HomeMy WebLinkAbout20120629Schoenbeck Rebuttal.pdfIdaho Public Utilities Commission
P.O. Box 83720
Boise, Idaho 83720-0074
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June 28, 2012
Capitol Law C. Tom Arkoosh
www.capitollawgroup.com • tarkooshcapito1lawgroup.com roup, PLLC
Re: Our Client: Twin Falls Canal Company and North Side Canal Company
CLG File No. 6417.000
Dear Commissioners:
Enclosed please find an original and nine copies of the Rebuttal Testimony of Donald W.
Schenbeck.
If you have any questions or comments, please do not hesitate to contact me.
Sincerely,
Capitol Law Group, PLLC
Lori Thomas
Paralegal to C. Tom Arkoosh
CTA/lbt
Enclosures
205 North 10" Street, 4 " Floor, P0 Box 2598, Boise, ID 83701-2598 • Tel: (208) 424.8872 • Fax: (208) 424.8874
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2912 JU 29 AM 8: 37
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
COA4
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE
SURROGATE AVOIDED RESOURCES (SAR)
AND INTEGRATED RESOURCE PLANNING Case No. GNR-E-11-03
(IRP) METHODOLOGIES FOR
CALCULATING PUBLISHED AVOIDED
COST RATES
REBUTTAL TESTIMONY OF
IPIS)M P I[S1flI11
ON BEHALF OF
NORTHSIDE CANAL COMPANY
TWIN FALLS CANAL COMPANY
RENEWABLE ENERGY COALITION
June 28, 2012
CASE NO. GNR-E-11-03
REBUTTAL TESTIMONY OF
DONALD W. SCHOENBECK
CONTENTS
I.INTRODUCTION AND SUMMARY ...................................................................... 1
II.MODIFIED RECOMMENDATIONS ......................................................................3
III.NO CHANGES TO PRIOR RECOMMENDATIONS.............................................8
Iv, ISSUES RAISED BY OTHER PARTIES.................................................................12
Donald W. Schoenbeck Page i of I
1 PREFILED REBUTTAL TESTIMONY OF
2 DONALD W. SCHOENBECK
3 I. INTRODUCTION AND SUMMARY
4 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
5 1 A. My name is Donald W. Schoenbeck. I am a member of Regulatory &
6 Cogeneration Services, Inc. ("RCS"), a utility rate and economic consulting firm.
7 My business address is 900 Washington Street, Suite 780, Vancouver, WA 98660.
8 Q. HAVE YOU PREVIOUSLY SUBMITTED TESTIMONY IN THIS
9 PROCEEDING?
10 A. Yes. I provided direct testimony in this proceeding on behalf of Northside Canal
11 Company, Twin Falls Canal Company and Renewable Energy Coalition
12 (collectively, "QF Companies"). This rebuttal testimony is being submitted on
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behalf of these same companies.
14 Q. WHAT TOPICS WILL YOUR TESTIMONY ADDRESS?
15 A. Following this introduction and summary, my rebuttal testimony is organized in
16 three sections. First, I will address matters where I have altered or modified the
17 recommendations set forth in my direct testimony from having reviewed the
18 prefiled direct testimony and subsequent discussions with other parties in this
19 proceeding. These issues have to do with the source of gas prices for use under
20 the SAR and IRP methods, allowable updates under the IRP method and avoided
21 capacity cost. The next section of this testimony will address issues where my
22 position has not changed even after reviewing other party's thoughts on certain
23 matters. These issues have to do with contract term, REC ownership, the
24 eligibility cap for fixed price contracts and Idaho Power's proposed Schedule 74.
Donald W. Schoenbeck Page 1 of 14
Finally, in the last section, I discuss an issue raised by another party that I had not
addressed in my direct testimony. Specifically, Dr. Reading's proposal with
regard to transmission network upgrades.
Q. PLEASE BRIEFLY SUMMARIZE YOUR RECOMMENDATIONS
ADDRESSED IN THIS TESTIMONY.
