC during the stay-out period.Staff
fully supported the stay-out provision and believes it will result in lower rates than would
otherwise occur and provide relative rate stability for the next two years.
ROCKY MOUNTAIN COMMENTS
Rocky Mountain asserted that the Stipulation represents a compromise of the Parties
positions,provides significant customer benefits and will result in fair,just,and reasonable rates
for Idaho customers.If the Commission approves the proposed Stipulation,Rocky Mountain
stated that the average residential customer using 800 kWh per month would see their bill
ORDER NO.33440 9
increase by $2.35 per month in 2016,followed by an undetermined decrease in their ECAM
surcharge in 2017 due to a higher level of NPC recovery in base rates during 2016.Finally,the
Company also acknowledged that it has agreed with Monsanto to extend the current terms of
their existing Electric Service Agreement governing curtailment products and payments through
December 31,2017.
SRA COMMENTS
On November 6,2015,SRA submitted a letter in support of the Parties’proposed
Stipulation.SRA stated that despite not being a party to this case,it has reviewed the documents
filed,including the Stipulation.SRA appreciates that the Parties were able to reach a Settlement
that the SRA believes is in the best interest of Rocky Mountain’s customers.SRA supported the
Stipulation.
SRA supported allowing the utility to recover ongoing and permanent power costs
through base rates rather than through the ECAM.SRA believes that,while there will be a
ratepayer impact should the Commission approve the Stipulation,the projected increase of $2.35
a month for the average Rocky Mountain residential ratepayer is almost certainly far lower than
a possible rate increase that could occur should this case be fully litigated as a general rate case.
SRA also appreciated that the Parties agreed to a two-year Rocky Mountain “stay-
out”that will forestall the next base rate increase to no sooner than January 1,2018.SRA
believes that avoiding the need to litigate a rate case is almost always in the best interest of all
parties and customers.The amount proposed to be shifted into permanent base rates,while not
insignificant,is reasonable.SRA noted that of the $10.2 million currently collected through
Rocky Mountain’s annual ECAM,$6.5 million is attributed to revenues from the trading of
renewable energy credits (RECs)that the Company will no longer realize.
SRA also supported terms of the Stipulation that spread the amount across all rate
schedules.SRA appreciated the Company’s willingness to “file an application...no later than
September 1,2016,”to incorporate several changes.Finally,SRA supported the decision to
remove revenues from S02 allowance sales from the ECAM.SRA expressed its appreciation
for the opportunity to comment on PAC-E-15-09,and recommended that the Commission
approve the proposed Stipulation.
ORDER NO.33440 10
MISCELLANEOUS PUBLIC COMMENTS
The Commission only received one public comment regarding the Company’s initial
Application.This commenter asked the Commission to deny Rocky Mountain’s proposed
modification to the ECAM.There were no comments addressing the proposed Settlement.
COMMISSION FINDINGS AND DECISION
The Commission has conducted a thorough review of Rocky Mountain’s Application,
attached exhibits,the Stipulation,Parties’comments in support of the Stipulation,and the two
public comments filed in this case.Preliminarily,the Commission notes that it is not bound by
the Stipulation reached by the Parties.When a settlement is presented to the Commission,the
Commission will determine the procedures appropriate to review the settlement.In this case,the
Commission issued a Notice of the Proposed Settlement and invited public comment.The
parties in support of a settlement carry the burden of showing that the settlement is reasonable,in
the public interest or otherwise in accordance with regulatory policy.Rule 275,IDAPA
31.01.01.275.The Commission “will independently review any settlement proposed to it to
determine whether the settlement is just,fair and reasonable,in the public interest,or otherwise
in accordance with law or regulatory policy.”Rule 276,IDAPA 31.01.01.276.
The Commission acknowledges and commends the Parties for their efforts in
reaching a settlement of the ECAM cost recovery issues presented in this case.Pursuant to the
Commission’s authority under Idaho Code §6 1-502 to determine ‘just,reasonable,or sufficient
rates,”the Commission approves the Parties’Stipulation.The Commission finds that the
Stipulation pertaining to Rocky Mountain’s request to increase rates,effective January 1,2016,
and modify certain provisions of the Company’s annual ECAM is fair,just and reasonable.
Idaho Code §61-622.
The Stipulation includes necessary updates in the Company’s base NPC and helpful
revisions to the current ECAM process.The Commission also finds that the Stipulation
represents a reasonable compromise of the various positions,concerns,and issues raised by the
Parties.The hallmark of reasonable compromise is a mutually beneficial resolution for both
sides of a transaction.Accordingly,the Commission finds that the Stipulation offers substantive
benefits to both ratepayers and the Company.
The Commission believes that the monthly increase in electric rates,2.8%for
residential customers and a 3.9%average increase for all customers,allows the Company a fair
ORDERNO.33440 11
and reasonable recovery of its established annual energy costs.Moreover,the “stay-out”
provision of the Stipulation provides rate stability by mitigating the potential for more significant
increases through the end of the 2017 calendar year.More importantly,the increase in base rates
for 2016 will later be accompanied by a roughly commensurate decrease in the annual ECAM
paid by customers in 2017.We find these terms in the public interest.Therefore,the Parties’
Stipulation is approved by the Commission without change or condition.
ORDER
IT IS HEREBY ORDERED that the Commission approves the terms and conditions
of the Parties’Settlement Stipulation as discussed in greater detail above.Modifying the current
ECAM process will increase the Company’s Idaho retail revenues by $10.2 million (applying to
all Idaho customer rate schedules)and become effective on January 1,2016.
IT IS FURTHER ORDERED that the new electric service schedules and tariffs
previously submitted by the Company on May 27,2015,are approved.
THIS IS A FINAL ORDER.Any person interested in this Order may petition for
reconsideration within twenty-one (21)days of the service date of this Order.Within seven (7)
days after any person has petitioned for reconsideration,any other person may cross-petition for
reconsideration.See Idaho Code §6 1-626.
ORDER NO.33440 12
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this bZ
day of December 2015.
PAUL KJELLAN ,PRESIDENT -
MARSHA H.SMITH,COMMISSIONER
KRI [NE RAPER,COMI’IIIS$IONER
ATTEST:
D.Jewell QC’mmission Secretary
O:PAC-E-1 5-09_np4_Final
ORDERNO.33440 13