20190514Staff Comments.pdf

MATT HLINTER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 10655
IN THE MATTER OF THE APPLICATION
OF'PACIFICORP DBA ROCKY MOUNTAIN
POWER FOR APPROVAL OF A $15.1
MILLION DEFERRAL OF NET POWER
COSTS, AND AUTHORITY TO INCREASE
BY 0.4 PERCENT ELECTRIC SERVICE
SCHEDULE NO. 94 (ENERGY COST
ADJUSTMENT).
CASE NO. PAC-E.19-04
COMMENTS OF THE
COMMISSION STAFF
RT C E IVED
,i019llfiY ll+ Pll 2: lrtr
i0r\HO F'USLIC"i ill'f l i:S COMl,llSSlON
Street Address for Express Mail:
472W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
)
)
)
)
)
)
)
)
STAFF OF the Idaho Public Utilities Commission, by and through its Attorney of
record, Matt Hunter, Deputy Attorney General, submits the following comments.
BACKGROUND
On March 29,2019, PacifiCorp dba Rocky Mountain Power ("Company") applied to the
Commission for an order authorizing the Company to adjust its rates under the Energy Cost
Adjustment Mechanism ("ECAM"). The ECAM allows the Company to adjust its rates each
year to capture the difference between the Company's actual power supply expenses and the
power expenses embedded in base rates. The adjustment is a separate line item on customer bills
that increases if power supply costs are higher than the amount already included in base rates, or
decreases if power supply costs are lower. The ECAM does not affect the Company's eamings.
The Company's present ECAM Application, if approved, would increase rates in all
customer classes. However, these increases would be offset by a number of savings during the
ISTAFF COMMENTS MAY 14,2019
same period-most signif,rcantly federal tax cuts passed onto Idaho customers under Schedule
197 , as approved in Order No. 34331. Therefore, Idaho customers would experience a net rate
decrease even if the Company's ECAM Application is approved.
The Commission first approved an annual ECAM rn2009, and the mechanism has been
modified several times since then. See Order Nos. 30904 ,32432,32910,33008, 33440,33492,
33776. The ECAM allows the Company to increase or decrease rates each year to reflect
changes in the Company's power supply costs over the year. These costs vary with changes in
the Company's fuel (gas and coal) costs, surplus power sales, power purchases, and associated
transmission costs. The Company tracks the difference between the actual net power costs
('NPC") it incurred to serve customers, and the embedded (or base) NPC it collected from
customers through base rates. The Company defers the difference between actual NPC and base
NPC into a balancing account for later disposition at the end of the yearly deferral period. At
that time, the ECAM allows the Company to credit or collect the difference between actual NPC
and base NPC through a decrease or increase in customer rates. In 2018, the deferred NPC
difference was about $15.1 million.
Besides the NPC difference, this year's ECAM includes: (l) an adjustment for coal
stripping costs; (2) aLoad Change Adjustment ("LCA"); (3) a true-up of the incremental
Renewable Energy Credit revenues; (4) Production Tax Credits; (5) Deer Creek Mine
amortization expenses; and (6) the Lake Side 2 generation resource adder. The ECAM includes
a"90ll0 sharing band" in which customers paylreceive 90Yo of the increase/decrease in the
difference between actual NPC and base NPC, LCA, and the coal stripping costs; and the
Company incurs/retains the remaining 10o%.
With this ECAM Application, the Company ultimately seeks an order approving the
Company's: (l) deferral, for later recovery through rates, of $15.1 million in power supply costs
during the deferral period; and (2) revised Electric Service Schedule 94, Energy Cost
Adjustment, which would reflect the ECAM adjustment and increase the Company's Schedule
94 revenues by approximately $4.6 million.
As noted above, the Company states that if its proposal is approved, rates for customer
classes would increase as follows:
. Residential Customers: 0.302o Residential Schedule 36, Optional Time-of-Day Service: 0.4o2
o General Service Schedule 6:0.5o/o
STAFF COMMENTS MAY t4,20192
o General Service Schedule 9:0.5%o Irrigation Customers: 0.4Yo
o Commercial or Industrial Heating Schedule 19:0.5Yo
o General Service Schedule 23:0.4o/oo General Service Schedule 35:0.6Yo
. Public Street Lighting:0.2o/o
o Industrial Customer, Schedule 400:0.5o/o
o Industrial Customer, Schedule 401:0.5Yo
Source: Application, Exhibit No. 2 to Direct Testimony of Robert M. Meredith; See also,
News Release and Customer Notice filed with Application.