A. First, regarding modifications to my prior direct testimony, I recommend the
following:
8 The Energy Information Administration's Annual Energy Outlook ("ETA
9 AEO") forecast should be used as the source of gas prices under the SAR
10 method and for any updates under the IRP method.
11 In addition to gas prices and QF contracts, updates to the IRP method can
12 include newly executed non-QF contracts with a term of at least five years
13 and known customer specific load changes that in aggregate are at least 25
14 MWs.
15 Avoided capacity cost recognition and pricing can be done as set forth in
16 Staffs revised updated avoided cost EXCEL spreadsheet model
17 ("Updated Avoided Cost Model version 2.0").
18
Second, I disagree with Staffs direct testimony where Staff advocates the
19 following policy changes: (a) that the Commission authorize a maximum QF
20 contract term of just five years under the IRP method, (b) that the seller is
21 compensated for RECs under the IRP method, (c) that the eligibility cap for fixed
22 published rates be maintained at just 100 kWs for wind and solar projects, and (d)
23 Idaho Power's proposed QF curtailment tariff, Schedule 74, should be approved.
24 For the reasons set forth in my direct testimony, and as further explained in this
25 rebuttal testimony, the Commission should not adopt any of these proposals. I re-
26 affirm my direct testimony in advocating that contracts should be offered for up to
27 twenty years under either pricing method, REC ownership should be retained by
Donald W. Schoenbeck Page 2 of 14
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the seller, the eligibility cap for fixed published prices should be 10 MW for all
resource types and Schedule 74 should not be approved by the Commission.
Finally, Dr. Reading's testimony recommends that a QF be entitled to full
recovery of construction contributions paid by the QF for network transmission
upgrades. The QF Companies fully support Dr. Reading's recommendation on
this issue.
II. MODIFIED RECOMMENDATIONS
Q. HAVE YOU REVIEWED THE DIRECT TESTIMONY OF THE NON-
UTILITY PARTIES FILED IN THIS PROCEEDING IN MAY 2012?
A. Yes, I have.
Q. HAS THIS REVIEW ALTERED OR CHANGED ANY OF THE
RECOMMNEDATIONS SET FORTH IN YOUR DIRECT TESTIMONY?
A. Yes. From having reviewed and considered the prefiled direct testimony of Staff
and Dr. Reading and from having additional discussions with parties, I believe it
is appropriate to modify three recommendations I made in direct testimony
regarding the source of gas prices, what updates or changes should be allowed
under the IRP method and how avoided capacity costs should be determined and
priced.
Q. HOW DID THE PARTIES TESTIMONY INFLUENCE YOUR THINKING
WITH REGARD TO GAS SOURCE?
A. Both Staff witnesses and Dr. Reading proposed using prices from the EIA AEO as
had also been recommended by Avista under the SAR method, including any
updates. (See Dr. McHugh pages 3-5, Mr. Sterling page 8, Dr. Reading page 19
and Mr. Kalich page 34) Based upon my further discussions, I believe all these
parties are now in agreement that the specific price series to use would be the
Donald W. Schoenbeck Page 3 of 14
Mountain division series for electric power ("EIA Forecast") as detailed by Dr.
McHugh under the SAR method. (See Dr. McHugh page 5, lines 7-10). Given
this consensus and my review of this source, I agree that the ETA Forecast
Lf achieves most of the objectives I was seeking in an independent third party source
5 and can be used to determine avoided cost rates.
6 Q. ARE THESE PARTIES IN AGREEMENT THAT THE EIA AEO SHOULD
7 BE USED FOR IRP UPDATES AS WELL?
8 A. No, I do not believe this is the case. Staff advocates that the utilities do not have
9 to use the ETA AEO (see Mr. Sterling page 23, lines 1-6) while Dr. Reading
10 appears to advocate that it could be used in the IRP update (see Dr. Reading page
11 26, line 15 to page 27, line 5). The Avista testimony did not specifically address
12 IRP gas price updates.
13 Q. WHAT IS YOUR RECOMMENDED SOURCE OR METHOD FOR AN
14 IRP GAS PRICE UPDATE?
15 A. I recommend the ETA AEO be used for IRP updates as well. I fully understand
16 and expect that the utility will use its preferred method for deriving gas prices for
17 its initial IRP filing. During the IRP development process, parties are generally
18 provided the opportunity to examine and comment on many inputs including the
19 gas price forecast. However, an IRP update does not allow for this opportunity.
