ML20153F637
| ML20153F637 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 02/24/1988 |
| From: | Tucker J UTAH POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML20153F598 | List: |
| References | |
| NUDOCS 8805110010 | |
| Download: ML20153F637 (39) | |
Text
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'b Exhibit B UNITED STATES OF AMERICA BEFORE THE NUCLEAR REGULATORY COMMISSION IN THE MATTER OF THE
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EXHIBIT B to Facility APPLICATION OF PACIFICORP
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Operating License No. NPF-1 FOR CONSENT TO THE TRANSFER )
Indemnity Agreement No. B-78 OF LICENSES
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REBUTTAL TESTIMONY OF JAMES D. TUCKER 8805110010 880509 ADOCK0500gg4 PDR T
.g Exhibit 211 t
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UNITED STATES OF AMERICA BEFORE THE i
FEDERAL ENERGY REGULATORY COMMISSION f
Utah Power & Light Company
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Pacificorp
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Docket No. EC88-2-000 j
PC/UP&L Merging Corp.
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r REBUTTAL TESTIMONY l
OF JAMES D. TUCKER ON BEHALF OF UTAH POWER & LIGHT COMPANY PACIFICORP PC/UP&L MERGING CORP.
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i February 24, 1988
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SUMMARY
OF REBUTTAL TESTIMONY
'l OF i
JAMES D. TUCKER j
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J r
Issues Addressed i
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Transmission capacity Into Arizona /New Mexico and l
r CREDA Witness Taylor, pp. 14, 34-35, 39, 40-41 l
' '(Ex. 178) l 1
Idaho / Montana Witness Durick, pp. 11, 13, 15-17, 22-24 (Ex. 80, Ex. 82 & Ex. 33) t
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Idaho / Montana Witness Hughes, p. 39 (Ex. $4) 67 i
II.
Near-Term Transmission Additions j
CREDA Witness Taylor, p. 50 (Ex. 178) j l
i Idaho / Montana Witness Durick, pp. 10, 24 (Ex. 80)
III.
The Southern Island Import Limit Idaho / Montana Witness Durick, pp. 22-24, 26; (Ex.
80, Ex. 81 & Ex. 83)
CREDA Witness Taylor, pp. 48, 68-71 (Ex. 178)
IV.
Incremental Flow Impacts of PP&L and UP&L Transactions f
on Idaho Power Company
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Idaho / Montana Witness Casazza, pp. 10, 19, 25-29 (Ex. 51, Ex. 58-62) l V.
The Ben Lomond Nomogram and Minimum Swing Voltage Cri-terion
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UAMPS/ Washington City Witness Hunter, pp. 13-14
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(Ex. 45)
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VI.
Losses and Reliability l
DG&T Witness Lim, pp. 35-37 (Ex. 49)
VII.
The Laramie River Exchange I
CREDA Witness Goff, p. 14 (Ex. 118)
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CONTENT AND CONCLUSIONS l
Transmission Capacity Into the Desert Southwest and California Witnesses Gordon T. C. Taylor and H. Charles Dorick have substantially overstated the control that the merged company will have over transmission capacity from the Northwest into the De-serc Souhhvest and. California.
They adopt a philosophy that if I
any one link in a series of connected transmission lines is con-l trolled by the merged company, the merged company then controls the entire series of lines, despite the fact that each of the owners in the series has an equal measure of control and their mutually dependent relationships dictate that they not arbitrari-ly exercise that control to exclude others.
Moreover, they attribute to the merged company control of certain facilities to
[
vhich other suppliers have access without the use of the merged l
companies' lines.
The fact that the merged company vill have less control than these witnesses attribute to it is evidenced by the history and current status of UP&L's sales to the Desert Southwest and r
California areas.
UP&L has not made any long-term firm sales
{
r south through the Glen Canyon interconnection in the last 10-15 years, and non-firm sales within the past five years have aver-aged only 3 MW.
The company does not have any firm sales on ei-l ther of its two transmission lines to Arizona and New Mexico.
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- l 1r-i Near Term Transmission Additions e
Substantial increases in transmission capacity that are under way will improve the transmission situation from the North-vest to California, and that vill, in turn, provide improved ac-cess to Arizona and New Mexico because of ample vest-to-east transmission capacity in the lines between California and Arizona /New Mexico.
