20171109Commments.pdf

CAMILLE CHRISTEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720.0074
[phone]
BAR NO. r0r77
RECEIVED
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Street Address for Express Mail:
472 W . WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
PACIFICORP DBA ROCKY MOUNTAIN )
POWER FOR AUTHORTZATTON TO REVISE )
THE WIND INTEGRATION RATE AND )
IMPLEMENT A SOLAR INTEGRATION RATE )
FOR SMALL POWER GENERATION )
CASE NO. PAC-E-17.1I
ALIFYING FACILITIES
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
attorney of record, Camille Christen, Deputy Attorney General, and in response to the Notice of
Modified Procedure issued in Order No. 33905 on October 11,2017, in Case No. PAC-E-I7-II,
submits the following comments.
BACKGROUND
On August 28,2017, PacifiCorp dba Rocky Mountain Power applied to the Commission
for an Order authorizing it to (1) decrease its wind integration rate for power purchase
agreements with wind-powered qualifying facilities (QF) from $3.06 to $0.57 per megawatt-hour
(MWh), and (2) implement a solar integration rate for purchases from solar-powered QFs of
$0.60 per MWh. Application at 1.
Rocky Mountain's wind integration charge offsets the published avoided cost rates the
Company pays for power under the Public Utility Regulatory Policies Act (PURPA). The charge
reduces published avoided cost rates to account for the costs of integrating wind QFs into the
COMMENTS OF THE
COMMISSION STAFF
STAFF COMMENTS NOVEMBER 9, 20 I71
Company's system. See Order No. 30497 at 6. When a utility has agreed to buy power from a
QF under PURPA, the rates for such power must not exceed the utility's "avoided s651"-v7[s1
the utility would have incurred had it generated or acquired the power elsewhere. If the costs of
integrating wind into the Company's system are not calculated and properly allocated to the
PURPA project developers, those costs will be impermissibly passed on to utility customers in
the avoided costs.
This Commission first approved Rocky Mountain's wind integration charge in 2008.
Order No. 30497. The charge was set forth in a stipulation between parties in Case No. PAC-E-
07-07, which the Commission approved. Id. at 6, 12-73. The parties to that case agreed that
Rocky Mountain's
published avoided-cost rates for Wind QFs will be adjusted to recognize an
assumed cost of integrating the energy generated by Wind QFs as a part of the
Company's generating resource portfolio. The integration charge will be
equivalent to the calculated cost of wind integration on a per MWh [basis]
provided in the Company's most recent Commission-acknowledged Integrated
Resource Plan (lRP). . . .
Id. at 6. The stipulation also required Rocky Mountain to notify "the Commission of any
changes to its wind integration charge as reflected in subsequent changes to its IRP." Id Rocky
Mountain's wind integration charge was last updated in 2016 to $3.06 per MWh. Order No.
33475.
The Company's proposed updated wind integration rate and new solar integration rate in
this Application are calculated using information regarding regulation reserve from the
Company's 2017 IRP. The Company filed its2017 IRP with this Commission on April 4,2077,
in Case No. PAC-E-17-03. The Company attached IRP Appendix F, the2017 Flexible Reserve
Study (2017 Study), as Exhibit A to its Application in this case. The 2017 Study estimates the
amount and the incremental cost of the regulation reserye required to maintain PacifiCorp's
system reliability and comply with North American Electric Reliability Corporation (NERC)
reliability standards. Application at 3. The Application describes the methodology used in the
2017 Study. Id. 4-6.
The 2017 Study estimates two categories of flexible resource costs----one for meeting
intra-hour regulation reserve requirements, and one for inter-hour system balancing costs
(associated with committing gas plants using day-ahead forecasts of load, wind, and solar). .Id. at
2STAFF COMMENTS NOVEMBER9,2OIT
6. The proposed wind integration and solar integration charges ($0.57 per MWh and $0.60 per
MWh, respectively) are the sum of these two categories of costs for wind resources and for solar
resources. Id. The Company explains these amounts represent the wind and solar integration
costs that will offset published avoided cost rates unless the QF developer agrees with the
Company to schedule and deliver, via a transmission provider, the QF output to the Company on
a firm hourly basis. Id. at7-8.
STAFF ANALYSIS
Rocky Mountain Power requests to decrease the wind integration rate from $3.06 to
$0.57 per MWh and proposes a solar integration rate of $0.60 per MWh. Staff recommends
approval of these charges, with additional, future analysis as more actual solar data becomes
available.
Staff notes that the Company filed this case before acknowledgment of the 2017 IRP on
which the proposed integration rates are based. In Commission Order No. 30497 (Case No.
PAC-E-07-07) the Commission approved a settlement stipulation that said:
The integration charge will be equivalent to the calculated cost of wind
integration on a per MWh provided in the Company's most recent Commission-
acknowledged Integrated Resource Plan (lRP)...[PacifiCorp] shall hereafter file
notice with the Commission of any changes to its wind integration charge as
reflected in subsequent changes to its I[tP.
Staff believes that there is no technical reason to further delay implementation of the
proposed rates. Staff has thoroughly examined the factors relevant to integration charges in the
2017 IRP and believes further review is not necessary at this time. However, Staff believes that
in the future, the Company should file its integration charge updates after IRP acknowledgment.
This will allow Staff to integrate its analysis of new wind and solar integration rates with the
analysis conducted for IRP acknowledgement, ensuring all factors that can affect integration
rates are comprehensively examined in the IRP.
Wind Intesration Charge
The primary drivers for the reduction of the wind integration charge from 2014 to 2017
can be categorized as either methodology changes or condition changes. The methodology
changes include changes in reliability standards, portfolio diversity, and impacts of the Energy
aJSTAFF COMMENTS NOVEMBER 9, 20 I7
Imbalance Market (EIM). The condition changes include changes in market prices and
transmission congestion. Each set of factors is discussed below.
Methodoloey Changes
Reliability Standards - The 2017 Study considered the effects of a new regulation reserve
standard, NERC Standard BAL-001-2, which became effective July 1, 2076, to replace the
BAL-001-1 standard which was considered in the 2014 study. The earlier standard required a
l0-minute interval, whereas the new standard uses a 30-minute interval. Thus, ramping
capability that can be deployed within 30 minutes can contribute to meeting the Company's
regulation reserve requirements. This change reduces regulation reserve requirements because
the Company does not need to hold regulation reserve for deviations with durations less than 30
minutes. This effectively increases the supply of regulation resources and reduces costs of
regulation reserve.
Portfolio Diversity -The 2017 Study used a portfolio wide approach to determine the overall
regulation reserve requirements, which reduces the amount of reserves required for a desired
level of reliability. The largest deviations in load, wind, and solar tend not to occur
simultaneously. In some cases, deviations will occur in offsetting directions reducing the total
amount of reserves needed to maintain a desired level of reliability. This portfolio-wide
diversity reduces the regulation reserve requirement. The 2014 study only considered reserve
requirements for a smaller amount of wind without any requirements for solar or non-variable
energy resources. The 2017 Study is based on an expanded portfolio ofresources, which
includes solar, non-variable energy resources, and additional wind capacity.
Energy Imbalance Market -The Company began its full EIM operation on November 1,2014,
and the EIM's intra-hour capabilities across the broader EIM footprint provide an opportunity to
reduce the regulation reserve the Company must hold. By pooling variability across multiple
balancing authority areas (BAA), participating BAAs can carry less reserves than would be
required independently and still meet reliability requirements.
STAFF COMMENTS NOVEMBER 9,20174
Condition Changes
Market Prices - A decrease in electricity market prices could decrease the cost of reserves used
to integrate wind and solar. When market prices drop, the reserve resources that could have been
used to generate electricity and sell it into markets will have a lower lost margin, resulting in a
lower cost of reserve. Since the prior study, market prices have declined, leading to a reduction
in the cost of reserves and the integration charge.
Transmission Congestion - According to Rocky Mountain, transmission congestion has
increased, primarily as a result of substantial additions of solar. Rocky Mountain Power's
Response to Staff Production Request I (attached). Rocky Mountain Power assumes that if
regulation-capable resources are backed down due to transmission congestion, eliminating their
ability to export electricity outside of their system, then those resources can be used to balance
wind and solar inside of their balancing areaat no additional cost. Staff believes this to be a
reasonable assumption.
Solar Integration Charge
Rocky Mountain Power asked in this case to implement a solar integration charge for the
first time. Solar generation on the Company's system was insignificant before 2015, but is
expected to amount to over 1,000 MW by the end of 2017. Due to the limited solar data, the
Company used proxy data for their 2017 Study. Staff believes that this approach is reasonable
given the limited actual data, but expects the Company to conduct additional analysis in the
future as more actual solar data becomes available.
STAFF RECOMMENDATION
Staff believes Rocky Mountain Power's 2017 Flexible Reserve Study has made
substantial improvement from its2014 wind study. Staff recommends that the Commission
authorize the Company's proposed wind integration charges.
The Company also proposed a solar integration charge for the first time. Due to limited
solar development, actual solar data are not readily available. Therefore, Staff recommends that
the Company complete additional analysis as more solar data becomes available. In the interim,
5STAFF COMMENTS NOVEMBER 9,2017
Staff recommends that the Commission authorize the solar integration charge proposed by the
Company.
+-
Respectfully submitted this q day of November 2017
W""ill,,, Urr^tr--
Camille Christen
Deputy Attorney General
Technical Staff: Yao Yin
Rachelle Farnsworth
i : umisc/comments/pace I 7. I I ccyyrf comments
6STAFF COMMENTS NOVEMBER9,2OIT
PAC-E- 17-ll I Rocky Mountain Power
October 26,2017
IPUC I't Set Data Request I
IPUC Data Request I
Please list and quantiE/ the primarl' reasons for the reduction of the wind
integration charge from 2014 to 2017 .