20 Consequently, I believe the Commission should require that any IRP update
21 should use precisely the same gas price source as under the SAR update. Given
22 that any IRP update will be in place for only one or two years, use of an
23 independent third party source should not result in any rate payer harm while on
Donald W. Schoenbeck Page 4 of 14
the other hand it would eliminate any potential game playing by the utility
2 regarding this most critical input variable.
3 Q. WHAT DID YOUR DIRECT TESTIMONY RECOMMEND WITH
4 RESPECT TO ALLOWABLE IRP UPDATES?
5 A. My direct testimony recommended that only two items may be updated: the gas
6 price forecast and the inclusion of any newly executed QF PPAs.
7 Q. HAVE PARTIES PROPOSED INCLUDING OTHER ITEMS FOR
8 ALLOWABLE IRP UPDATES?
9 A. Yes. Staff is proposing that fuel price forecasts, load forecasts and any new long-
10 term purchase or sale contract obligation can be updated (see Mr. Sterling pages
11 22-25). More specifically, Staff is proposing that fuel prices and load forecasts
12 should be updated once per year and any new purchase or sale contract
13 commitments made at least one year in advance and at least one year's duration
14 should be included in an IRP update, whenever the commitment is made.
15 Q. WHAT ARE YOUR THOUGHTS REGARDING THE STAFF'S
16 ALLOWABLE UPDATE ITEMS?
17 A. I previously addressed my concern about allowing the utility to make updates
18 based on internally generated forecasts for items that have no impact other than to
19 greatly complicate the QF PPA negotiation process and allow for potential game
20 playing of the avoided cost determination. Under the Staff proposal, this could
21 readily happen by a utility lowering an internally generated coal price forecast or
22 load forecast in an IRP update. With regard to allowing non-QF purchase or sale
23 contract commitments in the update, I believe Staffs proposed inclusion of utility
24 wholesale purchase contracts with terms of such short duration does not allow a
25 utility to actually avoid capacity. For these reasons, I disagree with these aspects
Donald W. Schoenbeck Page of 14
1 of Staffs update proposal. However, I am willing to recommend additional IRP
2 update items addressing both these areas as long as they can be readily verified
and not subject to any possible manipulation.
4 Q. WHAT ADDITIONAL ITEMS WOULD YOU RECOMMEND COULD BE
5 INCLUDED IN AN IRP UPDATE?
6 A. I recommend that customer specific known load changes of at least 25 MWs (up
7 or down) be included as well as any executed non-QF purchase or sale contract
8 commitments of at least 5 or more years in duration.
9 Q. WHY DID YOU SELECT 25 MWS AS THE VALUE FOR LOAD
10 CHANGES?
11 A. There were three reasons. First, it is the size of the standard market energy
12 trading amount. As such, this is at least one measure for considering it to be a
13 meaningful amount. The second reason has to do with the granularity with which
14 production simulation models can produce meaningfully different results. Very
15 modest load changes simply do not have a material impact on the result. Finally,
16 load changes of this magnitude could well be reported and widely known even
17 prior to the IRP update. This will facilitate the verification of the load change I
18 believe is critical to minimizing disputes over the IRP update.
19 Q. MUST THE KNOWN LOAD CHANGE BE JUST A SINGLE
20 CUSTOMER?
21 A. No. The 25 MW value can be an aggregated value from the departure, addition or
22 expansion of several customers but it must be known and measurable. It cannot
23 be a projection of load changes for a given customer class or sub-class from
24 updating typical load forecast input assumptions.
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Q. WHY DO YOU DISAGREE WITH THE STAFF PROPOSAL TO ALLOW
UTILITY WHOLESALE PURCHASES WITH A TERM OF JUST ONE
YEAR TO BE INCLUDED IN IRP UPDATES?
