HomeMy WebLinkAbout20180430Link Exhibit 67 - Redacted.pdfREDACTED
Case No.PAC-E-17-07
Exhibit No.67
Witness:Rick T.Link
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
O ROCKY MOUNTAJN POWER
REDACTED
Exhibit Accompanying Supplemental Rebuttal Testimony of Rick T.Link
April 2018
O
Rocky Mountain Power
Exhibit No.67 Page 1 of 78
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Witness:Rick T.Link
BATES e
ECONOMICCONSULTING
PUBLIC VERSION
THE INDEPENDENT EVALUATOR'S
FINAL REPORT ON
PACIFICORP'S
2017R REQUEST FOR PROPOSALS
O
Presented to:
OREGON PUBLIC UTILITY COMMISSION
Prepared by
Frank Mossburg
Vincent Musco
Karen Morgan
February 16,2018
1300 Eye Street NW,Suite 600
Washington,DC 20005
202-408-6110
Rocky Mountain Power
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Witness:Rick T.Link
O TABLE OF CONTENTS
I.INTRODUCTION AND SUMMARY..............................................................................1
A.INTRODUCTION ...................................................................................................1
B.RECOMMENDATION REGARDING THE FINAL SHORTLIST ......................l
C.ADDITIONAL RECOMMENDATIONS TO PROTECT RATEPAYERS...........4
D.ADDITIONAL COMMENTS AND RECOMMENDATIONS..............................5
II.RFP ISSUANCE TO BID RECEIPT...............................................................................6
III.BENCHMARK BID ANALYSIS...................................................................................10
IV.BID RECEIPT AND QUALIFICATION......................................................................11
V.INITIAL SHORTLIST DEVELOPMENT ...................................................................14
A.RANKING THE BIDS .......................................................................................16
B.INITIAL SHORTLIST ......................................................................................22
VI.BID REVIEW AND PRICE UPDATES........................................................................22
VII.FINAL SHORTLIST MODELING...............................................................................26
A.INITIAL MODELING..........................................................................................26
B.IE SENSITIVITY ..................................................................................................29
C.INTERCONNECTION ANALYSIS.....................................................................32
D.REVISED FINAL SHORTLIST ANALYSIS ......................................................35
E.OTH ER SEN S I TIV ITI E S......................................................................................3 6
VIII.CONCLUSIONS AND RECOMMENDATIONS.........................................................37
A tt achmentOne ...........................................................................................................................4 1
Attachment Two...........................................................................................................................43
A tt achmentThr ee ........................................................................................................................4 4
A tt achmentFour ..........................................................................................................................4 5
Attachment Five...........................................................................................................................46
Attachment Six.............................................................................................................................47
A ppendix A ...................................................................................................................................4 8
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O
I.INTRODUCTION AND SUMMARY
A.INTRODUCTION
This is Bates White's Final Closing Report on PacifiCorp's 2017R Renewables RFP
("2017R RFP"or the "RFP").Bates White served as the Independent Evaluator ("IE")for this
RFP.The primary purpose of this report is to provide the Oregon Public Utility Commission
("Commission")with the IE's recommendation with respect to the acknowledgement of
PacifiCorp's ("the Company's")selection of a Final Shortlist.This report is also intended to
provide the Commission with a record of the development and evaluation process for both the
Initial and Final Shortlists.
B.RECOMMENDATION REGARDING THE FINAL SHORTLISTpresentBateBav/hiteireceommeralsthattheComsszionackmnodelndgesthechFasnhskarbalyassis,
and
review of viability factors,the Company has selected four projects for the Final Shortlist
representing approximately 1,300 MW.These projects are
TB Flats I &II -A proposed 500 MW wind project located in Carbon and Albany
Counties,Wyoming.This project is to be developed by PacifiCorp's Benchmark team
based on a site developed by Invenergy.
Cedar Springs -A 400 MW wind project located in Converse County,Wyoming.This
project is to be developed by NextEra Energy Acquisitions.Half of the project will be
sold to PacifiCorp under a Build-TransferAgreement ("BTA")while the other half will
sell power to PacifiCorp under a Power Purchase Agreement ("PPA").
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Ekola Flats -a proposed 250 MW project located in Carbon County,Wyoming.This
project is to be developed by PacifiCorp's Benchmark team based on a site developed by
Invenergy.
Uinta -A proposed 161 MW wind project located in Uinta County,Wyoming from
InvenergyWind Development.The project will be sold to PacifiCorp under a BTA
Agreement.Unlike the top three projects this project does not require the completion of
the Aeolus-to-Bridger/Anticline Segment ("D2 Segment")in order to be deliverableto
PacifiCorp's system.
Our recommendation is based on the followingpoints.
The selected bids represent the top offers that are viable under current transmission
planning assumptions and provide the greatest benefit to ratepayers as determined by
the Company's System Optimizer ("SO")and Planning and Risk ("PaR")models.
The selected bids represent the best viable options from a competitive process.The
RFP received bids from 13 suppliers offering a total of 18 projects representing about
4,900 MW.Some of these projects offered multiple options.In total there were 59
bid options presented.Offers were received from projects both inside and outside the
Company's constrained area in Wyoming and included variations in design such as
different turbines and contract structures.
Our independent analysis confirmed that the selected bids were reasonably priced
and,while not the lowest-cost offers,were the lowest-cost offers that were viable
under current transmission planning assumptions.Our analysis included the creation
of our own cost models for each bid option,a review of PacifiCorp's models and a
review of the terms and conditions of each bid.
Two company-sponsored Benchmark bids were chosen and we took special care to
confirm those selections.We confirmed the accuracy of the Benchmark costs and
scoring and providedthe Commission with a complete review of all costs of each
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project prior to bid receipt.We also confirmed the Benchmark's status by:(a)
reviewing the project's Initial and Final Shortlist scores and models,(b)
independently scoring the project's non-price characteristics,(c)comparing the cost
and output of the project to recent third-party bids,and (d)evaluatingthe bid costs in
our own cost model.The bids were also disciplined by the fact that a third-party
bidder submitted a competing offer for a BTA for each project.
To the best of our knowledge the RFP aligns with the Company's Integrated
Resource Planning ("IRP")process,as well as its 2017 IRP Plan,which was filed on
April 4,2017 ("2017 IRP").The Initial and Final Shortlist analyses used current
assumptions from the IRP.The models used to select the Final Shortlist were the
same models that the Company uses in its IRP process.While it is our understanding
that the action plan from the 2017 IRP (which includes this resource acquisition
strategy)is approved,we have yet to see a final approval order and are unaware of
any potential conditions that may come with such an order.For the purposes of this
report,we assume that the 2017 IRP will be approved without any conditions that
may alter our recommendation here.
Additionally,we base our recommendation on our participation in the entire RFP process
from design,through bid receipt and analysis,to selection of the Initial and Final Shortlists.
During that time we:
1.Reviewed and commented on drafts of the RFP;
2.Attended the pre-bid conference;
3.Monitored bidder contact,including the answers to bidder questions;
4.Confirmed the assumptions used in the analyses;
5.Confirmed the initial qualification of bidders and the confirmation of
proposal details;
6.Provided input with respect to bidder disqualifications;
7.Reviewed the price and non-price scores and models for the Company's
Initial Shortlist process and confirmed the Company's selection of an
Initial Shortlist;and
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8.Reviewed the models for the selection of the Initial and Final Shortlist and
confirmed the Company's selection of the Initial and Final Shortlist.
Throughoutthe process we were in constant contact with PacifiCorp's evaluation team.
The Company was transparent in their discussions with us and provided all information that we
asked within a reasonable timeframe.
We note that we will also be monitoring the negotiations of final contracts with the
winning bidders to ensure that actual signed contracts match the offers submitted and evaluated.
In the case of the Benchmark resources we will monitor the negotiationof EPC contracts for the
facilities.
C.ADDITIONAL RECOMMENDATIONS TO PROTECT RATEPAYERS
We have additional recommendations related to the RFP to help protect ratepayers from
bearing undue risk.First,in order to protect ratepayers and ensure that they receive the benefits
promised during this RFP we would recommend that all selected resources to be owned by the
Company (i.e.,BTAs and Benchmark resources)be held to their capital and operations and
maintenance ("O&M")cost projections as provided with the bid.These amounts should be
considered a "hard"cap,meaning that there will be no opportunity for the Company to collect
additional costs even if they believe such expenditures were prudent.Doing so will help give the
offers a risk profile much closer to that of a PPA,requiring the Company to take risks that
typical wind developers take,and insulate ratepayers from the risk of cost overruns.Because the
majority of construction costs will be covered under the BTA agreement or,in the case of
Benchmarks,a negotiated engineering,procurement,and construction ("EPC")agreement,we
feel this is a reasonable requirement.
Second,ratepayers should not be harmed if either PacifiCorp or the project developers
fail to acquire 100%of the value of the Production Tax Credit ("PTC").PacifiCorp should
provide an unconditional guarantee (i.e.,not subject to force majeure or change in law)that
ratepayers will receive the full projected value of the Production Tax Credit.This includes
situations where (a)PacifiCorp cannot claim full PTC value or (b)PacifiCorp does not have the
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taxable income to use the full PTC value.Again,this is similar to what is expected of a third-
party developer.
Third,the Company should similarly be held to their cost projections for the Aeolus-to-
Bridger D2 Segment.PacifiCorp's resource acquisition strategy here -which includes three
projects that rely on the D2 Segment's construction for economic viability-is based on a certain
cost promise for this segment and the Company should be held to its promises.
D.ADDITIONAL COMMENTS AND RECOMMENDATIONS
Based on our work in this RFP we have several observations and recommendations to
assist parties moving forward.First,parties should make more effort in the future to align the
RFP process with the IRP process.This process was rushed in order to meet deadlines for
qualification for full value of the PTC.However,the PTC's sunset has been known since the
end of 2015.We were not involved in the IRP process but are unaware of any reason why this
fact could not have been incorporated into planning at an earlier time.Moreover,as of today
there is still no written order approving the Company's IRP,which cast additional uncertainty
over this RFP process.
Second,and related to the above point,transmission planning should better align with
IRP planning.One troubling aspect of this RFP was that the initial system impact studies
providedto bidders did not incorporate the early completion of the D2 Segment.After revisions
to account for the earlier in-service date of the D2 Segment were incorporated it was determined
that only projects with early queue positions could be deliverable to load without the completion
of the entire Gateway South project in 2024.These evaluations by PacifiCorp's transmission
group essentially left us with only about four potential offers in the transmission-constrained area
served by the D2 Segment.We realize that there are functional separations within the Company
but having alignment between the planning side and the transmission side will help make more
informed decisions in the future.
Third,future RFPs using the Company's production cost modeling should examine (as a
sensitivity)resource choice with levelized benefits as well as costs.While the issue ultimately
had no impact on winning projects selected in this RFP due to the transmission issues noted
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above,the Company's modeling method,which levelized cost but not the benefits of PTC
acquisition,could have biased the bid selection to less favorable offers.
Fourth,regarding the winning Cedar Springs project,which is 50%BTA and 50%PPA
of200 MW each (for a total of 400 MW),we note that the
.Additional analysis shows this option to be preferable to the selected
option across several years,but slightly less preferable over the entire 30-year expected life of
the facility.We believe the Company's selection of the 50-50 BTA/PPA option is reasonable,
but note that the PPA option would also be a reasonable choice given its superior risk protections
and additional portfolio flexibility.
Fifth,because the selected portfolio contains mostly options to be owned by the
company,the selected portfolio generates significant PTC benefits within the first ten years of
operation.These benefits credit against revenue requirements and serve to lower costs in this
initial period.However,after the end of the ten-year PTC window these credits disappear and
costs increase.PacifiCorp currently projects a $125 million cost increase in 2031.If the
Commission believes such an increase would be unreasonable they should consider enacting
some form of rate mitigation efforts in the future.
II.RFP ISSUANCE TO BID RECEIPT
PacifiCorp's RFP was approved by the Commission,with modifications,in a special
public meeting on August 29,2017.The Commission ordered modifications to the RFP
regarding IRP acknowledgement,eligibility of existing resources,minimum bid requirements,
credit requirements and terms in the pro forma PPA.PacifiCorp made the required changes to
the RFP and provided a revised RFP to the IE prior to issuance of the final RFP to the market.
We reviewed the changes made,had no objections,and the final RFP was approved by the
Commission on September 26,2017.