The Company states these increases will be offset by a number of savings during the
same period. The Company states that Idaho customers will receive a net rate decrease of
approximately $ 1 3 1,000 annually.
STAFF ANALYSIS
Deferral Analysis
Staff believes the Company's methodology complies with previous Commission orders.
Staff further believes that the Company used accurate actual loads and prudently incurred actual
costs and revenues and applied the proper loads, costs, and revenues embedded in base rates.
Accordingly, Staff believes the Company accurately adjusted for the difference in prudently
incurred actual costs/revenues versus base rate revenue recovery in its Application. The table
below summarized the NPC defenal to be recovered from customers.
Table of 2018 ECAM Deferral
STAFF COMMENTS MAY t4,2019J
NPC Differential
EITF 04-6 Adjustment
Load Change Adjustment Rate
Total Deferral Before Sharing
Sharing Band
Customer Responsibility
Production Tax Credit Deferral
Renewable Energy Credit Deferal
Deer Creek Amortization Expense
Lake Side 2 Resource Adder
Interest on Deferral 13 11
$ 1s I 714Annual Deferral - Dec 201
I
Idaho Customers
$ 7,152,587
(139,271)
$ 4,941,458
$ 5,490,509
90%
3,287,899
172,763
1,134,078
5,431,705
Staff reviewed the Company's internal and external audit reports, journal entries,
invoices, contracts, and bills to customers. Staff also reviewed the Company's adjustments to its
actual costs. Staff reconciled the general ledger amounts to the NPC provided in Company
Exhibit No. l. Staff also reviewed the Company's hedge contracts and policies and believes they
reasonably safeguard price stability and fuel stability. In addition, Staff reviewed the entries for
the amortization of the depreciation regulatory asset for Deer Creek Mine closure and believes
they comply with Order No. 33304 in Case No. PAC-E-14-10. Staff also reviewed transactions
and invoices for Energy Imbalance Market revenues. Staff concluded that the NPC in Company
Exhibit No. 1 is accurate and complies with ECAM orders.
NPC Deferual
The NPC adjustment within the ECAM allows the Company to collect or credit the
difference between actual net power costs incurred to serve customers in Idaho and the NPC
collected from Idaho customers through base rates. For the 2018 deferral year, the Company
under-collected NPC embedded in base rates as compared to actual NPC by about $7.1 million.
This results in an NPC adjustment of about $6.4 million after 90%ll0% customer sharing. Staff
believes that the calculations and methodology the Company used to derive the adjustment (1)
meets the intent of the ECAM, (2) conforms to Commission Order, and (3) is calculated
correctly.
For the 2018 defenal year, the NPC embedded in base rates is $26.90 per MWh. This
value was last adjusted by Commission Order No. 33668 in Case No. PAC-E-16-12 using the
Idaho NPC base amount of $91,646 ,727 divided by the base load at customer meter of 3,407,488
MWh. The amount collected through base rates is calculated by multiplying this rate by
3,602,982 MWh of actual Idaho sales to get $96,904,672 of actual revenue the Company
collected through base rates. When this amount is subtracted from $104,057,259, Idaho's share
of actual NPC, it results in an under-collected amount of about $7,152,587. The resulting
adjustment reflected in the balancing account for collection through Schedule 94 rates after
90%l l0% customer sharing is $6,437,328.
4STAFF COMMENTS MAY t4,2019
EITF 04-6
The EITF 04-6 adjustment reflects the difference between coal stripping costs incurred by
the Company and recorded as stated in the accounting pronouncement EITF 04-6 and the
amortization approved by the Commission in Case No. PAC-E-09-08. The Company uses this
account to "undo" the effects of EITF 04-6 that required the Company to expense coal stripping
costs as opposed to amortizing it over the coal produced from that section of open mines. This
account is a benefit of $139,271 to customers. Staff reviewed this adjustment and believes it is
accurately calculated.