A. Allowing such market-based wholesale purchases with short terms in the IRP
process does not eliminate the utility's need for capacity. PPAs with terms of just
one, two, three or even four years are shorter than the typical time it takes to plan
for and build a resource to meet a capacity deficit position. Consequently, the
only effect of including PPAs with this short of duration in the IR.P update would
be to artificially lower the avoided capacity costs included in a QF PPA. This is
inappropriate. However, I must emphasize that the non-QF PPAs I am
recommending be allowed in the IRP update must be fully executed and have
received Commission approval.
Q. BASED ON THIS REASONING, WOULD YOU AGREE THAT QF PPAS
WITH TERMS LESS THAN FIVE YEARS DO NOT AVOID CAPACITY
EITHER?
A. Yes, I would, provided that the Commission elects a reasonable QF PPA contract
term in this proceeding. If non-QF power purchase contracts less than five years
duration are not included in the IRP calculation of avoided costs, and the
Commission requires utilities to sign QF contracts with terms up to 20 years, then
I agree that QF PPAs with terms less than five years should not receive any
avoided capacity payment or credit. On the other hand, if the Commission adopts
the Idaho Power and Staff proposals to limit the maximum contract term to just
five years, than avoided capacity costs should be included in the contractual
prices because the QF and the utility are limited to this restrictive term.
Q. HOW HAVE YOUR RECOMMNEDATIONS CHANGED WITH REGARD
TO AVOIDED CAPACITY COST ALLOCATION AND PRICING?
Donald W. Schoenbeck Page 7 of 14
1 V A. I believe that my recommendations to determine capacity need, allocation and
2 pricing based on the results of a loss of load or unserved energy analysis is
3 analytically superior to the existing methods employed by the utilities and Staff.
4 However, I am readily aware that the results from such a probabilistic "black box"
5 simulation can be subject to and sensitive to certain critical assumptions used in
6 the analysis including inter-balancing area market availability. In addition, from
7 discussions with Staff, including the examination of Staffs revised avoided cost
8 EXCEL spreadsheet model ("Updated Avoided Cost Model version 2.0"), my
9 primary concern with Staffs avoided capacity need determination has been
10 addressed. Accordingly, I find Staffs revised model a simple, transparent and
11 straightforward approach to determine capacity need, allocation and pricing.
12 III. NO CHANGES TO PRIOR RECOMMENDATIONS
13 Q. HAS YOUR REVIEW OF SOME OF THE PARTIES' TESTIMONY
14 IDENTIFIED AREAS OF SIGNIFICANT DISAGREEMENT WITH YOUR
15 DIRECT TESTIMONY?
16 A. Yes. Staff has accepted four utility proposals which I continue to oppose. These
17 are: (i) that IRP priced contracts be limited to a maximum term of just five years,
18 (ii) that RECs are deemed transferred to the purchasing utility under the IRP
19 method,(iii) that a fixed price eligibility cap of just 100 kW apply to wind and
20 solar resources, and (iv) that Idaho Power's proposed Schedule 74 for curtailment
21 of QF generation be adopted. In large part, I have addressed the reasons why
22 each of these proposals is inequitable, inappropriate and unfair in my direct
testimony. I will limit my rebuttal testimony to specific points raised by Staff that
24 I did not previously address.
Donald W. Schoenbeck Page 8 of 14
1 Q. WHAT COMMENTS DO YOU HAVE WITH REGARD TO STAFF'S
2 MAXIMUM FIVE YEAR CONTRACT TERM FOR IRP BASED
3 CONTRACTS?
4 A. I find Staffs proposal to allow a maximum 20 year contract term under the SAR
5 based method but only a maximum five year term under the IRP based method
6 quite troubling. As stated in my direct testimony, a 20 year term is fair and
7 appropriate. A five year term is not. It appears the crux of Staffs proposal is that
8 the IRP contract term should be used "to control the pace ofPURPA
9 development" as set forth on page 29 of Mr. Sterling's testimony. Staff claims
10 this control is needed because the power "is not needed to serve customers" and
11 the depressed economy "strain customers' ability to pay." Of course, we are all
12 sympathetic to the economic woes the Pacific Northwest has been experiencing
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for some time. However, Staff must acknowledge that avoided costs are set such
14 that the ratepayer is indifferent as to whether the power came from a QF PPA or
15 the alternative resource.
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Staffs testimony does state that when the Commission had previously
17 imposed a maximum contract term of just five years from September 1996 to May
18 2002, QF development all but ceased as only one contract was executed during
19 this period. (See Mr. Sterling, pages 27-28) While Staff asserts this was
20 attributable to many factors, one of the significant factors was low natural gas
21 prices, a condition that is present today as well. The ability to finance and recover
22 capital costs based on the avoided costs proposed in this proceeding with today's
23 gas prices is impossible over a five year period. Just has had occurred in 1996 to
24 2002, adoption of a maximum five year contract term will not "control the pace"
Donald W. Schoenbeck Page 9 of 14
1 of QF development above the fixed price eligibility cap but, rather, it will end it.
2 Q. IS THERE ANOTHER FACTOR THAT WILL BE CONTROLING THE
3 PACE OF QF DEVELOPMENT?
4 A. Yes. Most parties to this proceeding are advocating no avoided capacity costs
5 should be paid during periods of sufficiency. If this is adopted by the
6 Commission, this feature will naturally control the pace of QF development
7 without having to put in place a totally unreasonable five year contract term.
8 Q. WHAT IS STAFF'S POSITION WITH REGARD TO ENVIRONMENTAL
9 ATTRIBUTES INCLUDING RECS?
10 A. The Staff believes the Commission should decide the question of REC ownership.
11 For contracts under the IRP method, Staff asserts the cost is included in
12 computing the avoided cost rates and therefore the utility should be entitled to the
13 RECs. (See Mr. Sterling, page 46, lines 6-20) Under the SAR method, Staffs
14 testimony states the utility should pay an additional amount "if it wished to own
15 the RECs." (See Mr. Sterling, page 46, line 21 through page 47, line 8)
16 Q. DO YOU AGREE WITH STAFF'S ASSERTION THAT THE COSTS OF
17 RECS ARE INCLUDED IN THE AVOIDED COST RATES DERIVED
18 UNDER THE IRP METHOD?
19 A. No. Staffs logic is dependent upon the assertion that renewal resources are
20 reflected in the utility resource plans and therefore are implicitly within the
21 resulting avoided costs under the IRP method. This assertion is simply not
22 correct. Earlier in the testimony, Staff acknowledges that under the utility IRP
23 proposals "capacity and energy values are calculated independently" of each
24 other. (See Mr. Sterling, page 17, lines 13-19). Under both the Idaho Power and
25 Staff proposals, the capacity value is based on a SCCT and not the costs of the
Donald W. Schoenbeck Page 10 of 14
renewable resources in the utility's preferred portfolio. Under both the Staff and
2 Idaho Power proposals, energy costs are derived from the incremental cost or
3 market price of short-term energy. The resources supplying this energy are gas-
4 fired or coal fired resources. These resources do not generate any RECs. As the
5 resources used to derive the avoided costs under the IRP method do not produce
6 RECs and Staff has proposed no incremental adjustment to the resulting IRP
7 avoided costs, the REC ownership right should stay with the seller under the IRP
8 method.
9 Q. DO YOU AGREE WITH THE STAFF POSITION THAT UTILITIES
10 SHOULD HAVE TO PAY FOR REC OWNERSHIP UNDER THE SAR
11 METHOD?
12 A. Yes, I do. If the REC market was liquid and transparent, it would make sense to
13 provide a REC purchase option under the published fixed rates for QFs choosing
14 to transfer (sell) RECs to the utility. However, it has been my experience that the
15 REC market is illiquid and not transparent. Because of this market situation, I
16 believe the fairest approach for all parties (QF, utility and ratepayers) is to simply
17 !
allow the seller to retain the ownership of any associated RECs and all other
18 environmental attributes. As noted in my direct testimony, this is my
19 recommendation under both IRP and SAR methods.