The final RFP was issued on September 27,2017 and was subject to an accelerated
schedule.The accelerated schedule was designed to allow winning bidders to capture the full
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value of the PTC by placing their projects into service prior to December 31,2020,1 and to align
with the Company's Certificate of Public Convenience and Necessity ("CPCN")process to
expand its transmission system in Wyoming in order to accommodate projects selected in this
RFP.
Since PacifiCorp issued the RFP in late September the followingsteps have been
completed:
Table 1:Milestone Events to Date
RFP Issued to Market 9/27/2017
16'Bidder's Conference 10/02/2017
Notice of Intent (NOI)to Bid Due 10/09/2017
Last Day for RFP Questions to IEs for Q&A 10/10/2017
Benchmark Bids Due 10/10/2017
RFP Bids Due -Wyoming Wind 10/17/2017
RFP Bids Due -Non-Wyoming Wind only 10/24/2017
Bid Eligibility Screening Completed 10/30/2017
Initial Shortlist (ISL)Evaluation/ScoringCompleted 11/7/2017
Capacity Factor Evaluationon ISL started 11/12/2017
IEs'Review of ISL Completed 11/17/2017
ISL Price Update 11/22/2017
Capacity Factor Evaluationon ISL Completed 11/27/2017
Price update for Tax Reform Bill 12/21/2017
Final Shortlist Evaluation Completed 2/12/2018
IE Report submitted to OPUC 2/16/2018
Bates White has actively participated at each step of the RFP process.We have been in
constant contact with the Company,Commission Staff and have had multiple discussions on
many issues.In addition,throughoutthe process we have coordinated with Utah's independent
evaluator to ensure that the rules of the RFP were applied consistently across both states.
PacifiCorp held a Bidder's Conference on October 2,2017.The conference was
simulcast in Portland,Salt Lake City,and online.Bates White attended the conference in
'RFP,page 1.
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Portland.PacifiCorp personnel walked through the RFP process,including bid qualification and
evaluation.Several questions were raised regarding a range of issues including bid fees,contract
requirements,schedule,and submission requirements.PacifiCorp answered most of these
questions at the conference and the reminder of the questions later via a posting on the RFP
website.Bidders asked questions up until the final day for questions of October 9,2017.Bates
White reviewed all questions and answers prior to posting.
After the bid conference,PacifiCorp presented us with the assumptions to be used in bid
evaluation.These included items such as cost of capital,asset lives,and forward market values.
We reviewed the assumptions file and asked PacifiCorp questions in order to determine that the
numbers used were consistent with the most recent IRP process or (for certain items)reflected
the most recent Company forecasts.
Bidders were to submit NOls by October 9,2017.Submissions were made electronically
and Bates White was copied on all submissions.In total,19 companies indicated their intentions
to bid by submitting NOls.We received no indications that there were companies who wanted
to submit an NOI but failed to do so.A list of those companies providing NOls is presented in
Table 2.
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O Table 2:SummaryofNOI Submissions
O
In the NOI bidders were asked to identify the types of proposals they might submit as
well as the project size.Table 3 summarizes the indicated bids by state,type,(BTA or PPA)and
size (in MW).The potential response was heavily weighted toward Wyoming wind offers and
far in excess of the RFP's targeted solicitation of 1,270 MW.
Table 3 SummaryofIndicated Bids
ID 2 200 1 110
MT 3 400 --
OR 1 187 1 187
UT 2 180 1 100
WA 1 145 1 145
WY 21 6,194 12 3,365
Total 30 7,305 16 3,906
2 Listing for ownership is name of entity providing credit support.
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O III.BENCHMARK BID ANALYSIS
On October 10,in accordance with the RFP timeline,PacifiCorp's Benchmark team
submitted their offers to the IE and the PacifiCorp evaluation team.In total,there were four
benchmark offers submitted.These projects are shown in Table 4.
Table 4:BenchmarkProject Summary Data
Ekola Flats 250 Carbon 11/1/2020
McFaddenRid e II 110 Alban /Carbon 11/1/2020
TB Flats I 250 Carbon 11/1/2020
TB Flats I &II 500 Alban /Carbon 11/1/2020
Source:Project Applications,Appendix C
Bates White next undertook a review of the offers.In assessing a utility'sown bids in
response to the RFP,our greatest concern is that the utility will incorporate cost estimates that
have been aggressively estimated and do not characterize the costs of the project accurately.To
determine whether this had occurred,we looked at a detailed breakdown of each of the
benchmarks costs to determine if any items have been improperly omitted from the cost
calculation,and at overall capital cost levels by comparing them to publicly-available data on
recent wind generation capital costs.Such a comparison provideda measure of the overall
reasonableness of the Benchmark capital costs and capacity factors.
We found that the Benchmarks were acceptable based on three items.First,the
benchmarks were not deliberatelyunderpriced through omission of any capital cost components.
Second,the benchmark capital and operating costs appeared reasonable when compared with
public data on U.S.wind projects.Third,the capacity factors of the benchmarks were reasonable
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when compared with public data and were supported by credible third-party analysis.Bates
White's detailed assessment of the Benchmark bids is included as Appendix A to this report.
In addition,as required by the Oregon Competitive Bidding Guidelines,we reviewed
PacifiCorp's price and non-price scoring of the benchmarks prior to receipt of third-party offers.
The price score was based on a comparison of the bid's costs to the market value of the energy
the bid would replace.The non-price score was based on criteria laid out in the RFP.Bates
White confirmed the price scores by inputting key bid criteria into our own busbar levelized cost
model.Additional details about all scores,as well as the actual scores,are provided later in this
memo.All scoring was confirmed prior to the review of third-party offers,per Oregon's
Competitive Bidding Guidelines.
IV.BID RECEIPT AND QUALIFICATION
Bids from third-party bidders were due on two separate dates.Wyoming project
proposals were due on October 17.Non-Wyoming proposals were due a week later.Bates
White suggested this bifurcation,noting that the original draft RFP did not allow bids from
outside Wyoming.Only after a last-minute modification to the RFP were non-Wyoming bids
allowed to participate.Our suggestion to allow non-Wyoming bidders an extra week to prepare
their bids was meant to recognize the reduced notice afforded to them.
Bates White supervised in person in Portland the receipt and opening of the bids on both
third-party bid receipt dates.No bids were rejected for being untimely and there was no
indicationthat any bidder had offers they wished to submit but were unable to do so.
Ultimately,ignoring those who did not bid or whose bids were deemed to be non-
compliant (discussed below),13 suppliers submitted a total of 18 projects representing almost
4,900 MW-which is about 3.9 times the quantity solicited.The majority of these projects were
Wyoming wind projects.Specifically,14 projects representing around 4,400 MW were based in
Wyoming while four projects representing 485 MW were located outside of Wyoming.Some
projects contained several options,typicallydifferences in project size,equipment,or transaction
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type (i.e.,PPA versus BTA or a combination thereof).In total,bidders submitted 50 Wyoming
bid options and nine non-Wyoming bid options.
One notable set of submissions came from Invenergy.These submissions were notable
because they were third-party BTA offers for three of the four Benchmark sites (all sites except
McFadden Ridge).Invenergycurrently holds the development rights on these three sites and
under their agreement with PacifiCorp's development team,both parties were free to offer bids
into the RFP.We viewed this as a positive sign because it provides a transparent and above-
board market offer to compare with the Benchmarks.
Fees for proposals were structured such that the bidder paid a fee of $10,000 covering a
base proposal and two alternatives.Each bidder was permitted to offer up to three additional
alternatives to the base proposal (maximum of six)at a fee of $3,000 per alternative.After the
receipt of offers,PacifiCorp worked with bidders to confirm and collect bid fees.PacifiCorp and
the bidders were able to come to agreement on fee amounts.
Upon final receipt of bids and bid fee confirmation,PacifiCorp went to work confirming
bid details with bidders.Bidders provided and confirmed project information and provided
update information where their original response was lacking.Bates White participated in calls
with the bidders to make sure that all parties understood the terms and conditions of the bid and
any deficiencies encountered.
Once the bids were confirmed,PacifiCorp and the IEs reviewed the offers for
qualification purposes.Bids were held to several minimum requirements.Key requirements
included:(a)being wind powered offers,(b)demonstrating that the project could be
commercially operational by December 31,2020,(c)being located in or demonstrating
deliverability to PacifiCorp's system,(d)having requested interconnection with PacifiCorp's
system or a third-party system and (at a minimum)having a feasibility study in progress,(e)
compliance with and verification of major equipment availability (wind turbines),and (f)having
one to two years of wind data from the site.
We discussed potential disqualificationswith PacifiCorp and the Utah IE.Ultimately,
four bidders had projects disqualified from consideration for the Initial Shortlist.The
disqualified Wyoming projects were as follows:
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1.Farm was rejected for containing an unacceptable level of
development risk.The project was still in the conceptual stage,the bidder did not have
site control,and relied on "virtual"met tower data.
2.withdrew its proposal from consideration for the
short-list because the project was proposing an unacceptable transmission structure.The
project was located outside of PacifiCorp's system and proposed using a "pseudo-tie"for
delivery rather than securing firm delivery to the system.
The rejected non-Wyoming projects were as follows:
1.Caithness Energy's Beaver Creek projects were disqualified as non-compliant as they did
not offer a wind-only option as required by the RFP.Their offer was for a wind farm
mixed with battery storage.In addition,their proposal presented issues with transmission
service as their proposal required a third party to take title to the energy prior to receipt
by PacifiCorp.
2.project was rejected due to the fact that it was not a wind-onlyresource as
O required by the RFP.had proposed a PPA from a pumped storage facility
which might possibly be combined with wind and solar projects at a later date.
Bates White was consulted on the decision to remove each of these bidders and bid
options and we agreed with the decision to remove them.Caithness pronounced themselves
"very disappointed"that PacifiCorp did not accept their option,which they believed had real
value for bidders.During discussions with the bidder PacifiCorp made clear that the failure to
offer a wind-onlyoption was the primary reason for the disqualification.offer was
also rejected due to the fact they did not offer a wind-only resource (though their project
consisted of other resource types beyond storage).
In making the disqualification PacifiCorp had to point to a reference in the RFP that
supported this decision.While the RFP,plainly read,asks only for "new wind resources",the
closest specific language in the RFP document is Section 3.H.13 which states:"proposal presents
an unacceptable level of development or technology risk."Caithness offered the argument,
which has some validity,that their project did not,in fact,pose any technology risk.However,
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the fact remains that the offer was not a wind-only project and would not match the plan
resulting from PacifiCorp's approved IRP.If the RFP was interested in dispatchable wind then it
would have stated so clearly in the document.
It is true that PacifiCorp and the IEs could have decided to allow the offer.However,the
issue with this decision is that other developers may have claimed -based on a clear reading of
the RFP -that such an offer was not permitted and,had they known,they would have offered
into the RFP in a different manner than they ultimately did.Yet another issue with granting the
request is that the bid evaluation method would have to be re-examined in order to ensure it was
capturing the full value of a dispatchable wind offer.In our experience these offers typicallyare
not cost-competitive and only stand to succeed if the evaluation places a high value on the
storage component.
Another factor is whether or not a storage-aided facility would truly count as a
"renewable"resource.In California's Green Tariff Shared Renewable programs,which aim to
bring renewables to those who want a larger share than under California RPS standards or who
want to participate in community-based solar programs,storage is not allowed because it
typicallycharges from the grid.
We note here that a cursory glance at Caithness offer prices,which ranged from around
,would likely not have proven to be valuable when compared with the
prices offered by other resources.PacifiCorp did tell the Caithness team that they were welcome
to discuss the project in the context of a bilateral transaction and we share that sentiment.If the
Commission is interested in pursuing more storage we would recommend that a separate
procurement be held for such resources.
V.INITIAL SHORTLIST DEVELOPMENT
After the bids were received and bid details were confirmed,the Company began the
Initial Shortlist evaluation.Per the RFP,each bid was scored on price and non-price factors.
The total bid score was weighted at a maximum 80%for price and a maximum 20%for non-
price factors.The non-price factors were defined as follows:
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Table 5:Non-Price Factor Weighting
Non-Price
Factor
Non-Price Factor Weighting
Price score was based on a comparison of the cost of the bid to the benefits of the bid.
Costs differed based on the type of bid.For BTA bids the costs were:
(a)the revenue requirement needed to cover the project's capital cost (less the full
Production Tax Credit),
(b)O&M costs,including maintenance capital and royalty payments,
(c)property tax,
(d)wind integration cost,
(e)network upgrade costs,and
(f)Wyoming generation taxes.
For PPA bids the costs included:
(a)the PPA price,
(b)network upgrades,and
(c)integrationcosts.