LCA
Staff reviewed the LCA and believes it was calculated correctly according to
Commission Order No. 33440. The LCA adjusts for the under or over recovery of fixed energy-
classified production cost (minus NPC) as a result of the difference between sales used to
determine base rates and the Idaho sales from the deferral year. This year's LCA reflected an
over recovery of $ I .523 million and a credit to customers of $ I .370 million after applying
90%l l0% customer sharing.
The Load Change Adjustment Rate (LCAR) of $5.54 per MWh was set in Case
No. PAC-E -16-12 and adjusted for changes in the corporate tax rate through Order No. 34331.
When multiplied by actual Idaho sales of 3,602,982 MWh, it produces $19,956,949 of energy-
classified fixed production cost collected through base rates. After subtracting this amount from
the actual amount of energy-classified fixed production cost, it provides customers with a credit
of $1,522,806 after 90%110% customer sharing.
Production Tax Credit (PfC)
The Commission approved a settlement in Case No. PAC-E-I5-09 that moved PTCs to
the ECAM at $1.99 per MWh, totaling $7,183,528 in 2018. The Company allocated $3,895,629
of its actual20lS PTCs to Idaho, resulting in a $3,287,899 adjustment in the ECAM.
5STAFF COMMENTS MAY 14,2019
Renewable Energy Credit (REC)
In PAC-E-I6-12, the Commission approved $0.09/MWh for RECs to be included in base
rates. The difference between that amount and actual REC revenue is included in the ECAM. In
2018, actual REC revenues were lower than the REC revenues in rates by $172,763.
D e er Cr e e k Amor tization
The Commission approved full amortization of unrecovered Deer Creek Mine capital
costs in Order No. 33304, Case No. PAC-E-14-10. In the next ECAM case, the Commission
approved a stipulation allowing the Company to collect about $ 1.13 million annually for the
Idaho-allocated Deer Creek amortization expense through the ECAM. See Order No. 33440,
Case No. PAC-E-15-09. The monthly amount of this expense has been consistent since the
Company's power costs were updated in PAC-E-I6-12.
Lake Side 2 Resource Adder
In Order No. 32910 in Case No. PAC-E-13-04, the Commission approved a Settlement
Stipulation to allow the Company to recover Lake Side 2 generation costs through the ECAM
until those costs are included in base rates. The Company has complied with this order by using
the authorized rate of $l.99 per MWh of generation up to a maximum of $5.43 million per year,
which the Company reached in 2018.
Prudence of Actual NPC
Overall, Staff believes the Company prudently dispatched its resources, purchased power
from the wholesale market, and sold generation into the market to minimize NPC to customers
recognizing market and weather conditions that occurred during the 2018 deferral year. Staff
formed its opinion after comparing the NPC in the 2018 deferral year as reflected in this year's
ECAM, with the NPC in the 2017 deferral year as reflected in last year's ECAM.
Specifically, Staff noted that system customer load decreased 0.5% when compared to
20 I 7 loads, while total system generation increased 0.9Yo as seen in the table below. This
occurred because the off-system sales in20l8 accounted for I l.9o/o of total generation, whereas
off-system sales in 2017 accounted for only 10.60/o of total generation. Any increase in the off-
6STAFF COMMENTS MAY 14,2019
SYSTEM GENERATION 2017 2018 Difference
MWh %MWh %o/o (Yearly)
Net System Load 59,375,995 89.4 59,055,479 88.1 (0.s)
Resale 7,047,878 10.6 7,966,935 I 1.9 l3.0
Total System 66,423,873 100.0 67,022,354 100.0 0.9
system sales increased customer benefits as long as the cost to dispatch the Company's
generation into the wholesale market was less than market prices.
A30oh decrease in hydro generation largely drove the changes in NPC between the2017
and20l8 deferral years. Any decrease in hydro generation must be offset with generation from
other resources, especially resources that are dispatchable. As seen in the table below, the
Company offset some of the short-fall in hydro generation with an increase in Company-owned
wind generation; however, the Company likely covered the rest of the short-fall with an increase
in dispatchable gas generation that drove up fuel costs. Additionally, an increase in variable
wind generation drove the need for more dispatchable resources, such as gas, to balance the
system.