20 Q. DO YOU HAVE ANY COMMENTS REGARDING STAFF'S SUPPORT
21 FOR CONTINUING THE 100 KW PUBLISHED RATE ELIGIBILITY
22 CAP FOR WIND AND SOLAR RESOURCES?
23 A. Yes. Staff's reasoning is based on the continuing existence of a financial
24 incentive to game play through the disaggregation of resource capability. No
25 party to this proceeding has objected to requiring annual gas price updates under
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1 both the SAR and IRP methods. If these updates are done simultaneously, I
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believe any financial incentive to disaggregate will be eliminated as the avoided
3 energy costs should be very close under either method. Under these
4 circumstances, a uniform eligibility cap across all technologies should be re-
5 instated by the Commission. As explained in my direct testimony, I recommend
6 this cap be 10 MW. I would also not that this is a significant reduction from the
7 previous 10 average MW cap and a substantial reduction in size, moving from
8 average to nameplate capacity.
9 Q. DO YOU HAVE ANY COMMENTS REGARDING STAFF'S SUPPORT
10 OF IDAHO POWER'S PROPOSED SCHEDULE 74?
11 A. No. Staff has not provided any additional arguments that I need to address. For
12 all the reasons stated in my direct testimony, the Commission should not approve
13 the Idaho Power proposed schedule.
14 IV. ISSUES RAISED BY OTHER PARTIES
15 Q. DID YOUR REVIEW OF THE PARTY TESTIMONY RAISE ANY NEW
16 ISSUES YOU HAD NOT ADDRESSED?
17 A. Yes. Dr. Reading's testimony recommended certain transmission and
18 interconnection policy matters which I had not previously addressed. (See Dr.
19 Reading pages 66 and 67). The essence of one of Dr. Reading's
20 recommendations is that the Commission should mirror the FERC pricing
21 standards for customer contributions in aid of construction for interconnection
22 costs. The FERC policy calls for the payment of all costs up to the point of
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interconnection to be borne by the project developer. The cost of facilities
24 beyond this point ("network upgrades") however are initially funded by the
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project developer but are eventually refunded by the transmission provider. On
the other hand, Idaho Power's Schedule 72 ("Interconnection to Non-Utility
Generation") provides for only a limited upgrade refund based upon another
generator using the same network upgrade facilities and this "vested interest"
refund right expires after just five years.
Q. IS THERE A BASIS FOR THE DIFFERENCE IN POLICIES BETWEEN A
FERC REGULATED INTERCONNECTION AND A QF
INTERCONNECTED DIRECTLY TO ITS BUYER?
A. Yes, there can be. In cases where a FERC interconnection is required, the
interconnected QF (or possibly the purchaser) must pay for wheeling the power
across the local transmission provider's system. In the case where the QF is
directly connected to the purchasing utility (who is also the transmission
provider), no such ongoing wheeling payments are required. Differences in
policy can also arise simply from having differing views on who benefits from the
system upgrade. FERC generally views network upgrades as providing a system
benefit for all users of the network. From this perspective, then, it is equitable for
all users to pay for the upgrade. Other parties have the prospective that the
network upgrade is not providing any system benefit and that it would not be
needed but for the QF. These parties argue that the QF should be responsible for
paying for all network upgrades.
Q. WHICH PERSPECTIVE DO YOU AGREE WITH?
A. I agree with FERC's perspective. Network upgrades that allow power to be
delivered to loads should be paid for by the loads and not the QF. In my view,
this "levels the playing field" with utility owned generation. Certainly, Idaho
Donald W. Schoenbeck Page 13 of 14
Power's customers are paying the network transmission costs to deliver power
2 from Bridger to Boise and all other Idaho Power owned resources. These
3 customers are even paying all the interconnection costs associated with these
4 utility-owned assets as well (costs up to the interconnection point with the
5 transmission network). The FERC prospective should be used to determine the
6 costs that should be borne by QFs in Idaho as well. The QF Companies fully
7 support Dr. Reading's recommendation and ask the Commission to adopt and
8 employ the FERC interconnection policy in Idaho whereby network upgrades
9 should be paid for by the users of the transmission system.
10 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
11 A. Yes.
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