The major benefit for both types of offers was captured by the value of the energy
replaced by the project.This value was based on one of three forecasts of benefits based on
project location (Wyoming,Utah/Idaho,or Oregon/Washington).Each forecast was created by
PacifiCorp's IRP team by running production costs models with and without proxy wind
resources and measuring the increase in cost at each location.Energy benefits for each project
were calculated based on the specific generation output of a given project.Beyond energy value,
BTA bids were assigned a terminal value to account for the fact that PacifiCorp would own the
site at the end of the project's useful life.
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Bids were ranked in separate categories,"Wyoming Wind"and "Non-Wyoming Wind."
In this context,"Wyoming Wind"meant projects whose deliverability was enabled by the D2
Segment.This was done because PacifiCorp's evaluation did not take into consideration the
cost of the Aeolus to Bridger transmission expansion (a cost that was included in the Final
Shortlist evaluation).We were concerned that ignoring this cost would place non-Wyoming
offers at a disadvantage.3
A.RANKING THE BIDS
Bates White independently verified the rankings in three ways.First,we reviewed each
model on a line-by-line basis to make sure that the details of the bids were properly input and
that all bids used the same default assumptions.Second,we reviewed the terms and conditions
of the bids and compiled our own non-price scores.Third,we tested PacifiCorp's models by
inputting key costs of each bid option into our own cost model,which determined an annual
$/MWh annuity cost for the bid option.After we reviewed the bids we conferred with both
PacifiCorp and the Utah IE to come to a consensus on shortlist candidates.
WyomingWind
The ranking of all the Wyoming Wind bid options is shown in Attachment One.Our
simplified cost models were able to match PacifiCorp's models reasonably well.On average
PacifiCorp's models showed a higher cost by $0.27/MWh and in 46 out of the 50 cases the
difference was less than a dollar per MWh.
The table below shows the offers for each project with the greatest net benefit,in other
words,options proposed for the same project with lower net benefit are removed for clarity.
3 Specifically,the Aeolus-to-Bridger transmission project -which has yet to be approved and built -will benefit all
Wyoming-based bids,including the Benchmark bids.It is important for the RFP evaluation process to consider the
cost of the transmission project in comparing bids,particularly in comparing Wyoming-based bids -which are most
likely to benefit from the transmission project -to non-Wyoming bids,which are less likely to benefit from the
transmission project.
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O Table 6:Best Offers from Each Wyoming Wind Project
Table 6 allows us to make a few observations.First,the offers were very close in value.
Thirteen of the projects offered net benefits of between $25/MWh and $30/MWh.This bunching
means that small assumptions can have a large impact on ranking.Second,we see that
PacifiCorp's terminal value adders were fairly small,about $1.18/MWh on average.Third,term
length does have an effect on the net benefits.The average energy benefit for projects with
terms less than 30 years is $46.76/MWhwhile the average benefit for 30-year projects is
$48.74/MWh.This difference is mostly driven by the fact that the value of energy replaced
increases in later years.These latter two items give a small advantage to BTA bids (since all
BTA offers are assumed to last for 30 years).Again,the difference is not vast,but it can have an
impact when bids are bunched so close together.This is why the BTA offers from
and were ranked just aheadof the lower-cost PPA offer from
.Finally,the Invenergy offers for the Benchmark sites were generally
To translate these net benefits into a price score and create a final ranking,PacifiCorp
utilized three scoring methods.First,the offers were "ranked'with the most beneficial bid
receiving a score of 80 points,a breakeven bid (i.e.,a bid with zero net benefit)receiving zero
points,and any scores in between being interpolated.Second,the offers were "force-ranked,"
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with the most beneficial bid receiving 80 points and the least beneficial receiving zero points,
with in-between scores being interpolated.Finally,PacifiCorp used the "force ranking"concept,
but used a "rank order"method to score all offers between the highest-and lowest-ranked offers.
So,if there were nine bids,the best would receive 80 points,the second-best bid would get 70
points,the third-best bid would get 60 points,and so on,with the worst bid receiving 0 points).
In each method PacifiCorp combined their scores with the non-price score to get a final
bid ranking.The results are shown in Table 7.
Table 7:PaciflCorp's Scores for Selected Projects
This table shows that regardless of the scoring system (e.g.,"Cases"1,2,and 3)utilized,
the actual project rankings did not change.This is an important point to underscore.
Nevertheless,there are a couple other points to draw out from Table 7.First,there was a
relatively big gap between the project and the project,which suggested
a logical threshold for determining the shortlist.Second,under the first scoring method price
scores were tightly bunched,with eight projects scored between 80 and 89 points.This meant
that non-price factors could have a larger impact on bid selection.Having said that,non-price
scores were relatively similar,with the exception of the ,which were lower than those
for other bidders.
In order to select bid options for the Initial Shortlist,PacifiCorp and the IEs proceeded
with the followinggoals in mind:
l.Selecting the bids with the greatest net benefit in terms of price and non-price
benefits,
2.A diversity of bidders and projects,'
4 This can minimize the risk of relying on the success of one given project or a given bidder.
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3.A mix of PPAs and BTAs,
4.A relatively clear split between the score of the last bid picked and the next bid that
was not selected,and
5.The RFP goal that there be a minimum of 2,000 MW selected.
PacifiCorp's recommended Initial Shortlist relative to other top-performingprojects is
shown in .
O
Source:PacifiCorp,2017R RFP -Wyoming Initial Short List Update -2017-1l-06 IE V4.pptx
The Initial Shortlist was comprised of nine projects including four PPAs,two BTAs,and
one PPA/BTA combination.All three Benchmark projects were selected to the shortlist.(Figure
l above omits the because the offer for the same site
scored higher,but,as seen on Table 6,the offer scored among the top
offers,which earned it the right to move on to the next round.)If a project was selected,all
alternatives for a given project were selected as well.
The nine projects represented a cumulative installed capacity of approximately3,100
MW,significantly above the RFP's stated target shortlist size of 2,000 MWs.The reason for
such a large selection of projects was the tight bunching of the offers.As noted above,when
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looking for a selection of projects we typicallytry to identify "gaps"in value.The first such gap
appears between the and projects.This is shown on both figure
one and above in Table 6.6 While the were also low scorers on the non-price side,
the gap appears in the price score as well.As can be seen on Table 6 there is about ag
gap between the project and the offer.
While we did consider imposing a stricter limit on the selection,ultimately,it was
considered more advantageous to include more projects in the Final Shortlist evaluation.This is
especially true given that all bids would be allowed to submit a best and fmal offer (BAFO)and
the offers were so tightly bunched that any changes resulting from the BAFO could certainly
alter the rankings.In addition,we did consider pushing for the exclusion of the McFadden Ridge
project on the grounds that it would not be included in the shortlist without the assistance of the
terminal value adder and the additional value resulting from its assumed 30 year operational life.
We ultimately decided to allow it because (a)the bid was scored properly according to the rules
of the RFP and (b)this was simply a selection to the Final Shortlist evaluation,not a selection for
a winning bid.
Non-WyomingWind
As noted above,the Non-Wyoming Wind category received substantially fewer offers
than the Wyoming category.This was not totallysurprising since the category was added at the
last minute per the decision of the Utah PSC.Only four qualified projects were submitted in this
category.The table below shows all options considered in the evaluation
Table 8:Non-Wyoming Offers (All Quahyled Options)
6 Note that the values in Figure 1 differ slightly from the values in Table 6 above and in the Appendix.Figure 1
comes from PacifiCorp's presentation to the IEs and regulators while the numbers in the other sources are taken
straight from PacifiCorp's cost models.In any case,the bid order is the same.
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Table 8 makes it clear that these bids do not provide the same level of benefit as the
Wyoming Wind offers.This is not unexpected given both (a)the quality of the wind resource in
Wyoming and (b)PaciñCorp's projected energy market benefits -which are higher in Wyoming
than elsewhere.Of course,the Wyoming bids did not include the cost of the proposed
transmission upgrade-again,this was considered in the Final Shortlist evaluation.
The was the only non-Wyoming project which provided positive net
benefits.We note that this project is actually located in Southwestern Wyoming right near the
Utah border.However,because it lies outside of the constraint that is alleviatedby the Aeolus to
Bridger transmission segment it was valued as a Non-Wyoming resource.
PacifiCorp scored these bids using the same methods as the Wyoming bids.The ranking
of the offers did not change depending on the scoring method used and the non-price scores of
the bids were not a factor (i.e.,they did not change the ultimate project rankings).
In terms of bid selection,PacifiCorp recommended selecting all projects except theg
.This selection is shown in Figure 2.
O
Source:PacifiCorp,2017R RFP -Non-Wyoming Initial Short List Update -2017-11-06 V6.pptx
PacifiCorp made this selection in order to achieve a balance of PPAs and BTAs.In
addition,there was a reasonable gap between the last bid selected and the rejected
bid.We agreed with this conclusion.
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B.INITIAL SHORTLIST
PacifiCorp placed the followingprojects and bidders on the Initial Shortlist.Again,if a
project was selected to the Shortlist,then all bid options from a project were selected.
Table 9:Initial Shortlist
O
VI.BID REVIEW AND PRICE UPDATES
Best and Final Offers from all offers on the Initial Shortlist were due on November 22,
2017.Most bidders took advantage of the opportunity to adjust their pricing.Shortly thereafter
it became clear that some form of tax reform legislation would soon be passed by the Federal
Government.After discussions with the IEs,PacifiCorp sent a notice to all remaining bidders
informing the bidders that,once tax reform legislation was finalized,bidders would be allowed a
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brief opportunity to refresh their offers to reflect any changes they felt necessary.This
opportunity was extended to all bidders since parties could not be sure how the final law changes
would affect each bidder.
On December 18th afÍCT COnferênCC COmmittee approval of the "Tax Cuts and Jobs Act,"
PacifiCorp notified bidders that they could revise their offers by December 21 to reflect any
changesthey thought necessary as a result of the Act.Several bidders took advantage of the
opportunity to adjust their offers.
PacifiCorp made other adjustments to the offers as well.As described in the RFP,
PacifiCorp engaged a third-party consultant (Sapere Consulting)to review wind generation data
from each offer in order to assess the reasonablenessof data provided by the bidders.This was
done in accordance with Guideline 10(f)in Commission Order 14-149.Evaluations were
completed by November 17,2017.Sapere Consulting found that most offers had reasonable
output estimations.The exceptions were and bids,which
each were subject to an 8%reduction in their net capacity factors based on the consultant's
findings.
In addition,PacifiCorp found that the offers from had mistakenly omitted
Wyoming sales taxes in their offers.In order to perform production cost modelingthe Company
adjusted their levelized cost models to reflect these developments.Adjusting for (a)offer
repricing,(b)capacity factor adjustments for offers,(c)inclusion of sales taxes in
offers,and (d)some revisions in interconnection costs,resulted in the following
changes in net benefits for all Wyoming shortlisted offers.
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O -
O
Table 10 shows that almost all bids saw the net benefits of their offer reduced.In some
cases this was because the bidder raised their offer price.,for example,did this for several
of their offers.In the case of BTAs,net benefits were reduced due to the lowering of the
corporate tax rate,which lowered the value of the PTC.Other bidders,for example,s
project and Project,left their offers relatively stable
and saw little change in their valuations.
The non-Wyoming offers saw similar changes as shown in Table l1.
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O Table I I:Non-Wyoming Price Updates"
Putting together both lists,the table below shows the top offer for each project according
to PacifiCorp's net benefits calculation.
Table 12:Top Offers for Each Project
O
The top offer,by net benefits,was the PPA,followed by the
PPA,the PPA,and the and .Note
how close the offers are in price,with six projects net benefits in the $22-$27/MWhrange.
One issue that we note here is that PacifiCorp initially requested letters of commitment
from shortlisted bidders.During this process,PacifiCorp had objections to some of the forms of
6 Note that two bid options for the were removed from consideration due to the fact that
the bidder was not able to hold to t eir promise on-me ate as a result of delays in turbine manufacturing.
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commitment provided by bidders,while some bidders'financial backers objected to providing
such a letter of credit,since the letter compelled them to set aside collateral.Parties ultimately
decided to interpret the RFP rules as requiring credit commitments only 20 days after selection to
the Final Shortlist.We felt this was a reasonable compromise as it allowed PacifiCorp to
continue with the evaluation and select the best offers from a wide range before getting into a
discussion of what forms of collateral they would accept.