The increase in gas generation also was caused by a lower per MWh cost for gas in 2018
compared to 2017 . The Company's average cost for gas decreased by 2 1% from2017 to 2018,
from $29.07 per MWh in 2017 to $22.97 per MWh in 201 8. The lower cost of gas and increased
7
GENERATION 2017 201 8 Difference
MWh %MWh %%;o (Yearly)
Purchased Power / Net
Interchange
13,992,836 2t.t 13,520,820 20.2 (3)
Coal 37,365,559 56.3 36,485,022 54.4 (2)
Gas 7,446,999 tt.2 10,553,552 15.7 42
Hydro 4,728,162 7.1 3,257,403 4.9 (3 l)
Other (Primarily Wind)2,890,317 4.4 3,205,557 4.8 ll
Total System 66,423,873 100 67,022,354 100
STAFF COMMENTS MAY 14,2019
generation from gas also reduced the Company's need to buy electricity, and was likely the
source ofgeneration used to increase outside sales.
Although coal generation declined, this was due to maintenance outages on the
Company's units. The amount of coal generation typically doesn't vary much because coal
generation is a baseload resource and the cost of coal is not subject to changing market prices.
Rate Reduction Analysis and Proposed Rates
Staff determined the Company's rate spread methodology complies with past
Commission orders, and believes the resulting rates are fair, just, and reasonable. The Company
calculated the rate spread across customer classes using the line loss-adjusted equal cents per
kilowatt-hour method approved in Commission Order No. 33440. While revenue increased
overall by 0.4o/o, the revenue impact to each customer class on a percentage basis will differ due
to the variance in the ratios of customer charge, demand charge, and the energy component. A
copy of the Company's rate impact is included as Attachment A to these comments.
CUSTOMER NOTICE, PRESS RELEASE AND PUBLIC COMMENTS
The Company included its press release and customer notice with its Application. Staff
reviewed them and determined they comply with Rule 125 of the Commission's Rules of
Procedure. IDAPA 31.01.01.125. The Company included its notice with bills mailed to
customers beginning April 5 and ending ili4ay 2,2019, which provided customers with a
reasonable opportunity to file comments by the May 74,2019 comment deadline. As of May 13,
2019, no customer comments had been filed.
STAFF RECOMMENDATION
In summary, based on the analysis discussed above, Staff recommends the Commission:
l. Approve the Company's Application as filed, with rates effective June 1,2019.
2. Direct the Company to submit tariffs that reflect Commission approved rates.
8STAFF COMMENTS MAY 14,20t9
fuou,of May 2019Respectfully submitted this
Technical Staff: Brad Iverson-Long
Travis Culbertson
Rachelle Farnsworth
Joe Terry
Rick Keller
i :umisc/comments/pace I 9.4mhbltncrltrk comments
Hunter
Attorney General
9STAFF COMMENTS MAY 14,2OI9
CERTIFICATE OF SERVICE
TED WESTON
ROCKY MOUNTAIN POWER
1407 WEST NORTH TEMPLE STE 330
SALT LAKE CITY UT 841 16
E-MAIL: ted.weston@oacifi corp.com
DATA REQUEST RESPONSE CENTER
E-MAIL ONLY:
datareque st@,pac i fi c orp. c om
BRADLEY MULLINS
1750 SW HARBOR WAY
STE 450
PORTLAND OR 97201-5133
E-MAIL: [e-mail]
ELECTRONIC ONLY
KYLE WILLIAMS
BYU IDAHO
[e-mail]
RANDALL C BUDGE
THOMAS J BUDGE
RACINE OLSON PLLP
PO BOX 1391
POCATELLO ID 83204-1391
E-MAIL: [e-mail]
[e-mail]
YVONNE R HOGLE
ROCKY MOLINTAIN POWER
1407 WN TEMPLE STE 320
SALT LAKE CITY UT 841 I6
E-MAIL: [e-mail]
RONALD L WILLIAMS
WILLIAMS BRADBURY PCC
PO BOX 388
BOISE ID 8370I
E-MAIL: [e-mail]
ELECTRONIC ONLY
JIM DUKE
IDAHOAN FOODS
[e-mail]
ELECTRONIC ONLY
VAL STEINER
ITAFOS CONDA LLC
[e-mail]
BRIAN C COLLINS
MAURICE BRUBAKER
BURBAKER & ASSOCIATES
16690 SWINGLEY RIDGE RD #I4O
CHESTERFIELD MO 63017
E-MAIL: [e-mail]
mbrubaker@ consultai. com
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS l4th DAY OF MAY 2019,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-E-79-04, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING: