20180615PacifiCorp Final Report.pdf

Y ROCKY MOUNTAIN
BP,Iy,E^.R"-.
June 15,2018
VA OVERNIGHT DELIVERY
RECEIVED
?$18 JUi{ l5 ltt 9: l9
ii),\HU I-USLIC
.il il :l lr:ii CO}JMISSION
Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472 W. Washington
Boise, lD 83702
Re:CASE NO. GNR-U.18.01
INVESTIGATION INTO THE IMPACT OF FEDERAL TAX CODE REVISIONS
ON UTILITY COSTS AND RATEMAKING
Dear Ms. Hanian:
Please find enclosed an original and seven (7) copies of Rocky Mountain Power's Final Report
in the above referenced matter. Enclosed is a CD containing the non-confidential work papers.
Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at (801) 220-
2963.
Very truly yours,
Pre
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
CERTIFICATE OF SERVICE
I hereby certify that on this l5th of June, 2018, I caused to be served via e-mail a true and
correct copy of Rocky Mountain Power's Final Report in Case No. GNR-U-18-01 to the
following:
Service List
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
505 Pershing Ave., Ste. 100
P.O. Box 6119
Pocatello, Idaho 83205
E-mail: [e-mail]
Anthony Yankel
12700 Lake Avenue, Unit 2505
Lakewood, Ohio 44107
E-mail: [e-mail]
MONSANTO COMPANY
Randall C. Budge
Racine, Olson, Nye & Budge, Chartered
P.O. Box 1391;201 E. Center
Pocatello, Idaho 83204- 1 39 I
E-mail : [e-mail]
[e-mail]
Brubaker & Associates
16690 Swingley Ridge Rd., #140
Chesterfield, MO 63017
E-mail : [e-mail]
[e-mail]
Katie Iverson
Brubaker & Associates
19540 N. Wessex Dr.
Surprise, AZ 85387
kiverson@consultbai. com
PIIC
Ronald L. Williams
Williams Bradbury, P.C.
P.O. Box 388
Boise ID, 83701
E-mail : [e-mail]
Jim Duke
Idahoan Foods
E-mail: [e-mail]
Kyle Williams
BYU Idaho
E-mail : [e-mail]
Val Steiner
Nu-West Industries, Inc.
E-mail : [e-mail]
Bradley Mullins
1750 SW Harbor Way, Suite 450
Portland, OR 97201
E-mail : [e-mail]
Page 1 of2
PACIFICORP, DBA ROCKY MOUNTAIN POWER
Ted Weston
PacifiCorp, dba Rocky Mountain Power
1407 West North Temple
Suite 330
Salt Lake City, uT 841l6
E-mail : ted.weston@oacifi corp.com
Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OFt97232
E-mail : datarequest@pacifi corp.com
Dated this l5th day of June,20l8.
Ve,.
Katie Savarin
Coordinator, Regulatory Operations
Page2 of2
Yvonne R. Hogle (#8930)
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Telephone: (801 ) 220-4050
Facsimile : (80 l) 220 -3299
Email : wonne.hoele@l'tacifi corp.com
f?ECEIVED
?018 JUri l5 AFI 9r 20
qtrF-. tt,nl l,-,"1i 1Lr l-iJDLlUl[:i C0[{MISSICN
Afforney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
INVESTIGATION INTO THE IMPACT
OF FEDERAL TAX CODE REYISIONS
ON UTILITY COSTS A}tD
RATEMAKING
CASE NO. GNR-U-18-01
FINAL REPORT
Rocky Mountain Power, a division of PacifiCorp ("Rocky Mountain Power" or "the
Company"), in accordance with Idaho Code $61-502, $61-503, and RP 052, respectfully submits
this final report ("Final Report") to the Idaho Public Utilities Commission ("Commission")
pursuant to a) Order No. 33965 through which the Commission initiated an investigation into the
impact of the federal income tax legislation enacted December 22,2017, titled An Act to Provide
for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution of the Budget for Fiscal
Year 2018 ("Tax Reform Act"), and b) the all-party agreement ("Stipulation") filed in this docket
with the Commission May I 1, 2018, and approved by Order No. 34072.
This Final Report complies with paragraph 14 of the Stipulation which requires the
Company to provide a final report of the Tax Reform Act's net savings, including the calculation
of excess deferred federal income taxes associated with both protected and unprotected defened
tax balances. In accordance with the Stipulation, the Company must provide a reconciliation of the
treatment of the benefits from the Tax Reform Act, including a true-up of any under- or over-
allocation of customer credits.
The Company's initial report and the Stipulation in this docket has resulted in a rate
1
reduction of $8.385 million, or approximately 3 percent, beginning June l, 2018. Specifically, the
Company reduced rates by $6.185 million through Electric Service Schedule No. 197 - Federal
Tax Act Adjustment, which will be in effect until the tax savings are included in base rates in the
next general rate case, and by $2.2 million through Schedule No. 97 - Energy Cost Adjustment
Rate, enabled by a one-time credit of $3.4 million applied as an offset to the 2013 incremental
depreciation regulatory asset balance.
PROCEDURAL BACKGROUND
On or about December 22, 2017, Congress enacted the Tax Reform Act effective
January 1,2018. In response, the Commission initiated this investigationl into the impact of the
federal tax code revisions on utilities'costs and ratemaking. On March 30,2018, in compliance
with Order No. 33965, the Company filed an application ("Report") proposing immediate deferral
of all savings associated with the Tax Reform Act and authorization to decrease rates by
$2.8 million effective June 1,2018.
With the intent of resolving the issues raised by parties as a result of the Company's
proposal in the Report, the parties met on April 30,2018 for settlement discussions, which led to
execution of the Stipulation that was approved by the Commission May 31,2018, pursuant to
Order No. 34072.
Consistent with the Stipulation, the Company provides this Final Report of the Tax Reform
Act's net savings, and a reconciliation of the accounting for the benefits from the Tax Reform Act.
The Final Report gives parties an opportunity to review the Tax Reform Act balance that remains
after accounting for the ongoing $6.185 million reduction to rates and the $3.4 million one-time
offset approved by Commission Order No. 34072. It also allows parties to respond to the
2
I Case No. GNR-U-18-01 Order No. 33965
Company's proposed ratemaking treatment for the remaining net Tax Reform Act benefits.
OVERVIEW OF THE TAX REFORM ACT
The Tax Reform Act was enacted December 22,2017, with the majority of the provisions
becoming effective January 1,2018. In general, the most notable items affecting the Company's
annual revenue requirement include:
o The federal corporate income tax rate reduction from 35 to 2l percent;
o The requirement to normalize excess deferred income taxes associated with public
utility property utilizing the average rate assumption method ("ARAM");
. The elimination of the allowance for bonus depreciation for public utility property;
o The repeal of the domestic production activities deduction (section 199);
o The repeal of the deduction and imposition of certain limitations with respect to
certain expenditures;
o A reduction to third-party wheeling revenues due to the change in the corporate
income tax rate; and
o The impact of the reduced tax gross-up on Production Tax Credits ("PTCs").
ESTIMATED REVENUE REOUIREMENT IMPACTS
To comply with the March 30,2018 filing requirement2 for the Company to provide the
revenue requirement impact of the federal tax code changes, the Company initially provided a
preliminary estimate using the 2016 Normalized Results of Operations in its Report. By the time
settlement discussions were held April 30,2018, the Company had completed the 2017
Normalized Results of Operations and updated its original estimate therewith. Both estimates were
calculated using a "price change" approach in which the Company reduced revenues to reflect the
J
2 Order No. 33965
lower revenue requirement while maintaining the same earned return on equity before accounting
for the change to the corporate income tax rate.
Some of the revenue requirement impacts associated with Tax Reform Act (normalization
of excess deferred income tax including the repeal of the domestic production activities deduction,
imposition of limitations on the deductibility of certain expenditures, and the impact on wheeling
revenues) were not included in either estimate in the Report because they were more complex or
required additional guidance or information to calculate. However, consistent with the Stipulation,
this Final Report provides a complete calculation of all the impacts of the Tax Reform Act.
The Company calculated the impacts by comparing the 2017 Results of Operations under
the old federal tax rate of 35 percent with the new federal tax rate of 2l percent, attached as
Exhibit l. The results are summarized in Table I below:
TABLE 1
To prepare the comparison, the Company modified its2017 Results of Operations to
include all of the plant additions for 2018 to correctly calculate the impact the Tax Reform Act
will have on the Company (see Exhibit l, page 2), forming the starting point in Exhibit l. The
impacts associated with the elimination of the allowance of bonus depreciation for public utility
property will only impact future revenue requirement calculations as new property is placed into
service. The Company then made the following adjustments:
o Changed the federal tax rate,
4
Current Ta>es
\Meeling Rercnue Ofbet
ARAIvI Am ortization
TOTAL
$ Thousands !daho
$
$ 10,905
8,103
(514)
3,316
Tax lmpact
o Adjusted fortax related changes, such as the change in section 199, changes to
employees meals deductibility, and the elimination of the deduction for transit
passes (see Exhibit 1, page 3),
o Added in the ARAM amortization discussed below (see Exhibit l, page 4),
. Adjusted the accumulated deferred income tax balances (see Exhibit l, page 5),
o Adjusted wheeling revenues for the tax law impact on (see Exhibit 1, page 6).