VII.FINAL SHORTLIST MODELING
A.INITIAL MODELING
To develop a Final Shortlist,bids on the Initial Shortlist were screened using the System
Optimizer Model ("SO Model").The SO analysis involved PacifiCorp creating a "base case"by
dispatching the system without new wind additions and the D2 Segment over a 20-year time
frame.The model added resources over the years in order to maintain a given reserve margin.O PacifiCorp then allowed the SO model to run again,this time allowing it to select a
combination of bids from the shortlisted offers that would minimize costs,including the D2
Segment,to ratepayers.One key assumption here was the amount of new supply from inside the
constrained area in Wyoming that would be enabled with the construction of the D2 segment.
PacifiCorp initially assumed 1,030 MW would be available but ultimately,as discussed later in
this report,decided that 1,270 MW could be incorporated onto the system with the addition of
the D2 Segment.
The SO Model can only analyze the least-cost resource choice under one scenario or
"path"of natural gas prices and CO2 emissions costs at a time.PacifiCorp used three "paths"of
natural gas prices (high,medium and low).Medium natural gas price assumptions were based
on PacifiCorp's December forward price curve while high and low sensitivities were based on
consultation with third-party experts.The SO model also used three "paths"of CO2 costs (high,
medium,and zero).The "medium"scenario started at $4.49/ton in 2030,rising to $7.95/ton in
2036 while the "high scenario"started at $3.62/ton in 2026 and rose to $19.23/ton in 2036.
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Taken together these three gas and three CO2 Scenarios presented a total of nine specific "price-
policy"scenarios.
These nine cases produced just two distinct portfolios.The full analysis provided to the
IEs in January can be found in Attachment Two.
1.Under all scenarios the SO model selected the bid,
the Bids,the
bid and the bid.("Portfolio A")
2.In the medium gas,high CO2 case and in all three "high gas"cases the
model also selected the PPA.("Portfolio B")
All selected portfolios showed net benefits as compared to the base case,ranging
anywhere from $198 million to $782 million on a net present value basis.Benefits increased as
gas prices and emission costs increased.
Once the SO Model was run,the Company passed along these two distinct portfolios to
be assessed for stochastic risk.The term stochastic refers to assumptions being randomly varied
along a given distribution using a Monte Carlo method.Assumptions for five factors were
tested.Those five assumptions were load (electric demand),natural gas commodity prices,
wholesale electricity prices,hydro generation availability,and thermal generation availability.
Each portfolio was again assessed under the three CO2 price cases and three gas price paths.
The stochastic analysis was performed with the Planning and Risk ("PaR")Model.The
assumptions were randomly varied to result in 100 model runs for each case.This resulted in
100 different estimates of the cost -as measured by the present value of the revenue requirement,
or PVRR,over 20 years -for each case.The average (mean)of these 100 estimates was
provided as was the "risk-adjusted"mean which was equal to the average value plus the cost for
the case at the 95th percentile times 5 percent.
7 Note that this run was prior to the discovery that offer had omitted W oming sales taxes.Subsequent
analysis incorporated this cost and resulted in the se ection o the offer.
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Table 13:Modeling Results
SO Model PaR PaR Risk-Natural Gas .PVRR(d)CO2 Cost Portfoho Mean adjustedCost(Benefit)/Cost PVRR(d)PVRR(d)(Sm)
Iow Zero A ($198)($153)($161)
Iow Medium A ($229)($162)($170)
low High A ($347)($306)($323)
Medium Zero A ($372)($319)($335)
Medium Medium A ($399)($349)($367)
Medium High B ($493)($445)($467)
High Zero B ($704)($572)($601)
High Medium B ($720)($604)($634)
High High B ($782)($689)($724)
Table 13 above shows that the stochastic analysis reduces benefits somewhat,but
benefits remain in each case.
The third step in the selection of the Final Shortlist was to use the SO Model to assess
how the cost of the two portfolios from the stochastic risk assessment vary with different
assumptions about fuel price and CO2 COmpliancecosts.Recall that,unlike the PaR model,the
assumptions in the SO Model are defined outright,not varied along a distribution.Unlike the
first step,where the SO Model was allowed to pick the ideal portfolio,in this analysis,each
portfolio is fixed,allowing the model to dispatch the resource as part of the portfolio.The
purpose of this step is to gather another data point regarding the risk of each portfolio.The result
is an estimate of how much a portfolio costs under less than ideal circumstances (i.e.,when key
risk factors do not move in its favor).The results of this analysis are presented in Table 14.Note
that table this does not include some costs for transmission improvements for Portfolio B that
PacifiCorp added after the fact,such costs tilted the selection to Portfolio A in the low and
medium gas scenarios.
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O Table 14:Scenario Modeling Results
Low Zero ($198)($170)
Low Medium ($229)($216)
Low High ($347)($359)
Medium Zero ($372)($379)
Medium Medium ($399)($407)
Medium High ($493)($493)
High Zero ($692)($704)
High Medium ($709)($720)
High High ($770)($782)
This table shows that both portfolios produce positive benefits but that the portfolio with
more wind is slightly more beneficial in higher gas price scenarios.This outcome make sense
since the cost of wind stays the same but the cost of other resources increases.Therefore,more
wind would generally be preferable in high gas price scenarios.
O
B.IE SENSITIVITY
We were somewhat surprised by the fact that the SO model would choose projects that
had lower net levelized net benefits than other resources.Typically,we would expect resource
selection to mirror the levelized cost analysis and,therefore,expected to see the and
PPAs selected before the Benchmark projects.
We questioned PacifiCorp regarding this outcome.One item that they identified as a
possible driver in the bid selection was the fact that,in order,to create the inputs for the SO
model,bid costs were levelized but any PTC benefits were not-that is,these credits were
flowed through as they were earned.Moreover,the SO Model covers the time period through
2036.Combined,these two factors meant that the SO Model spreadthe PTC benefits within the
period of study,instead of over a 30-year period as is done in the Company's levelization
models.This means that any offers earning PTCs would look more attractive than a levelized
cost model would otherwise indicate.
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To see if this was the case,we asked the Company to run the SO Model with medium gas
price and CO2 inputs and levelize PTCs over the 30-year life of BTA and Benchmark bids,
instead of treating them as earned.The results were more in line with the levelized cost models.
The SO model selected the PPA,the PPA,and the g
project.
At this point,PacifiCorp made the observation that the non-levelizedPTC selection
would more closely reflect how they planned to pass PTC benefits through to ratepayers.While
this was a reasonable assertion,we also noted that we had some concern that costs for their
selection would not be levelized in real life but would,in fact,be front-loadedas well due to the
way in which the costs for rate-based assets are recovered.Therefore,we had some concern that
the front-loadednature of rate recovery would cancel out the front-loadedbenefits of the PTC
recovery,and that the PPA-heavy portfolio was truly a better selection.
In response to this concern PacifiCorp produced an analysis looking at the actual flow of
cost recoveries,treating both PTCs and costs as incurred.The table below compares the two
portfolios,PacifiCorp's selected offers (PAC Portfolio)versus the PPA-heavy portfolio.Even
though the SO Model only covers through 2036 PacifiCorp extended the analysis out through the
2050 -the end of the BTA project's useful life -by assuming market energy prices would
simply increase with inflation each year after 2036.Note that PacifiCorp did not assume that
any new supply replaces expiring contracts.
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Table 15:Comparison ofbenefits ($m)
2017 ($0)($0)($0)($0)
2018 $0 $0 ($0)($0)
2019 ($0)($0)($0)($0)
2020 $7 $13 $5 $10
2021 $58 $46 $46 $42
2022 $40 $38 $73 $68
2023 $22 $31 $87 $87
2024 $1 $20 $88 $98
2025 ($17)$5 $78 $101
2026 ($25)$4 $65 $103
2027 ($34)($3)$49 $102
2028 ($57)($20)$24 $93
2029 ($88)($52)($13)$71
2030 ($96)($78)($51)$41
2031 ($0)($79)($51)$12
2032 ($4)($82)($53)($16)
2033 ($19)($97)($59)($48)
2034 ($31)($109)($68)($80)
2035 ($41)($141)($80)($120)
2036 ($56)($156)($95)($161)
2037 ($30)($108)($102)($188)
2038 ($36)($114)($110)($214)
2039 ($42)($120)($119)($240)
2040 ($49)($126)($129)($265)
2041 ($20)$39 ($133)($258)
2042 ($25)$37 ($137)($251)
2043 ($30)$35 ($142)($245)
20 Þ‡($34)$34 ($147)($240)
2045 ($38)$32 ($153)($236)
2046 ($41)$31 ($158)($231)
2047 ($42)$30 ($163)($228)
2048 ($40)$30 ($168)($224)
2(149 ($46)$28 ($173)($221)
2050 ($484)($28)($223)($224)
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O
While the PPA portfolio is more expensive in the early years,as we might assume since
the value of the PTC in a PPA is spreadout over a longer period of time,by 2034 it has greater
cumulative benefits than PacifiCorp's selected portfolio.Even over the entire lifetime of all
projects,the PPA portfolio produced more net benefits.Note also that the only reason the
PacifiCorp portfolio was even close in net benefits over the entire time period was due to a large
terminal value applied to company-owned bids totaling about $374 million in 2050.Without the
terminal value the PPA portfolio produced a net cumulative benefit of $219 million versus $185
million for PacifiCorp's chosen portfolio.
C.INTERCONNECTION ANALYSIS
At this point we believed that the PPA-heavy portfolio should be the top choice.
However,when we voiced this opinion to the Company they claimed that they had concerns
regarding interconnection costs for some of the offers.
Specifically,the original system impact studies for most bids assumed completion of
Gateway West and South projects by 2024.Because the Company had decided to move up the
completion date for the D2 Segment they had a concern that projects located farther back in the
interconnection queue would only be feasible to come online with the entire Gateway West and
South projects complete.
As background,PacifiCorp's transmission arm,which assesses interconnection costs,
must,by law,assume that each queue project is interconnected in order received so each project
assumes that all projects ahead of it in the queue are interconnected.As more projects in the
Wyoming area are interconnected it puts more strain on the transmission system until eventually
major upgrades such as the Gateway West and South projects are needed.
Based on this analysis PacifiCorp believed it was highly unlikelythat projects higher up
in the queue would be able to interconnect with the D2 Segment alone.was one
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such project,as was PacifiCorp's McFadden Ridge Project.The ,andg
projects were noted to have low queue positions and would likely be safe.
The Company said that PacifiCorp transmission was in the process of restudying
interconnection costs assuming the accelerated completion schedule for the D2 Segment.At the
end of January PacifiCorp transmission issued revised system studies.PacifiCorp transmission
found that the Project with Queue number 713 triggered the need for major upgrades,stating:
"Additionally,the Q0713 project triggers the need for the Transmission Provider's planned
Energy Gateway South project.This project consists of a new 400 mile 500 kV transmission
line from the planned Aeolus substation in Wyoming to the Transmission Provider's existing
Clover substation in central Utah,with ancillary improvements."(See Attachment Three,page 8)
This meant that,in effect,any bid within the constrained area in Wyoming with a higher
queue number than 712 would require extensive new transmission investment to be deliverable
and likely would not be deliverable,bythe end of2020.To see the effect on bids we can return
to our earlier table showing the best offers from each project.Again,any offers higher than 712
located in the constrained area in Wyoming would need the completion of the Gateway South
Project.
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From this table we see that based on this analysis a majority of offers are no longer viable
without major transmission investment.The g,and projects
are only viable because they are outside the constrained area in Wyoming.Inside the constraint
only three projects -,,and|-are viable.
PacifiCorp claimed that this was why they proposed in their initial RFP that bids must
have a completed system impact study;however,such a requirement would not have solved this
issue.The fact is that even for projects that had completed system impact studies at the time of
bid submission,those studies needed to be redone to account for the accelerated completion
schedule for the D2 Segment.And,once those studies were redone,the same result would have
occurred:projects with queue positions above 713 would have been effectively eliminated from
further consideration.
To its credit,PacifiCorp dropped pursuit of McFadden Ridge after this analysis.
However,these restudies showed more transfer capability from the constrained area than
PacifiCorp had been assuming.Earlier studies assumed about 1,030 MW of new supply was
enabled by the D2 Segment but PacifiCorp revised the number to 1,270 MW based on the sum of
the wind projects in the constrained area that could be accommodated prior to Gateway South
improvements."With this revision,PacifiCorp stated that the larger Ekola Flats project was now
selected as part of the optimal portfolio in the SO Model.Prior to this revision Ekola was not
selected because,at 250 MW,there was not enough transfer capability to accommodate it.
The net result of these adjustments calls for consideration of the overall context of the
RFP.Recall that in its RFP as originally drafted,PacifiCorp proposed to select only projects
from the constrained area and offered three Benchmark projects.Based on the final analysis laid
out above,only one other third party bid on the shortlist (the project)could even
compete with these offers.In fact,only one other Wyoming wind offer -the
*Specifically,the company assumed Q542 (240 MW),Q706 (250 MW),Q707 (250 MW),Q 708 (250 MW),Q 712
(520 MW)could be accommodated for a total of 1,510 MW of interconnection capability.PacifiCorp then
subtracted 240 MW to account for a customer that already has an executed interconnection agreement,leaving a
total of 1,270 MW.
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wind proposal -had a high enough queue position to be viable.So this entire RFP really boiled
down to two viable benchmarks and two third-party offers,meaning a lot of the analysis
presented here was of questionable value.
To be clear,the remaining viable offers were competitive offers,but were not the best the
market could provide based on cost or risk,but for the transmission constraint issue.We
understand and appreciate PacifiCorp's position and do not disagree with their transmission
department's findings (beyond noting the obvious fact that many projects will likely drop out of
the queue and that actual interconnection costs will differ from projected).To go forward with
projects that cannot meet the proposed online date without major accelerated transmission
investment would not seem to be the wisest course of action
The real issue here is that PacifiCorp's procurement (in the form of this RFP)got out
ahead of its resource and transmission planning.If PacifiCorp had identified this plan earlier,
then all aspects of this work (IRP,transmission planning and resource acquisition)could have
worked together in a more coherent fashion.
D.REVISED FINAL SHORTLIST ANALYSIS
Based on these findings PacifiCorp completed additional analysis to confirm the Final
Shortlist selection.PacifiCorp updated their analysis to remove all non-viableoffers,update
interconnection costs,increase transfer capability from the D2 Segment and adjust the Invenergy
offer to include Wyoming sales taxes.The updated presentation is included here as Attachment
Four.
With these revisions,the SO Model selected a portfolio that included the Benchmark TB
Flats I and II bid,the Ekola Flats benchmark,the Cedar Springs BTA/PPA,and the Uinta BTA.
Benefits generally increased due to the larger amount of total supply selected (as the 109 MW
McFadden project was replaced by the 250 MW Ekola Flats project).
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REDACTED Case No.PAC-E-17-07
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Again,the outcome was not surprising given the fact that there were so few bids to
choose from and that,with the revised and increased costs for the Invenergybid options,the
Benchmark options generally were lower cost.
E.OTHER SENSITIVITIES
Along with the analysis described above PacifiCorp also provided additional sensitivities,
including a solar sensitivity and a wind repowering sensitivity.The goal of each analysis was to
ensure that other procurement activities did not lessen the benefits of this procurement.
For the solar sensitivity PacifiCorp ran the SO Model for two scenarios:(a)medium gas
and medium CO2 prices and (b)low gas no CO2 prices.PacifiCorp looked at value of adding
about 1,000 MW of new solar PPAs (a)instead of the shortlisted bids from the RFP and (b)
along with the shortlisted bids.Prices and quantities were based on initial results from
PacifiCorp's current solar RFP.
In all cases the combination of solar and shortlisted resources provided more net benefits.
For example,in the medium gas medium CO2 scenario benefits of just solar were $343 million
on net whereas solar and the shortlisted bids provided $647 million of net benefits in the SO
Model.In the low gas zero CO2 Scenario solar PPAs alone provided $196 million of net benefits
but $312 million when combined with the shortlisted offers.
In the wind repowering scenario PacifiCorp allowed additionalrepowering of existing
units up to their large generator interconnection agreement ("LGIA")limits.Running the same
scenarios as with the solar sensitivity PacifiCorp found that benefits increased when repowering
was added to the shortlisted bids.For example,in the medium gas medium CO2 SCenaTÎO
benefits increase to $608 million on net versus $405 million with just the Final Shortlist offers
alone.
PacifiCorp also provided a sensitivity which tried to account for the fact that the turbines
used by the might require the installationof a synchronous condenser or other
equipment at the Aeolus substation to addressperformance issues.PacifiCorp ultimately
determined that upgrade costs would have to be in the
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REDACTED Case No.PAC-E-17-07
Witness:Rick T.Link
.It was PacifiCorp's judgment that costs would not be
higher than this level.
Finally,per our request,PacifiCorp looked at the as-earned costs and benefits of the Final
Shortlist portfolio versus a portfolio in which the Cedar Springs PPA/BTA bid was replacedg
.Our reason
for requesting this was that we wanted to see if,as we found before,the actual recovery of costs
and benefits truly favored the full PPA option.
PacifiCorp calculated costs and benefits under the medium-gas medium CO2 COSÍ
scenario for each portfolio as they had done before,looking at as-earnedcosts and benefits and
extending the analysis out to 2050 by assuming that energy benefits increase with inflation.
They found that their preferred portfolio had a cumulative net benefit of $298 million on a net
present value basis and the portfolio with had a value of $280 million
on a net present value basis.Removing the terminal value brings the numbers closer together,
but the company's preferred portfolio still has a greater net benefit,$255 to $250 million on a net
present value basis.
We do note that the portfolio with has a lower cumulative net
benefit from about 2033 through 2048,better risk protections,and offers the Company future
flexibility,making it a reasonable choice.However,given the fact that the total net benefits
favor PacifiCorp's selection we cannot conclude that the selection of the BTA/PPA bid is
unreasonable.
VIII.CONCLUSIONS AND RECOMMENDATIONS
We recommend that the Commission acknowledge PacifiCorp's Final Shortlist.The bids
do represent the top viable offers and are projected to provide net benefits.With proper risk
mitigation the offers can provide value to ratepayers.While it is our understanding that the 2017
IRP is approved,we have yet to see a final approval order and are unaware of any potential
conditions that may come with the approval order.For the purposes of this report,we assume
there are no conditions that alter our recommendation here.
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A majority of the selected offers here are BTAs and Benchmark resources.These bids
offer at least two risks that are not generally present in power purchase agreements:(a)the risk
of capital and operating cost overruns and (b)failure to claim the full value of the Production
Tax Credit.Some of these risks can and will be managed in the BTA and EPC contracts the
company will sign,but the protection will not be as strong as in a PPA.Developers can promise
to deliver PTC complaint equipment and install by a certain time,but,several of these projects
are dependent on PacifiCorp's transmission arm completing the D2 Segment in order to achieve
deliverability.
In order to achieve a level of risk protection similar to a PPA for ratepayers,PacifiCorp
must guarantee that capital and O&M costs will not exceed the amounts forecasted here and that
ratepayers will be credited the full PTC values projected here as well regardless of whether or
not PacifiCorp has the taxable income to utilize the credits.For reference,we include the final
cost projections for each resource from the Company here as Attachment Five.
To be clear these should be "hard"guarantees as would be found in a commercial
contract.PacifiCorp should not be permitted to recover additional costs or not credit full value
of the PTC due to force majeure or change in law events.The risk regarding the PTC is
exceptionally important.As we have just seen with corporate tax reform (and the debate that
took place prior to the law's passage in which the PTC was considered briefly for major
overhaul),the value of the credit can change rapidly.
Again,the reason that the Company should take this risk without exception is that a
commercial developer will take this risk in a PPA.By way of example,the pro forma PPA in
this RFP has this to say about tax credits:
ii."Seller shall bear all risks,financial and otherwise throughoutthe Term,
associated with Seller's or the Facility's eligibility to receive PTCs,ITCs
or other Tax Credits,or to qualify for accelerated depreciation for Seller's
accounting,reporting or tax purposes.The obligationsof the Parties
hereunder,including those obligations set forth herein regarding the
purchase and price for and Seller's obligation to deliver Net Output,shall
be effective regardless of whether the sale of Output or Net Output from
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Exhibit No.67 Page 41 of 78
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the Facility is eligible for,or receives,PTCs,ITCs or other Tax Credits
during the Term."*
A related risk that was not analyzed is the risk of cost overruns for the D2 Segment.
Because there is no real competition for this service it is more likely that cost overruns would
occur here.These cost projections are important because they are a major driver of selection in
this RFP.If actual costs are higher it may turn out that a better solution would have been to
select more supply from outside the constrained area in Wyoming.Therefore,PacifiCorp should
also be held to its cost projection for the D2 Segment.The revenue requirement numbers used in
this analysis are included in Attachment Six.
In addition,the selected portfolio contains mostly options to be owned by the company.
As a result PTC benefits are projected to flow to customers for the first ten years of operation as
incurred.However,after the end of the ten-year PTC window these credits disappear and costs
increase.PacifiCorp currently projects a $125 million cost increase in 2031.If the Commission
believes such an increase would be unreasonable they should consider enacting some form of
rate mitigation efforts in the future.
Going forward,many of the issues in this RFP were primarily caused by the resource
acquisition function getting ahead of the resource planning and transmission planning function.
Soon after the PTC sunset was established at the end of2015,PacifiCorp's IRP team should
have begun to consider if this change would drive them to pursue more renewable supply.
Earlier consideration of this fact could have spurred debate about the proposal and possibly
achieved earlier IRP approval as well as earlier revision of transmission planning in system
impact studies.As it was the process was rushed and ultimately very few bids could be called
viable.
In the future parties should seek better alignment of all these functions.Other tax credits
(e.g.,the Investment Tax Credit)are also planned to sunset and PacifiCorp has more
transmission investment planned.As the next IRP process gets started parties should be asking
what schedule PacifiCorp plans to pursue.Will they pursue additional solar with the sunset of
9 Draft PPA section 2.8
39 P a ge
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Exhibit No.67 Page 42 of 78
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the ITC?Would it make sense to accelerate any other portions of the Gateway project?Earlier
consideration of these questions can lead to better and more transparent outcomes for all.
Finally,from a bid analysis standpoint any future modeling should at least consider the
effect of unleveling of tax credit benefits.As demonstrated in our requested sensitivities if the
production cost modeling does not consider the entire life of an asset then leveled benefits can
force a choice of a suboptimal offer.
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Attachment One
Qualified Wyoming Wind Options
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Attachment One contains commercially sensitive
information which is considered business
confidential information.The Company requests
special handling.Please contact Ted Weston at
(801)220-2963 to make arrangements to review.
Rocky Mountain Power
Exhibit No.67 Page 45 of 78
Case No.PAC-E-17-07
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Attachment Two
INITIAL FINAL SHORTLIST MODELING
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Exhibit No 67 Page 46 of 78
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O
Attachment Two contains confidential and
commercially sensitive information.The
confidential information is available to parties
who have signed a confidential agreement in this
docket.
O
The Company requests special handling of the
commercially sensitive information.Please
contact Ted Weston at (801)220-2963 to make
arrangements to review.
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Attachment Three
INTERCONNECTION ASSESSMENT
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O System Impact Study Report
Large Generator Interconnection
System Impact Restudy Report
Completed for
("InterconnectionCustomer")
Q0713
Proposed Point of Interconnection
Yellowcake -Antelope Mine 230 kV transmission line
(POI at approx.43.113 N,105.425 W)
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O System Impact Study Report
TABLE OF CONTENTS
1.0 DESCRIPTION OF THE GENERATING FACILITY .......................................................l
2.0 SCOPE OF THE STUDY.........................................................l
3.0 TYPE OF INTERCONNECTION SERVICE .....................................................2
4.0 DESCRIPTION OF PROPOSED INTERCONNECTION........................................................2
5.0 OTHER OPTIONS CONSIDERED ....................................................4
6.0 STUDY ASSUMPTIONS........................................................................................4
7.0 ENERGY RESOURCE (ER)INTERCONNECTION SERVICE....................................................5
7.1 Requirements .............................................................5
7.1.2 Generating Facility Modifications 5
7.1.3 Transmission System Modifications 7
7.1.4 Transmission Requirements 8
7.1.5 Existing Circuit Breaker Upgrades -Short Circuit 8
7.1.6 Protection Requirements 8
7.1.7 Data (RTU)Requirements 9
7.1.8 Substation Requirements 11
7.1.9 Communication Requirements 12
7.1.10 Metering Requirements 13
7.2 Cost Estimate (ER)........................................................15
7.3 Schedule..................................................................................................................................l6
7.3.1 Maximum Amount of Power that can be delivered into Network Load,with No Transmission
Modifications (for informational purposes only)16
O 7.3.2 Additional Transmission Modifications Required to Deliver 100%of the Power into Network
Load (for informational purposes only)16
8.0 PARTICIPATION BY AFFECTED SYSTEMS.........................................................l6
9.0 APPENDICES ................................................................16
9.1.1 Appendix 1:Higher Priority Requests 17
9.1.2 Appendix 2:Property Requirements 18
9.1.3 Appendix 3:Study Results 20
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Exhibit No.67 Page 50 of 78
PACIFICORP tn c nk
System Impact Study Report
1.0 DESCRIPTIONOF THE GENERATINGFACILITY
("Interconnection Customer")proposed interconnecting 350 MW of new generation to
PacifiCorp's ("Transmission Provider")Yellowcake -Antelope Mine 230 kV transmission line
(Point of Interconnection at approx.43.113 N,-105.425 W)located in Converse County,
Wyoming.The project ("Project")will consist of one hundred forty (140)GE 127 2.5 MW wind
turbines for a total output of 350 MW.The requested commercial operation date is December 31,
2020.