Response to IPUC Data Request I
Please refer to Attachment IPUC l, which provides the calculations supporring
the discussion below, including references lo additional discussion within the
2014 Wind Integration Study (2014 WIS) and 2017 Flexible Reserve Study (2017
FRS).
2014 WIS (Appendix H):
http://www.pacificorp.com/content/dam/pacificorp/doc/Enerey_Sources/lntegrate
d_Reso urce P I anl2 0 I 5 I RP/Paci fiCom-2 0 I 5 I RP- Vo I 2 -Appendices.pdf
2017 FRS (Appendix F):
http://wwn'.pacificorp.com/content/damlpacifrcorp/doc/Energv-SourcesAntegnate
d_Resource_Plan/20 I 7_lRP/20 I 7_IRP_VoluqeII_20 I 7 IRP Final.pdf
'fhe total wind integration costs dropped from $3.06 per megawatt-hour ($/MWh)
to $0.57llt4Wh, or roughly 8l percent.
The average intra-hour reserve requirement embedded in the wind integration cost
calculation has dropped by 2l percent. The estimated inrpact relative to the
previous wind integration costs is a l6 percent reduction. The Cornpany has not
specifically identified the impact of individual assumption changes, which include
the following:
. Reliability Standardo Portfolio Diversity
. Energy imbalance market (EIM)
r Historical Periodo Data granularity
lnter-hour / system balancing integration costs have dropped from $0.71lMWh to
S0.l4MWh, representing approximately l9 percent of the total change in wind
integration costs. The methodology for these costs is largely the same, reflecting
the incremental cost of sub-optimal gas plant commitment using forecasted load
and rvind, rather than actual load and wind. However, the methodology was
updated to reflect porttblio diversity, spreading the costs among, load, w'ind and
solar, rather than the incremental impact of wind after accounting for load as in
the 2014 WIS. This may have contributed to higher-hour costs for load and
decreased costs associated with wind. Because this cosl is related to gas plant
commitment, it is impacted by changes in gas prices and the Company's resource
Attachment A
Case No. PAC-E-17-l I
Staff Comments
ll/09/17 Page I of 2
PAC-E-17-ll /Rocky Mountain Power
October 26,2017
IPUC I't Set Data Request I
needs. The Company has not quantified the eflbct of these specific elements. The
system balancing integration cost results are discussed in more detail on pages
121 through 123 of the 2017 FRS.
The remaining reduction in wind integration costs is associated with the marginal
cost ofoperating reserves, and represents a47 percenlreduction relative to the
2014 WIS. The change in regulation reserve costs is primarily attributable to the
following faetors: lower market prices, transmission congestion, and 3O-minute
regulation reserye capability. Assuming sufficient regulating capability is
available within PacifiCorp's pordolio, the cosl of regulation reserve reflects the
lost margin on resources that can provide the service, i.e. the difference between
the market price or alternative generation cost and their fuel cost. Since the prior
study, market prices have declined, which reduces this margin, and a l0 percent
drop in market price can reduce the margin by more than I0 percent. In addition,
transmission congestion has increased, primarily as a result of substantial
additions of solar, which has reduced the ability of resources to get to market. If
regulation-capable resources are already backed dov*n due to transmission
congestion there is no additional cosl to count that capacity as regulation reserve.
Finally, in the prior study the entire regulation reserve requirement was included
in the spinning reserve category, which is limited to capacity available within l0
minutes. The FRS assumes that dispatchable capacity available within 30-minutes
can be counted toward the regulation reserve requirement. This increases the
supply of regulation resources and reduces costs when 30-minute capacity from
the unit with the lowest-cost reserve can be used instead of being limited to only
rhe l0-minute capacity of that unit. The system balancing integration cost results
are discussed in more detail on pages I l9 ttrough l2l of the 2017 FRS.
Recordholder; Dan MacNeil
Sponsor: Dan MacNeil
Attachment A
Case No. PAC-E-17-l I
Staff Comments
lll09/17 Page 2 of 2
CERTIFICATE OF SBRVTCE
I HEREBY CERTIFY THAT I HAVE THIS 9TH DAY OF NOVEMBER 2017,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. PAC-E-L7-II, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
TED WESTON
ROCKY MOUNTAIN POWER
1407 WEST NORTH TEMPLE STE 330
SALT LAKE CITY UT 84I16
E-MAIL: [e-mail]
DANIEL E SOLANDER
ROCKY MOUNTAIN POWER
1407 WEST NORTH TEMPLE STE 320
SALT LAKE CITY UT 841 16
E-MAIL: [e-mail]
DATA REQUEST RESPONSE CENTER
E.MAIL ONLY:
datareq r"re st@ pac i fi c orp. c om
SECRET
CERTIFICATE OF SERVICE