Federal Coroorate Income Tax Rate Reduction
The reduction of the federal corporate income tax rate from 35 to 2l percent impacts the
Company's revenue requirement in three ways: First, it reduces current income taxes; second, it
creates a reduction to the accumulated deferred income taxes ("ADIT") liability; and third, it
reduces the Company's FERC Open Access Transmission Tariff ("OATT"), which reduces third-
party wheeling revenues.
Required Normalization of Excess Deferred Income Taxes
In addition to current income taxes, the Tax Reform Act also impacts three groups of ADIT:
protected property related items; non-protected property related items; and non-protected non-
property related items.
The decrease to the tax rate reduces the future ADIT liability by reflecting the lower income
tax rate that will be due when the temporary differences reverse. This reduction ("Excess Deferred
Income Taxes") was calculated by measuring the temporary differences at the new combined
federal and state statutory income tax rate compared to the ADIT balance existing under the old
statutory income tax rate. The Excess Deferred Income Taxes were recorded to a regulatory
liability resulting in no immediate net change to the rate base upon which the Company earns a
return.
5
The treatment ofthe regulatory liability associated with property-related timing differences
is governed by normalization rules. The Tax Reform Act provides that Excess Deferred Income
Taxes on public utility properly (e.g., temporary differences that result from different depreciation
methods and lives) or protected property related ADIT must be normalized using the average rate
assumption method ("ARAM") of accounting.s Under the ARAM, the public utility identifies the
reversal pattern (book depreciation turnaround vs. tax depreciation turnaround) and reverses the
Excess Deferred Income Taxes beginning when the turnaround occurs over the remaining book
life through regulated operating expense. Thus, while excess ADIT was calculated based on
balances at the time of the enactment of the rate change that excess would not begin to reverse
until book depreciation exceeds tax depreciation.
The Company also has non-protected property related Excess Deferred Income Taxes.
While the Tax Reform Act does not require that non-protected property related to Excess Deferred
Income Taxes be normalized using ARAM, the Company has historically treated it that way and
proposes that treatment continue. In part, this is due to the configuration of the Company's
property-related tax system, PowerTax, which presently uses ARAM to amortize all Excess
Deferred Income Taxes included in the system, protected and non-protected.
The non-protected non-property Excess Deferred Income Taxes are not subject to the
income tax normalization rules imposed by the Tax Reform Act and can be used to satisfy other
regulatory assets or deferred and amortized over a period prescribed by the regulatory jurisdiction.
Based on the 20 I 7 Norm alized Results of Operations, the impact of the Tax Reform Act on the
3 Violations of the income tax normalization provisions associated with public utility property would result in (i) a
prohibition against the public utility's claim to accelerated depreciation with respect to all public utility property and
(ii) imposition of an additional tax on the public utility wherein the tax for the taxable year will increase by the amount
by which it reduces its excess tax reserve more rapidly than permitted under a normalization method of accounting.
6
non-protected non-property related Excess Deferred [ncome Taxes was $46.5 million total-
Company and $1.2 million for Idaho. Idaho includes actual cash payments rather than accruals for
pension expenses reducing its non-protected non-property Excess Deferred Income Taxes. The
Company is proposing a five-year amortization of this balance beginning with the next general
rate case.
The Excess Deferred Income Tax balances and amortization expense included in the filing
are shown in Tables 2 and 3 below.
TABLE 2
TABLE 3
OFFSETTING IMPACT TO FERC OATT
The net impact of the Tax Reform Act was a reduction to the Company's overall revenue
requirement. This also applies to the transmission revenue requirement used for its FERC OATT.
The reduction to the transmission revenue requirement reduces the FERC OATT, which reduces
7
Property Related
Protected
Non-Protected
Non-Property Related
TOTAL
$ Thousands ldaho
$
$ 1,637,36E $ 90,690
Total
Company
$ 1,331,532
259,302
46,534
77,448
12,017
1,215
Property Related ARAITI (includes
protected & Non-protected Propefi)
Non-Propefi Related (1)
TOTAL
$ Thousands Idaho
$ 2,6s4
$ 2,654
Excess Deferred lncome Tax Balance as of December 31, 20tB
Excess Deferred lncome Tax Amortization
lncluded in Filine
the amount of transmission wheeling revenues collected from third-party users of the Company's
transmission system. This reduced Idaho allocated wheeling revenues by $0.5 million, which is
netted against the overall savings shown in this report.
TAX IMPACT ON PRODUCTION TAX CREDITS
The Internal Revenue Code ("IRC") provides that a wind facility will generate PTCs equal
to an inflation-adjusted 1.5 cents per kilowatt hour of electricity that is produced and sold to a
third-party for a period of l0 years, beginning on the date the facility is placed in-service for
income tax purposes.a
The annual amount of PTCs passed on to customers is based on three factors: 1) the
megawatt-hours of energy produced at the qualifring wind facilities; 2) the inflation-adjusted IRS
rate; and 3) the Company's tax gross-up rate. The Company's wind facilities were placed in-
service in 2006 through 2010. Thus, beginning in 2016 as the first qualifying wind facilities
reached their I 0-year anniversary from their initial in-service date, the energy produced from those
wind facilities no longer qualified for PTCs. The number of qualifying wind facilities continues to
decline each year as they reach the 10-year anniversary from their initial in-service date. Due to
both the volatility of megawatt-hours produced from the wind facilities and the approaching end
of the qualification period for each of the wind facilities, the Commission authorizeds tracking
PTCs in the Energy Cost Adjustment Mechanism ("ECAM").
The Tax Reform Act reduces the Company's tax gross-up rate applied to PTCs from
l.6l percent to 1.33 percent, which reduces the value of the PTC customers receive in rates from
$1.99 per MWH to $1.75 per MWH, based on the PTCs included in the 2017 Normalized Results
of Operations. Beginning January 1,2018, the PTC rate willchange from $1.99 to $l .75 per MWh
4IRC section 45(a).
s Order No. 33440 in Case No. PAC-E-15-09 page 6.
8
to reflect that a portion of the PTCs have been adjusted for the current tax gross-up rate, Exhibit 2
provides the calculation of the new PTC rate.
PROPOSED ACCOUNTING TREATMENT FOR RATE STABILIZATION
Based on the 2017 Normalized Results of Operations, the net revenue requirement impact
of the Tax Reform Act is $10.9 million. Consistent with the Stipulation, $6.185 million will be
returned to customers through Schedule 197, $3.3 million is subject to ARAM, leaving
approximately $1.4 million per year which the Company proposes to defer into a regulatory
liability to be used to offset regulatory assets like the 2013 incremental depreciation balance, Deer
Creek closure costs, or other future customer expenses such as the 201 8 depreciation study.
Gradualism and rate stability are longstanding ratemaking principles recognized by this
Commission in setting rates. The Company's proposal to pass $9.485 million annually ($6.185
million plus $3.3 million), represents 87 percent, of the benefit to customers now and defer the
remaining $1.4 million into a regulatory liability better aligns with those principles. Reducing rates
by the full balance of the Tax Reform Act benefits would provide interim reductions, only to leave
customers facing greater upward pressures on rates a short time thereafter. Significant changes in
customer rates downward then upward in a matter of a few years does not meet the principle of
gradualism, and does not promote rate stability. The Company proposes that a deferred regulatory
liability and the Company's proposed ratemaking treatment provides for responsible accounting
treatment that willprovide customer benefits ofthe Tax Reform Act through lower and more stable
rates, as set forth in the example of the proposed deferral shown in Exhibit
IMPACT TO CREDIT RATING
Fitch, S&P, and Moody's have all issued reports suggesting that the tax law changes may
have the potential to negatively impact utility company credit metrics. Deferring part of the
9
reduction will allow more time to analyze these impacts and adjust capital structure levels, as
appropriate. At face value, it is easy to assume that the primary impacts on the Company of the
Tax Reform Act and its reduction of corporate rates from 35 percent down to 2l percent are
entirely positive, but a closer analysis shows there are negatives in the case of regulated public
utilities. A January 2018 report from The Brattle Group ("Brattle Tax Report") discusses several
of these adverse effects.6
The Brattle Tax Report demonstrates that coverage ratios for utilities will tighten as
eamings before interest and taxes ("EBIT") and earnings before interest, taxes, depreciation and
amortization ("EBITDA") decrease, EBIT and EBITDA interest coverage is lowered and EBITDA
to debt is also lowered. These reduced coverage ratios potentially result in ratings downgrades
which may increase utilities' borrowing costs. The report goes on to show that utilities' realized
earnings volatility is increased by a lower tax rate because the "cushion" provided by the impact
of taxes on utility rates becomes smaller. This will make earnings more sensitive to reductions to
EBITDA as the offsetting tax benefit goes from a 35 percent rate to a2l percent rate. The Brattle
Tax Report also states that cash flows may be deferred due to a lower tax rate on depreciation
timing differences.
The same impacts noted in the Brattle Tax Report led Moody's Investor Service
("Moody's") to lowerthe outlook for24 regulated utilities on January 19,2018 based primarily
on the Tax Reform Act's impacts on cash flows. On January 24,2018, just after issuing its revised
negative outlooks, Moody's, issued a Sector Comment for regulated utilities in the US entitled
"Tax reform is credit negative for sector, but impacts vary by company." The comment cited many
3 See The Brattle Group, "Six Implications of the New Tax Law for Regulated Utilities", January 2018 (available at
http://files.brattle.com/files/1301 l-six-implications oLthe-new-tax-law-for-reeulated-utilities.pd0.
l0
of the same adverse impacts raised in the Brattle Tax Report, noting that while tax reform is neutral
for utility earnings it is negative for cash flow and further noting that cash flow to debt ratio could
decline by 150-250 basis points.
While the Company has not had its outlook revised to negative, the adverse impacts
discussed by Moody's and The Brattle Group will likely impact the Company if all benefits are
refunded to customers immediately. Deferring part of the reduction to rates to offset future rate
increases will ease some of these negative impacts, and allow more time for the Company, the
Commission and the other parties to analyze the impacts and reach a solution that keeps the
Company financially healthy. Deferring the remaining balance of the Tax Reform Act into a
regulatory liability and allowing the Company to offset known cost increases discussed gives the
Company time to better consider potential adverse impacts from the Tax Reform Act and to adjust
its capital structure as appropriate to account for them.
REOUEST FOR RELIEF
Gradualism and rate stability are longstanding ratemaking principles recognized by this
Commission in seffing rates. The Company's proposal to pass 87 percent of the benefit to
customers now and defer the remaining balance to a regulatory liability is intended to support these
same principals and is responsible accounting treatment. The Company's proposed ratemaking
treatment will provide customer benefits of the Tax Reform Act through lower and more stable
rates and support the Company's current credit rating.
DATED this l5th day of June,2Ol8.
RESPECTFULLY SUBMITTED,
MO
R. Hogle
ll
General Counsel
EXHIBIT I
Revenue Requirement Impact - Tax Rate Change
Rocky Mountain Power
Revenue RequiEment lmpact - Tar Rate Change
RESULTS OF OPERATIONS SUMMARY
Exhibit 1 Page 'l
21016 TAX RATE
DECEMBER 2017
NORMALIZED RESULTS
tolxct'
DECEMBER 2017
NORMALIZED RESULTSl
IDAHO
TOTAL
TOTAL
CURRENT TAX OFFSET
1
2
3I
5
6
7
I
9
10
11
12
14
15
16
17
1E
t9
20
21
22
23
21
25
26
28
29
30
31
33
3,1
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
6'l
62
63
64
65
Operating Revenues
lnterdepadmental
Special Sales
Oher OpeEting Rewnues
Operating Expenses:
Steam Production
Nuclear Production
Hydrc Produclion
other Power supply
Transmission
Distribution
Customer Ac@unting
Customer SeM@ & lnfor
Sales
Operating Revenue for Retum
Rate Base:
Electric Planl in SeMce
Plant Held for Future Use
Misc Deferrcd Oebits
Elec Plant Acq Adj
Pensions
Prepayments
Fuel Slock
Material & Supplies
Wo.king Capital
Weatherization Loans
Mis@llaneous Rate Base
278,539,915
0
28,641,606
9,499,302
513,983
0
0
(s11,924\
267,635.233
0
28,641,606
8.987,379
102,60E)(6,
(8,102,608)
(10,489)
0
0
0
(3,316.058)
0
0
(3316^O5E)
(4,293)
o
0
(9.1'r9)
(675,640)
(1s3,014)
(2,553,891)
0
(3,495,957)
179,E99
305.264,218316,680,824 2,060
70,928,509
0
2,674,996
75,549,044
'12,913,866
10,936,574
4,542,613
't60,1 10
0
7,907,361
70,928,509
0
2,674,996
75,549,0,14
12,913,866
10,936,574
4,52A,497
160,1 10
0
7.907,381
0
0
(4,293)
185,613,093 00,489)1E5,596,977
Deprcciation
Amodization
Taxes OtherThan lncome
lncome Taxes - Federal
ln@me Taxes - State
lnmme Tdes - Def Net
lnvestment Tax Credit Adj.
41,078,81 3
3,831,300
9,873,361
3,720,069
907,657
12,610,002
(439.790)
(6,721)
0
0
(22,282)
(322,703)
532,021
(8,567,639)
0
257.187.784
59.493,040
0
(8,391.092)
2EE.4E4
0
0
1,413
(3)
(1)
0
0
0
41.078,813
3,831,300
9,843,373
2,721,722
1,286,664
1,348,472
(439,790)
(6,721)
2,076
__119r
1,690,932,850
(0)
21,863,4E6
E22,391
0
2,886,288
'1 1,878,959
13,727 ,710
1,267,654
1,687,023
0
1.745,0E6,360 4,'t t0 (236)
(554,286,183)
(33,988,970)
(262,095,165)
c/3.s02)
(r,763,371)
0
(15,243,459)
0
0
(867,450,650)4,251.577 2,653.89'l
877.635,710 4,255 688 (236) 2.653.860
4,
0
0
0
0
0
0
0
0
(236)
0
0
0
0
0
0
0
0
0
0
(31)
0
0
245.302,810
59.961.408
1,690,932,850
(0)
21,883,486
422,391
0
2,886,288
11,E78,959
13,727,710
1,271,497
1,687,023
0
1,745,090,203
(ss4,286,183)
(ss,988,970)
(255,189.696)
(73,502)
(1,763,371)
0
(15,243,459)
(860,545,181)
88/,,545,022
Rate Base Dedudionsl
A@um Prov For Oepr
(31)
2,653,89'l
00
110
0
0
,577
0
0
0
A@um Def lncome Taxos
Unamorlized ITC
Customer Adv for Consl
Customer Service Deposits
Misc. Rate Base Oeduclions
Total Rate Base
1,251
6.779%
8.208%
6.779%
a.208toRetum on Equity
Footnolaa:
act. Please rcferto Etibil 1 pege 2.
(2) RefertoRAMDec20lTResultslO-21%andJAMDec20lTResultslD-21%modelsandlDworkpapec-21%.
TOTAL
ARAM
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Exhibit 1 Page 2
Rocky Mountaan Power
Reyenue Requhrment lmpac{ - T.r Rate Change
RESULTS OF OPERATIONS SUMMARY
Descrlption of Account Summary:
DECEMBER 2017
FILED RESULTS
IDAHO loJUstEDl
DECEMBER 2017
NORMALIZED RESULTS
IDAHO
I
2
4
5
6
7
I
't0
11
12
t3
14
16
17
't8
19
20
21
23
25
26
27
28
29
30
31
u
35
36
38
40
11
42
43
44
45
46
47
48
49
50
5'l
52
53
54
56
57
5E
59
60
61
62
63
64
Operating Revenues
lnterdepartmental
Special Sales
Other Operating Revenues
Ope6ting Exp€nses:
Steam Produdion
Nuclear Produalion
Hydro Prcduction
Other Power Supply
Transmission
Dislrihnion
Customer A@our(ing
customer SeMce a lntor
Sales
278,539.915
0
28,641,6@
9,499,302
27E,539,915
0
28,641,606
9,499.302
0
0
0
0
316,680,824 0 316,6E0,824
70,928,509
0
2,674,995
75,549,044
'12,913,866
10,936,574
1,142,613
160,1 10
0
70,92E,509
0
2,674,996
75,549,0,14
12,9r3,866
10,936,574
4.542,613
,60.1 t0
0
7,907,381
0
0
0
0
0
0
0
0
0
07,907,381
1 85,613,093 185,613.093
Oepreiation
Amortization
Taxes Other Than lncome
Rate Base:
Elgc{ric Plant in Senice
,r0,569,404
3,807,S07
9,873,361
9,373,979
1,675,930
6,896,682
(439,790)
(6,721)
509,409
23.393
0
(5,653,910)
(768,273\
5.713,320
o
0
41.078,813
3,831,300
9,873,361
3,720,069
907,657
'r2,610,002
(439,790)
(6,7211
lncome Taxes - Def Net
lnvestment Tax Credit Adj.
Misc Rerenue & Expense
Operating Revenue for Retum
257,363,845 (176.061)
59,316,980 176.061
257,187.784
59,493,040
1.655.736,461
(0)
21,883,4E6
822,391
0
2,E86,288
11,878,959
13.727,710
't,279,68E
1,687,023
0
35,196,3E9 r,690,932,850
(0)
21,EE3,486
822,351
0
2,886,288
, r.E78,959
13,727,7't0
1,267,654
1,687,023
0
Misc Defered Oebits
Elec Plant Acq Adj
Pensions
PEpayments
Fuel Stock
Material & Suppli€3
Working Capital
Wsatherization Loeng
Ratg Base Oeductions:
Accum Prov For DePr
Accum Prov ForAmort
Accum O6f lncomo Taxes
Unamortized ITC
CuslomerAdvior Const
Customer SeMce Doposits
Misc. Rats Base Oedus{ions
Total Rate Base
(12,035)
0
0
1,709.902,005
(553,776,774)
(33,965,577)
(2s9,055,,r50)
(73,502)
(1,763,371)
0
(15.243,459)
35,'t84.355 1.745.086.360
(s09,409)
(23,393)
(3,039,715)
0
0
0
0
(554,286,183)
(33,988,970)
(262,095,165)
(73,502)
(1,763,371)
0
(15,243,459)
(863,878,1 33)(3,572,5r7)(867,450,650)
u6,023,a72 31.611.838 877,635,710
7.011%
8.660%
6.779%
A.20ao/oRetum on Equity
Footnotea:
(1) TheDeember20lTNomalizedResultsofOpe.ationswererevisedftomthefilsdDe@mber20lTRrsultsofOpeEtionsbyaddingtheiollowingadjustments;c)therCEpital
Additions,DoprecationE)eenseandResre,AFUDCEquity,andtdchangesonthe MajorPlantAdditions.PleaserefsrtoRAMOec20lTResultslO-35%,theJAMDec2017
Resuhs lO - 35%, and the lO work p8p€r3 -35%.
0
0
0
0
0
0
0
Exhibit 1 Page 3
WORK PAPER ADJUSTMENT PAGE NO, 7.7Rocky mountain Power
ldaho Results of Operations - December 2017
Tax Deductible ltems - New
Adjustment to Tax:
Schedule M Deduction - Sec. 199
Schedule M Deduction - Sec. 199
Sch M Add - Meals & Entertainment
Sch M Add - Meals & Entertainment
Sch M Add - Transit Pass
ACCOUNT Tvoe
SCHMDP 3
SCHMDP 3
SCHMAP
SCHMAP
SCHMAP 3
TOTAL
COMPANY
IDAHO
FACTOR FACTOR % ALLOCATED REF#
SG
SE
SO
SE
SO
c
3
(34,219,097)
(1,620,786)
731.873
22,879
343,380
6.221%
6 466%
5.953%
6.466%
5.953%
(2,1 28,639)
(1 04,807)
43,568
1,479
20,441
the December 201 7 results of operations to reflect ongoing tax expense as a result of the changes from the Tax Cuts and Jobs Act of 201 7 signed on
December22,2olTwilhaneffectivedateofJanuaryl,20l8. lncludedalsoisanaddbackforthetransitpasscostsprovidedforemployeesthatareno
longer tax deductible.
anremoves a expense
Rocky Mountain Power
ldaho Results of Operations - December 2017
ARAM Adjustment - NEI
Adjuatment to Tax:
Add 201 8 ARAM Amount
Add 201 I ARAM Amount
Add 201 I ARAM Amount - Bridger Coal
Add 2018 ARAM Amount - Bridger Coal
Exhibit 1 Page 4
WORK PAPERADJUSTMENT PAGE NO, 7.9
IDAHO
FACTOR FACTOR % ALLOCATED REF#ACCOUNT Tvoe
411 10
282
41110
282
TOTAL
COMPANY
t
J
3
3
(2,540,21e)
2,540,219
(113,672)
113,672
1 00.000%
100.00002
1 00.000%
1 00,000%
(2,540,21e)
2,540,219
(113,672)
113,672
ID
ID
ID
ID
property and non-protected property using the average rate assumption method (ARAM)
Also,
This adjustment provides an annual amortization of the accumulated deferred income taxes related to the change in federal tax rate of the protected
property and non-protected property using the average rate assumption method (ARAM) for Bridger Coal Company.
an
Exhibit 1 Page 5
WORK PAPERADJUSTMENT PAGE NO, 7.8Rocky Mountain Power
ldaho Results of Operations - December 2017
Deferred lncome Tax - New
Adjustment to Tax:
Restate DIT @24.58660
Remove DIT Attributed to Flow Through
of
ACCOUNT Tvoe
41010
41010
J
c
TOTAL
COMPANY FACTOR FACTOR%
(1,154,165) lD 100.000%
(734,855) tD 100.0000%
IDAHO
ALLOCATED REF#
(1,1 54,165)
(734,855)
ARAM associated with flow through taxes. The full impact of the ARAM will be captured under a separate ARAM adjustment.
removesexpensethe new tax rate. This
Exhibit 1 Page 6
Rocky Mountain Power
ldaho Results of Operations - December 2017
Tax lmpact on Wheeling Revenue - NEW
WORK PAPERADJUSTMENT PAGE NO. 3.5
ACCOUNT Tvoe
TOTAL
COMPANY FACTOR FACTOR%
sG 6.2210A
IDAHO
ALLOCATED REF#
(511 ,924)
AdJustment to Revenue:
Other Electric Revenues 456 3 (8,229,471)
Adjustment Detail:
Adjusted Vvheeling Revenues 12 ME December 2018
lmpact of Tax Rate Change
Adjusted Wheeling Revenues 12 ME December 2018
103,558,626
(8,22s,471)
95,329,1 56
of
in the transmission rate due to
EXHIBIT 2
Production Tax Credit Base Rate
ldaho Energy Cost Adjustment Mechanism
Production Tax Credit Base Rate
GNR-U-18-01
Base PTCs - PAC-E-15-09
1 TotalCompany PTCs in Rates
2 lD SG Allocation Factor
3 ldaho Allocated PTCs in Rates
4 Annual ldaho Base Load @ meter (M\Nh)
5 lD Allocated PTCs in Rates ($/M$lttl
Base PTCs - GNR-U-18-01
PTC in GNR-U-18-01 Before Tax Gross-up
Net to Gross factor = (1/(1-tax rate))
Base Amount Updated for New Tax Rate
lD SG Allocation Factor from GNR-U-18-01
lncluded in GNR-U-1 8-01
ldaho Allocated PTCs in Rates
Annual ldaho Base Load @ meter (M\/Vtt)
lD Allocated PTCs in Rates ($/MWh)
PAC-E-15-09
$ (115,633,069)
6.0063%
($6,945,269)
3,483,480
$(1.es)
Exhibit 2
PAC-E-i5-09 GNR-U-18-01
$ (47,5s5,547) $ (47,555,547)
'r.61 16 1.3260
$(76,641,923) $
6.22060/o
(63,058,655)
6.22060/o
$ 844,961 $ (4,767,587) $ (3,922,627)
($6,100,308)
3,483,480
$(1.75)
Federal/State Combined Tax Rate
Net to Gross factor = (1/(1-tax rate))
37.95',1o/o
1.6116
24.587o/o
1.3260
EXHIBIT 3
Estimated Federal Tax Impact Deferral and Amortization Table
Rocky Mountain Power
Estimated Federal Tax lmpact Deferral and Amortization Table
State of ldaho
$ - Thousands
Deferral
Exhibit 3
Ref
(2)
Current Tax.
\Mreelino. ARAM1 Offsets Total Deferred(
Annual Refund
$6,1 85
Refund
Jan-1 8
Feb-1 8
Mar-18
Apr-'18
May-18
Jun-1 8
Jul-18
Aug-18
Sep-18
Oct-18
Nov-1 8
Dec-18
Total
Beoinninq Balance
$-
909
1,817
2,726
3,635
4,544
1,512
1,905
2,299
2,692
3,085
3,478
515
515
515
5t5
515
515
515
Endino Balance$ 909
1,817
2,726
3,635
4,544
1,512
1,905
2,299
2,692
3,085
3,478
3,872
o
(2,516)
909
ono
909
909
909
909
909
909
909
909
909
909
909
909
909
909
909
a
(3,42s\
909
909
909
909
909
909
3,872 $
4,265
4,658
5,052
5,445
5,838
6,232
6,625
7,018
7,412
7,805
$r0,905 $
$
(3,425) $
$
7,480 $3,608 $3,872
4,265
4,658
5,0s2
5,445
5,838
6,232
6,625
7,018
7,412
7,805
8,1 98
8,985
9,378
9,771
1 0,1 65
't0,558
10,951
11 ,345
11,738
12,131
12,525
12,918
13.31 'l
Jan-19 $
Feb-'19
Mar-19
ApFl9
May-19
Jun-1 I
Jul-19
Aug-'19
Sep-1 9
Oct-19
Nov-19
Jan-20 $
Feb-20
Mar-20
Apr-20
May-20
Jun-20
Jul-20
909
909
909
909
909
909
909
909
909
909
909
909
909
909
909
909
909
909
909
909
909
909
515
515
515
515
5't5
5't5
515
515
515
515
515
Dec-1 9
Total $ 10,90s$ $ 10,905 $ 6,185 $ 8,s91
8,591 $
8,985
9,378
9,771
'10,165
10,558
'10,951
11,345
11,738
12,131
12,525
12,918
909
909
909
909
909
909
909
909
909
909
909
909
5't5
515
515
515
515
515
515
515
515
515
515
515
909
909
909
909
909
909
909
909
909
909
909
909
$$$
Aug-20
Sep-20
Oct-20
Nov-20
Dec-20
Total $10,90s $$10,905 $6,185 $13,3't I
(1)
(2)
See Exhibit 1 page 1 line 2 for detail of the $10.9 million.
lncludes $3.425m offsetforthe 2013 depreciation study, effective June 2018. The settled cash refund of$6.185m is effective June 2018