The restudy of this Project is performed due to the staging of the Energy Gateway West project.
Specifically,while the entire Gateway West project has a longer development timeline,the Aeolus-
Bridger/Anticline D.2 segment of the project (500 kV segment from the planned Aeolus substation
to the planned Anticline substation)now has an expected 2020 in-service date.The earlier
availability of the D.2 segment materially changes certain modeling assumptions that could impact
the cost or timing of the interconnection of certain projects whose previous studies depended on
Gateway West in its entirety.
Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by
the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Transmission Provider has assignedthe Project "Q0713."
O 2.0 SCOPE OF THE STUDY
The interconnection system impact restudy shall evaluate the impact of the proposed
interconnection on the reliability of the transmission system.The interconnection system impact
study will consider Base Case as well as all generating facilities (and with respect to (iii)below,
any identified network upgrades associatedwith such higher queued interconnections)that,on the
date the interconnection system impact study is commenced:
(i)are directly interconnected to the transmission system;
(ii)are interconnected to Affected Systems and may have an impact on the interconnection
request;
(iii)have a pending higher queued interconnection request to interconnect to the transmission
system;and
(iv)have no Queue Position but have executed an LGIA or requested that an unexecuted
LGIA be filed with FERC.
This interconnection system impact restudy will consist of a short circuit analysis,a stability
analysis,and a power flow analysis.The study will state the assumptions upon which it is based;
state the results of the analyses;and provide the requirements or potential impediments to
providing the requested interconnection service,including preliminary indication of the cost and
length of time that would be necessary to correct any problems identified in those analyses and
implement the interconnection.The study will also provide a list of facilities that are required as a
result of the Interconnection Request and a non-binding good faith estimate of the cost
responsibility and a non-bindinggood faith estimated time to construct.
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O System Impact Study Report
Based on the engineering judgement,the stability results for this project are not expected to change
and hence the restudy of stability analysis was not performed.
3.0 TYPE OF INTERCONNECTIONSERVICE
The InterconnectionCustomer has selected Energy Resource (ER)interconnection service.
4.0 DESCRIPTIONOF PROPOSED INTERCONNECTION
The InterconnectionCustomer's proposed Generating Facility is to be interconnected through a
new Point of Interconnection ("POI")substation between Yellowcake and Antelope Mine 230 kV
substations.Figure l below,is a one-line diagram that illustrates the interconnection of the
proposed Generating Facility to the Transmission Provider's system.
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Exhibit No.67 Page 52 of 78
PACIFICORP '"Ne c
System Impact Study Report
Q0713 POI Substation
Yellowcake 230 kV
,Antelope Mine
PointofChangeofInterconnectionOwnership
Tie Une Substation
7 3 Miles
00713 Substation 34.5kV
M
Collector
Figure 1 SimplifiedSystem One Line Diagram
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O System Impact Study Report
5.0 OTHER OPTIONSCONSIDERED
The followingalternative options were considered as potential points of interconnection for this
Project:None
6.0 STUDYASSUMPTIONS
All active higher priority transmission service and/or generator interconnection requests with
an in-service date of December 2020 or earlier will be considered in this study and are listed
in Appendix 1.If any of these requests are materiallymodified or withdrawn,the Transmission
Provider reserves the right to restudy this request,and the results and conclusions could
significantly change.
For study purposes there are two separate queues:
o Transmission Service Queue:to the extent practical,all network upgrades that are required
to accommodate active transmission service requests will be modeled in this study.
o Generation Interconnection Queue:Interconnection Facilities associated with higher
queued interconnection requests with an in-service date of December 2020 or earlier will
be modeled in this study.
The Interconnection Customer's request for energy or network resource interconnection
service in and of itself does not convey transmission service.Only a Network Customer may
make a request to designate a generating resource as a Network Resource.The provision of
transmission service may require additional studies and the construction of additional
upgrades.
Under normal conditions,the Transmission Provider does not dispatch or otherwise directlyOcontrolorregulatetheoutputofgeneratingfacilities.Therefore,the need for transmission
modifications,if any,which are required to provideNetwork Resource Interconnection Service
will be evaluated on the basis of 100 percent deliverability (i.e.,no displacement of other
resources in the same area).
This study assumes the Project will be integrated into the Transmission Provider's system at
agreed upon and/or proposed POI.
The Interconnection Customer will construct and own any facilities required between the Point
of Change of Ownership and the Project unless specifically identified by the Transmission
Provider.
Generator tripping may be required for certain outages.
All facilities will meet or exceed the minimum Western Electricity Coordinating Council
("WECC"),North American Electric Reliability Corporation ("NERC"),and the Transmission
Provider's performance and design standards.
The Energy Gateway West,Aeolus-Bridger/Anticline D.2 500 kV line from the proposed
Aeolus substation to the proposed Anticline substation and ancillary projects are assumed in
service in 2020.
All system improvements associated with the prior queued projects are in service before
Q0713.This includes a new Aeolus -Shirley Basin #2 230 kV line with 2xl557 ACSR
(Q0707),rebuild of the Standpipe-Freezeout-Aeolus 230 kV line to 2xl272 (Q0712),and
rebuild of the Aeolus -Shirley Basin #1 230 kV line with 2x1557 ACSR (Q0712).
All existing and proposed Remedial Action Schemes ("RAS")associated with prior queue
generation facilities are assumedto be in service for this study.
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O System Impact Study Report
A RAS that will arm approximately 640 MW of generation for the Energy Gateway D.2
outages was assumed to be in-service.
This report is based on information available at the time of the study.It is the Interconnection
Customer's responsibility to check the Transmission Provider's web site regularly for
Transmission System updates at http://www.pacificorp.com/tran.html
7.0 ENERGYRESOURCE (ER)INTERCONNECTIONSERVICE
Energy Resource Interconnection Service allows the Interconnection Customer to connect its
Generating Facility to the Transmission Provider's Transmission System and to be eligible to
deliver electric output using firm or non-firm transmission capacity on an as available basis.
7.1 Requirements
7.1.2 GENERATING FACILITYMODIFICATIONS
All interconnecting synchronous and non-synchronous generators are required to
design their Generating Facilities with reactive power capabilities necessary to
operate within the full power factor range of 0.95 leading to 0.95 lagging.This
power factor range shall be dynamic and can be met using a combination of the
inherent dynamic reactive power capability of the generator or inverter,dynamic
reactive power devices and static reactive power devices to make up for losses.
For synchronous generators,the power factor requirement is to be measured at the
O Point of Interconnection.For asynchronous generators,the power factor
requirement is to be measured at the high-side of the generator substation.The
Generating Facility must provide dynamic reactive power to the system in support
of both voltage scheduling and contingency events that require transient voltage
support,and must be able to provide reactive capability over the full range of real
power output.
If the Generating Facility is not capable of providing positive reactive support (i.e.,
supplying reactive power to the system)immediately followingthe removal of a
fault or other transient low voltage perturbations,the Generating Facility must be
required to add dynamic voltage support equipment.These additional dynamic
reactive devices shall have correct protection settings such that the devices will
remain on line and active during and immediately followinga fault event.
Generators shall be equipped with automatic voltage-control equipment and
normally operated with the voltage regulation control mode enabled unless written
authorization from the Grid Operator is given to operate in other control mode (e.g.
constant power factor control).The control mode of the generating units shall be
accurately represented in operating studies.The generators shall be capable of
operating continuously at their maximum power output at its rated field current
within +/-5%of its rated terminal voltage.
As required by NERC standard VAR-001-la,the Transmission Provider will
provide a voltage schedule for the Point of Interconnection.In general,Generating
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O System Impact Study Report
Facilities should be operated so as to maintain the voltage at the Point of
Interconnection,or other designated point as deemed appropriated by Transmission
Provider,between 1.00 per unit to 1.04 per unit.The Transmission Provider may
also specify a voltage and/or reactive power bandwidth as needed to coordinate
with upstream voltage control devices such as on-load tap changers.At the
Transmission Provider's discretion,these values might be adjusted depending on
operating conditions.Generating Facilities capable of operating with a voltage
droop are required to do so.Voltage droop control enables proportionate reactive
power sharing among generation facilities.Studies will be required to coordinate
voltage droop settings if there are other facilities in the area.It will be the
Interconnection Customer's responsibility to ensure that a voltage coordination
study is performed,in coordination with Transmission Provider,and implemented
with appropriate coordination settings prior to unit testing.
For areas with multiple generating facilities additional studies may be required to
determine whether or not critical interactions,including but not limited to control
systems,exist.These studies,to be coordinated with Transmission Provider,will
be the responsibility of the Interconnection Customer.If the need for a master
controller is identified,the cost and all related installationrequirements will be the
responsibility of the Interconnection Customer.Participation by the Generating
Facility in subsequent interaction/coordinationstudies will be required pre-and
post-commercial operation in order ensure system reliability.
To facilitate collection and validation of accurate modeling data to meet NERC
modeling standards,PacifiCorp,as the Planning Coordinator,requires Phasor
Measurement Units (PMUs)at all new Generating Facilities with an individual or
aggregate nameplate capacity of 75 MVA or greater.In addition to owning and
maintaining the PMU,the Generating Facility will be responsible for collecting,
storing and retrieving data as requested by the Planning Coordinator.Data must be
collected and be able to stream to Planning Coordinator for each of the Generator
Facility's step-up transformers measured on the low side of the GSU at a sample
rate of at least 30 samples per second and synchronized within +/-2 milliseconds
of the Coordinated Universal Time (UTC).Initially,the following data must be
collected:
Three phase voltage and voltage angle (analog)
Three phase current (analog)
Data requirements are subject to change as deemed necessary to comply with local
and federal regulations.
All generators must meet the Federal Energy Regulatory Committee ("FERC")and
WECC low voltage ride-through requirements as specified in the interconnection
agreement.As the Transmission Provider cannot submit a user written model to
WECC for inclusion in base cases,a standard model from the WECC Approved
Dynamic Model Library is required 180 days prior to trial operation.The list of
approved generator models is continually updated and is available on the
http://www.WECC.biz website.
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System Impact Study Report
Based on the turbine specification data provided by the Interconnection Customer,
the wind turbines do not have the capability to deliver 100%of the power to the
Point of Interconnection within the range of +/-0.95 power factor.The data
provided indicates that the wind turbines have a power factor capability of 0.98
capacitive and 0.96 inductive at rated power.
The study showed that the collector system injects approximately 17.2 MVAr (see
Figure 3 in Appendix 3)when it is connected to the transmission system without
the wind turbines being online.The Interconnection Customer will be required to
ensure that there is minimum reactive interchange under these conditions and that
the collector system of the Project is not contributing excessive reactive power into
the system increasing voltage under light load conditions.Failure of the Project to
minimize the reactive interchange under these conditions may result in the opening
of the POI breakers for the Project by the grid operator.
At low output level,the Project needs to ensure that it maintains the power factor
within +/-0.95 at the POI and minimize the reactive power flow towards the
transmission system to prevent high voltages.PacifiCorp has experienced high
voltages in the Wyoming area when the transmission system is lightly loaded with
low wind conditions.With low wind conditions the wind farms tend to supply
reactive power into the transmission system increasing the voltage.
The Interconnection Customer is responsible for the protection of the transmission
line between the Generating Facility and the Point of Interconnection substation.In
order to provide this protection the Interconnection Customer shall construct and
own a tie line substation to be located at the change of ownership (separate fenced
facility adjacent to the Transmission Provider's Point of Interconnection
substation)and include an Interconnection Customer owned protective device and
associated transmission line relaying/communications.The ground grids of the
Transmission Provider's Point of Interconnection substation and the
Interconnection Customer's tie line substation will be connected to support the use
of a bus differential protection scheme which will protect the overhead bus
connection between the two facilities
7.l.3 TRANSMISSION SYSTEM MODIFICATIONS
Construct a new POI substation with 3-breaker ring bus configuration between
Yellowcake and Antelope Mine substations (refer to Figure 1).
Expansion of the Windstar 230 kV substation with a new 230 kV bus.
Addition of two new 230 kV breakers at Windstar substation.
A new line termination at Windstar substation.
A new line termination at Shirley Basin substation and one 230 kV circuit
breaker.
Construction of a new,60-mile Windstar -Shirley Basin 230 kV line with 2-
1272 ACSR (Aluminum Conductor Steel Reinforced).
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O System Impact Study Report
Additionally,the Q0713 project triggers the need for the Transmission Provider's
planned Energy Gateway South project.This project consists of a new 400 mile
500 kV transmission line from the planned Aeolus substation in Wyoming to the
Transmission Provider's existing Clover substation in central Utah,with ancillary
improvements.
7.1.4 TRANSMISSION REQUIREMENTS
Construct approximately 1,200 feet of 230 kV transmission line to loop-in the
existing Antelope-Yellowcake230 kV line to the Q0713 POI substation.This will
require two guyed wood pole main line structures near structure 1/33 and a new
guyed wood pole structure at each end of the POI sub.
Construct approximately 60 miles of 230 kV transmission line from Windstar
substation to Shirley Basin substation.Conductor shall be double bundle 1272
ACSR "Bittern"Conductor.
The Interconnection Customer shall construct the tie line from the collector
substation to the tie-line substation.
The Interconnection Customer is required to build tie-line substation adjacent to the
new POI substation which will house the tie-line circuit breaker.The Transmission
Provider shall review the design of the tie-line span between the tie-line substation
O deadend tower and the new POI substation deadend tower.The Interconnection
Customer shall coil conductor,OPGW,shield wire,and line hardware with
sufficient quantities to span between the tie-line substation tower and the POI
substation tower.
The Transmission Provider will construct the span between the tie-line substation
tower and the new POI substation tower.
If any Transmission Provider lines are crossed by Interconnection Customer tie-
line,the Interconnection Customer line will cross under Transmission Provider's
line with at least NESC plus 3 foot clearance under all sag conditions of both lines.
7.1.5 EXISTINGCIRCUITBREAKER UPGRADES -SHORT CIRCUIT
The increase in the fault duty on the system as a result of the addition of the
Generating Facility with 140 GE 127 2.5 MW wind turbine generators fed through
140 -2600 kVA 34.5 kV -690 V transformers with 9.0%impedance then fed
through two 230 -34.5kV 120/115/200 MVA step up transformers with 8.0%
impedance will not push the fault duty above the interrupting rating of any of the
existing fault interrupting equipment.
7.1.6 PROTECTIONREQUIREMENTS
The installation of protective relays for line fault detection will be required at the
Transmission Provider's new 230 kV POI substation for the protection of the line
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to the Interconnection Customer's collector substation and the lines to Windstar
and Teckla substations.
The ground mats of the tie-line substation and the Q0713 POI substation must be
tied together so that metallic control cables can be used between the two facilities.
Bus differential relays will be applied to detect faults on this connection.With this
arrangement the Interconnection Customer must install line relays systems that will
detect and clear all faults on the tie lines in 5 cycles or less.A set of non-pilot step
distance line relays that will detect faults on the tie-line will also be applied at the
Q0713 POI substation.Should the Interconnection Customer desire a potential
alternative to the tie line substation in order to provide adequate protection to its
tie-line,the Interconnection Customer may petition the Transmission Provider for
an exemption to this arrangement.The Transmission Provider must review and
approve the Interconnection Customer's proposed alternative.Without approval of
the proposed alternative the tie-line substation configuration will be required.The
Interconnection Customer will need to supply and maintain sets of line relays to be
installed at Q0713 collector substation that will detect faults on the 230 kV line
back to the Q0713 POI substation.These line relays can be time coordinated with
the relays detecting faults on the transmission network and will not communicate
with the line relays to be installed at the Q0713 POI substation for the tie-line.
Protective relay elements in the line relays at the Q0713 POI substation will monitor
O voltage and frequency.If the voltage,magnitude or frequency is outside of the
normal operation range,this relay will trip the 230 kV breaker at the tie line
substation.
The lines to Windstar and Teckla substations will continue to use permission over
reaching logic line distance relays so the existing relays at Windstar and Teckla
substations will require setting adjustments to accommodate addition of the POI
substation.
The new 230 kV line between Windstar and Shirley Basin substations will be
protected with a line current differential relay system.
7.1.7 DATA (RTU)REQUIREMENTS
Data for the operation of the power system will be needed from the Generating
Facility and the new POI substation.The Interconnection Customer will install a
Transmission Provider approved data concentrator at the collector substation and
will install OPGW between the collector substation and tie line substation.The
data will then be tied into a Transmission Provider owned RTU at the new POI
substation.
In addition to the control and indication of the new 230 kV breakers at the POI
substation,the following data will be acquired through the POI substation RTU.
Also listed is the data that will be acquired from the collector substation.
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From POI substation:
Analogs:
Net Generation MW
Net Generator MVAr
Energy Register
From the Q0713 collector substation:
Analogs:
Transformer 1 Real power
Transformer l Reactive power
Transformer 2 Real power
Transformer 2 Reactive power
34.5 kV Real power 52 Al &N
34.5 kV Reactive power 52 A1 &N
34.5 kV Real power 52 A2 &C
34.5 kV Reactive power 52 A2 &C
34.5 kV Real power 52 D
34.5 kV Reactive power 52 D
34.5 kV Real power 52 E
34.5 kV Reactive power 52 E
34.5 kV Real power 52 F
34.5 kV Reactive power 52 F
O 34.5 kV Real power 52 G
34.5 kV Reactive power 52 G
34.5 kV Real power 52 H
34.5 kV Reactive power 52 H
34.5 kV Real power 52 I
34.5 kV Reactive power 52 I
34.5 kV Real power 52 J
34.5 kV Reactive power 52 J
34.5 kV Real power 52 K
34.5 kV Reactive power 52 K
34.5 kV Real power 52 L &Bl
34.5 kV Reactive power 52 L &B1
34.5 kV Real power 52 M &B2
34.5 kV Reactive power 52 M &B2
34.5 kV Reactive power 52 CAP l
34.5 kV Reactive power 52 CAP 2
A phase 230 kV transmission voltage
B phase 230 kV transmission voltage
C phase 230 kV transmission voltage
Average Wind speed
Average Plant Atmospheric Pressure (Bar)
Average Plant Temperature (Celsius)
Status:
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230 kV Transformer Breaker 1
230 kV Transformer Breaker 2
34.5 kV breaker 52 Al &N
34.5 kV breaker 52 A2 &C
34.5 kV breaker 52 D
34.5 kV breaker 52 E
34.5 kV breaker 52 F
34.5 kV breaker 52 G
34.5 kV breaker 52 H
34.5 kV breaker 52 I
34.5 kV breaker 52 J
34.5 kV breaker 52 K
34.5 kV breaker 52 L &Bl
34.5 kV breaker 52 M &B2
34.5 kV breaker 52 CAP 1
34.5 kV breaker 52 CAP 2
34.5 kV breaker Bus Tie
Line Relay Alarm
From the Tie Line Substation
Status:
230 kV Breaker
7.1.8 SUBSTATION REQUIREMENTS
90713 POI Substation:
To support the requested interconnection,the Project will require a new 230kV,
three breaker ring bus POI substation.The substation will be approximately270'x
470'(fence dimensions)based on the Interconnection Customer provided facility
requirements.The following is a list of the major equipment required for this
Project:
3 -230kV Power Circuit Breakers
6-230kV CCVTs
3 -230kV CT/VT Meteringunits
13 -230kV Switches
9 -230kV Lightning Arresters
l -230kV SSVT
l -Microwave Communication System
90713 Collector Station:
The Interconnection Customer will provide a separategraded,grounded and fenced
area along the perimeter of the Interconnection Customer's Generating Facility for
the Transmission Provider to install metering equipment.This area will share a
fence and ground grid with the Generating Facility and have separate,
unencumbered access for the Transmission Provider.AC station service for the
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control house will be supplied by the Interconnection Customer.DC power for the
control house will be supplied by the Transmission Provider.
Windstar Substation:
Install a new 230kV bay and line position to support a new 230kV line to Shirley
Basin substation.The followingmajor material will be required for this Project:
2 -230kV Power Circuit Breakers
3-230kV CCVTs
5 -230kV Switches
3 -230kV Lightning Arresters
Shirlev Basin Substation:
Install a new 230kV bay and line position to support a new 230kV line to Windstar
substation.The followingmajor material will be required for this Project:
1 -230kV Power Circuit Breaker
3-230kV CCVTs
5 -230kV Breaker Disconnect Switches
l -Motor Operated Line Disconnect Switch
3 -230kV Lightning Arresters
l -Line Relay Panel
l -Breaker Control Panel
7.1.9 COMMUNICATIONREQUIREMENTS
The Interconnection Customer is required to install OPGW between the POI
substation and the collector substation.ADSS fiber is required between the tie-line
substation and the POI substation.The Interconnection Customer is to supply 2 -
DNP3 circuits from the collector substation to the tie line substation and into the
POI substation building with the SCADA points required.
Communications to the Transmission Provider's existing communications will be
achieved through microwave.A new microwave communication system will be
installed at the POI substation.The POI microwave will connect to the
Transmission Provider's Flat Top communications site.The microwave tower at
Flat Top will need to be replaced.The path will then connect to the Transmission
Provider's Glenrock communications site and on through the existing system.The
existing microwave between Glenrock and Flat Top will be upgraded to a 6 Ghz
space diversity path.
Communication circuits are required between the POI,Windstar and Teckla
substations over the new microwave.Multiplexes,routers and channel banks will
be required at the POI,Teckla,and collector substations.At the POI substation a
48volt battery and charger is required for communication.At the collector
substation the Interconnection Customer will supply AC voltage for the
communication equipment.
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7.1.10 METERING REQUIREMENTS
Interchange Metering
Point of Interconnectionwill be at the Transmission Provider Q0713 substation.
Metering will be designed bidirectional and rated for the total net generation of the
Project.The bidirectional metering will also include the retail load (per tariff)
delivered to the Interconnection Customer.The Transmission Providerwill specify
and order all interconnection revenue metering,including the instrument
transformers,metering panels,junction box and secondary metering wire.The
primary metering transformers shall be combination 1000:5 CT/VT extended range
for high accuracy metering.
The metering design package will include two revenue quality meters,test switch,
with DNP real time digital data terminated at a metering interposition block.One
meter will be designated a primary SCADA meter and a second meter will be used
designated as backup with metering DNP data delivered to the alternate control
center.The metering data will include bidirectional KWH KVARH,revenue
quantities including instantaneous PF,MW,MVAR,MVA,including per phase
voltage and amps data.
An Ethernet connection is required for retail sales and generation accounting via
the MV-90 translation system.
O 90713 Transformer A metering:
Revenue metering is required on the high side of the step-up transformers.The
primary metering transformers shall be combination 230kV,500:5 CT/VT
extended range for high accuracy metering.
The Transmission Provider will design and procure the collector revenue metering
panels.The panels shall be located inside the collector control house.The collector
substation metering panel shall include two revenue quality meters,test switches,
and all SCADA metering data terminated at a metering interposition block.An
Ethernet phone line is required for retail sales and generation accounting via the
MV-90 translation system.
Q0713 Transformer B metering:
Revenue metering is required on the high side of the step-up transformer.The
primary metering transformers shall be combination 230kV,500:5 current ratio,
CT/VT extended range for high accuracy metering.
The Transmission Provider will design and procure the collector revenue metering
panels.The panels shall be located inside the collector control house.The collector
substation metering panel shall include two revenue quality meters,test switches,
and all SCADA metering data terminated at a metering interposition block.An
Ethernet phone line is required for retail sales and generation accounting via the
MV-90 translation system.
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Station Service/Construction Power
The Project is within the Transmission Provider service territory.Please note,prior
to back feed Interconnection Customer must arrange transmission retail meter
service for electricity consumed by the Project and arrange back up station service
for power that will be drawn from the transmission or distribution line when the
Project is not generating.Interconnection Customer must call the PCCC Solution
Center 1-800-625-6078 to arrange this service.Approval for back feed is contingent
upon obtaining station service.
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7.2 CosT ESTIMATE (ER)
The followingestimate represents only scopes of work that will be performed by the Transmission
Provider.Costs for any work being performed by the Interconnection Customer are not included.
Direct Assigned
Q0713 Collector substation $1,218,000
Add metering and control house
Q0713 POI substation $837,000
Add POI terminal and metering
Total Direct Assigned $2,055,000
Network Upgrade
Q0713 POI substation $9,702,000
Add 230kVring bus substation
Yellowcake -Antelope Mine transmission line $399,000
Loop transmission line in/out ofPOI substation
Windstar to ShirleyBasin 230kV line $28,726,000
Build 60 miles ofnew 230 kV line
O Windstar substation $4,194,000
Add new lineposition,update relay settings
Shirley Basin substation $2,120,000
Add new line position
Flat Top substation $904,000
Upgrade communications equipment
Teckla substation $48,000
Upgrade communications equipment,update relay settings
Glenrock substation $174,000
Upgrade communications equipment
Total Network Upgrade $46,267,000
Grand Total $48,322,000
*Any distribution line modifications identified in this report will require a field visit analysis in
order to obtain a more thorough understanding of the specific requirements.The estimate provided
above for this work could change substantially based on the results of this analysis.Until this field
analysis is performed the Transmission Provider must develop the Project schedule using
conservative assumptions.The Interconnection Customer may request that the Transmission
Provider perform this field analysis,at the Interconnection Customer's expense,prior to the
execution of an Interconnection Agreement in order to obtain more cost and schedule certainty.
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System Impact Study Report
Note:Costs for any excavation,duct installation and easements shall be borne by the
Interconnection Customer and are not included in this estimate.This estimate is as accurate as
possibly given the level of detailed study that has been completed to date and approximates the
costs incurred by Transmission Provider to interconnect this Generating Facility to Transmission
Provider's electrical distribution or transmission system.A more detailed estimate will be
calculated during the Facilities Study.The Interconnection Customer will be responsible for all
actual costs,regardless of the estimated costs communicated to or approved by the Interconnection
Customer.
7.3 SCHEDULE
The Transmission Provider estimates it will require approximately 60-78 months to permit,
design,procure and construct the facilities described in the Energy Resource sections of
this report followingthe execution of an Interconnection Agreement.The schedule will be
further developed and optimized during the Facilities Study.
Please note,the time required to perform the scope of work identified in this report as well
as the current anticipated in-service date of the Transmission Provider's Gateway South
transmission line (2024)does not support the Interconnection Customer's requested
Commercial Operation date of December 31,2020.
7.3.1 MAXIMUM AMOUNTOF POWER THAT CAN BE DELIVERED INTO NETWORK
O LOAD,WITH No TRANSMISSION MODIFICATIONS(FOR INFORMATIONAL
PURPOSES ONLY)
Zero (0)MW can be delivered on a firm basis to the Transmission Provider's
network loads with additionaltransmission modifications.
7.3.2 ADDITIONALTRANSMISSION MODIFICATIONSREQUIRED TO DELIVER100%
OF THE POWER INTO NETWORK LOAD (FOR INFORMATIONAL PURPOSES
ONLY)
In order to deliver 100%of the power into Network Load,in addition to the
mitigation identified in section 5.1.1.2,the completion of additional Transmission
Provider Energy Gateway projects and other system improvements would also be
required.
8.0 PARTICIPATIONBY AFFECTEDSYSTEMS
Transmission Provider has identified the following affected systems:WAPA,Black Hills,Tri-
State,and Basin Electric
A copy of this report will be sharedwith each Affected System.
9.0 APPENDICES
Appendix 1:Higher Priority Requests
Appendix 2:Property Requirements
Appendix 3:Study Results
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9.1.1 APPENDIX 1:HIGHER PRIORITY REQUESTS
All active higher priority transmission service and/or generator interconnection requests will be
considered in this study and are identified below.If any of these requests are withdrawn,the
Transmission Provider reserves the right to restudy this request,as the results and conclusions
contained within this study could significantly change.
Transmission/Generation Interconnection Queue Requests considered:
Q0542 (240 MW)-QF/NR
Q0706 (250 MW)-ER
Q0707 (250 MW)-ER
Q0708 (250 MW)-ER
Q0712 (520 MW)-ER
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9.1.2 APPENDIX 2:PROPERTY REQUIREMENTS
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements
Rights of way easements will be acquired by the Interconnection Customer in the Transmission
Provider's name for the construction,reconstruction,operation,maintenance,repair,replacement
and removal of Transmission Provider's Interconnection Facilities that will be owned and operated
by PacifiCorp.Interconnection Customer will acquire all necessarypermits for the Project and will
obtain rights of way easements for the Project on Transmission Provider's easement form.
Real Property Requirements for Point of Interconnection Substation
Real property for a Point of Interconnection substation will be acquired by an Interconnection
Customer to accommodate the Interconnection Customer's Project.The real property must be
acceptable to Transmission Provider.Interconnection Customer will acquire fee ownership for
interconnection substation unless Transmission Provider determines that other than fee ownership
is acceptable;however,the form and instrument of such rights will be at Transmission Provider's
sole discretion.Any land rights that Interconnection Customer is planningto retain as part of a fee
property conveyance will be identified in advance to Transmission Provider and are subject to the
Transmission Provider's approval.
The InterconnectionCustomer must obtain all permits required by all relevant jurisdictions for the
planned use including but not limited to conditional use permits,Certificates of Public
O Convenience and Necessity,California Environmental Quality Act,as well as all construction
permits for the Project.
InterconnectionCustomer will not be reimbursed through network upgrades for more than the
market value of the property.
As a minimum,real property must be environmentally,physically,and operationallyacceptable to
Transmission Provider.The real property shall be a permitted or able to be permitted use in all
zoning districts.The Interconnection Customer shall provide Transmission Provider with a title
report and shall transfer property without any material defects of title or other encumbrances that
are not acceptable to Transmission Provider.Property lines shall be surveyed and show all
encumbrances,encroachments,and roads.
Examples of potentially unacceptable environmental,physical,or operational conditions could
include but are not limited to:
1.Environmental:known contamination of site;evidence of environmental
contamination by any dangerous,hazardous or toxic materials as defined by any
governmental agency;violation of building,health,safety,environmental,fire,land
use,zoning or other such regulation;violation of ordinances or statutes of any
governmental entities having jurisdiction over the property;underground or above
ground storage tanks in area;known remediation sites on property;ongoing
mitigation activities or monitoring activities;asbestos;lead-based paint,etc.A
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phase I environmental study is required for land being acquired in fee by the
Transmission Provider unless waived by Transmission Provider.
2.Physical:inadequate site drainage;proximity to flood zone;erosion issues;wetland
overlays;threatened and endangered species;archeological or culturallysensitive
areas;inadequate sub-surface elements,etc.Transmission Provider may require
Interconnection Customer to procure various studies and surveys as determined
necessary by Transmission Provider.
Operational:inadequate access for Transmission Provider's equipment and vehicles;existing
structures on land that require removal prior to building of substation;ongoing maintenance for
landscaping or extensive landscape requirements;ongoing homeowner's or other requirements or
restrictions (e.g.,Covenants,Codes and Restrictions,deed restrictions,etc.)on property which are
not acceptable to the Transmission Provider.
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9.1.3 APPENDIx 3:STUDY RESULTS
Power Flow Study Results
A Western Electricity Coordinating Council (WECC)approved 2015 Heavy Summer case was
used to perform the power flow studies using PSS/E version 33.7.The 2015 Heavy Summer case
was modified for the study.
Power flow studies were performed on both peak and off-peak load cases.The study was
performed assuming the Energy Gateway D.2 Projects are in-service.The local 500 kV,345 kV,
230 kV and 115 kV transmission system outages were considered during the study.
N-0 Results:
Under N-0 conditions with the Q0713 project in service there is a 101%overload on the Difficulty
-Amasa 230 kV line.A new approximately60-mile 230 kV line from Windstar to Shirley Basin
constructed with 2-1272 ACSR will mitigate this issue as well as some N-1 issues discussed
below.
The data provided by the Interconnection Customer indicated that the generator does not have
adequate reactive capability to deliver 100%of its power output at +/-0.95 power factor.Hence,
external shunt compensation which is dynamic in nature will be required in order to control the
voltage and provide adequate reactive capability to maintain the voltage at the POI with a +/-0.95
power factor on the high side of the step-up transformer.
Figure 3 below,shows injection of approximately 17.2 MVAr into the transmission system was
observed if the collector system was connected with no generation from the Project.The addition
of 17.2 MVAr on the transmission system under light load conditions could cause high voltages.
The Project must control the voltage at the POI within the required voltage range provided by the
Transmission Operator.
N-1 Results:Assuming Energy Gateway D.2 segment and the system improvements associated
with the prior queued projects are in service,the followingissues were identified.
o Outage of the Amasa -Difficulty-ShirleyBasin 230 kV line overloads the Dave Johnston
South Tap -Refinery Tap to 101%.Low voltages in the Spence -Buffalo Head area also
observed.The new Windstar -Shirley Basin 230 kV line identified as mitigation under
the N-0 results will resolve these issues.
Outage of the Aeolus -Anticline 500 kV line,the Aeolus 230/500 kV transformer or the
Anticline 345/500 kV transformer,post generation dropping of 640 MW (Aeolus RAS),
results in multiple 230 kV line overloads.Construction of the Transmission Provider's
planned Energy Gateway South 500 kV line from Aeolus to Clover,approximately400
miles,will mitigate these issues.
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Exhibit No.67 Page 70 of 78
Case No.PAC-E-17-07
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O System Impact Study Report
N-2 Results:No N-2 thermal or voltage issues were observed in the studies.
65060 1.010
ANT MINE 232.20
99749
QC713_POI
99750 99751 99752 99753
-100.34 Q0713_COL Q0713_COL 00713_GEN Q0713_GEN
30.11 0.01 -0.00 0.00 -e -0.00 0.00 -0.00 -0.00 «e 0.00
-17.17 15.69 -15.69 15.77 -15.77 -0.00 0.00 -0.00
100.33
-12.94 1.021 1.026 1.026 1.026
234.75 35.39 35.40 0.71
1.019
234.37
66745 1.019
YELLOWCK '"234.40
Figure 3:Chargingfrom Q713 collector systems
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Exhibit No.67 Page 71 of 78
Case No.PAC-E-17-07
Witness:Rick T.Link
O
Attachment Four
UPDATED FINAL SHORTLIST
O
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Rocky Mountain Power
Exhibit No 67 Page 72 of 78
Case No.PAC-E-17-07
Witness:Rick T.Link
O
Attachment Four contains confidential and
commercially sensitive information.The
confidential information is available to parties
who have signed a confidential agreement in this
docket.
O
The Company requests special handling of the
commercially sensitive information.Please
contact Ted Weston at (801)220-2963 to make
arrangements to review.
O
Rocky Mountain Power
Exhibit No.67 Page 73 of 78
Case No.PAC-E-17-07
Witness:Rick T.Link
O
Attachment Five
FINAL COSTS FOR SHORTLISTED BIDS
O
Rocky Mountain Power
Exhibit No 67 Page 74 of 78
Case No.PAC-E-17-07
Witness:Rick T Link
O
Attachment Five contains commercially sensitive
information which is considered business
confidential information.The Company requests
special handling.Please contact Ted Weston at
(801)220-2963 to make arrangements to review.
Rocky Mountain Power
Exhibit No.67 Page 75 of 78
Case No.PAC-E-17-07
Witness:Rick T.Link
O
Attachment Six
TRANSMISSION REVENUE REQUIREMENTS
O
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Rocky Mountain Power
Exhibit No 67 Page 76 of 78
Case No.PAC-E-17-07
Witness:Rick T Link
O
Attachment Six contains commercially sensitive
information which is considered business
confidential information.The Company requests
special handling.Please contact Ted Weston at
(801)220-2963 to make arrangements to review.
O
O
Rocky Mountain Power
Exhibit No.67 Page 77 of 78
Case No.PAC-E-17-07
Witness:Rick T.Link
O
Appendix A
BENCHMARK BID ANALYSIS
O
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Rocky Mountain Power
Exhibit No.67 Page 78 of 78
Case No.PAC-E-17-07
Witness:Rick T.Link
O
AppendixA contains confidential and
commercially sensitive information.The
confidential information is available to parties
who have signed a confidential agreement in this
docket.
O
The Company requests special handling of the
commercially sensitive information.Please
contact Ted Weston at (801)220-2963 to make
arrangements to review.
O