Northwest utilities will, therefore, have increased access to the southwestern markets, and the merger vill in no way impede this access.
Southern Island Imoort Limit A correct analysis of the California, Southern Nevada and j
Arizona /New Mexico areas (the Southern Island) shows that Utah i
Power & Light controls 7.6 percent of the transmission capacity i
to that area from the Northwest, and Pacific Power & Light con-l trols 4 percent.
Incremental Loop Flow Impacts of PP&L/UP&L Transactions on Idaho Power Comoany Witness John A. Casazza for Idaho Power Company (IPC) is in-correct in his testimony that the operations of the merged compa-1 ny after the merger vill create flows on the IPC transmission system that are prohibited by the Transmission Service Agreement i
(the TSA) between IPC and UP&L.
Mr. Casazza's argument is based P
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l on incremental power flow analysis that shows, under some op-erating conditions, that there vill be incremental or loop flows running from vest to east on the IPC system, and vest-to-east schedules are prohibited by the TSA.
!Ils conc 1'ision is incor-rect.
The incremental flows from west to east are tlat result of reductions in scheduled flows from east to vest, and the l
scheduled flow on the IPC, system caused by the merged company vill always be east to vest.
Periodic incremental flows from vest to east are not proh!bited by the TSA.
Instead, the TSA expressly provides for the reduction of east to vest transmission schedules, and it contains provisions relating to such reduc-tions.
t Ben Lomond Nomocram and Minimum Svino Voltace Criterion 4
l Witness Douglas O. Hunter is wrong when he claims that the cities of Logan and Hyrum are located where they would not be af-fected by the transmission limitations into Ben Lomond.
Those f
cities are south of the transmission path that contributes to l
that restraint.
In considering the request of Washington City for transmis-i
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sion services, Up&L initially considered the impact that the t
f-merger would have on its ability to wheel power for Washington City while maintaining its existing level of non-firm purchases f
i from IPC, but the increased flexibility that the merged company L
l vould have in accepting delivery from the PP&L/ Wyoming area was I
t i
L
1
-S-d not taken into account.
That has now been considered, with the result that, because the merged company vill have more capacity with IPC than UP&L has independently, wheeling for Washington City is possible through PP&L/ Wyoming interconnections with IPC vith delivery to UP&L through the Naughton interconnection.
Planned transmission additions through Naughton vill increase the stability of the Naughton plant and, therefore, increase trans-mission capacity into Ben Lomond.
Losses and Reliability The analysis of Mr. James Lim, purporting to show that wheeling for Washington City through Ben Lomond vill reduce line losses for UP&L, is erroneous because Mr. Lim used historical schedules rather than historical line flows to make his determi-nation.
Line losses are related to actual flows, not scheduled flows.
Mr. Lim also is incorrect in stating that such wheeling would improve system reliability.
Such wheeling vill have no reliability effect, since all Western Systems Coordinating Coun-cil Systems operate within the WSCC reliability criteria either with or without this transfer.
Laramie River Exchance The Laramie River exchange proposed by vitness Randall P. Goff is not feasible.
Such an exchange requires that transfer
requirements be in opposite directions, while in this case the intended uses are both in the same direction.
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A d
J.
D. Tucker 1 QUEFTION 2
Please state your name.
3 ANSWER 4
James D. Iteker.
5 QUESTION 6
Are you the same James D.
Tucker who has previously 7
filed testimony in this proceeding?
8 ANSWER 9
Yes, I am.
10 QUESTION 11 Will you offer any exhibits in connection with your 12 rebuttal testimony?
13 ANSWER 14 Yes, I have one exhibit, Exhibit No. 212, consisting 15 of five schedules.
16 QUESTION 17 Mr. Tucker, have you reviewed the testimony filed by 18 the witnesses for the various intervenors in this pro-19 ceeding?
20 ANSWER 21 Yes, I have.
22 QUESTION 23 What is the purpose of your rebuttal testimony?
24 ANSWER 25 The purpose of my testimony is to respond to certain 26 i
d J.
D. Tucker 1 statements cade in this case by Idaho Power Company (IPC) 2 and Montana Power Company (MPC) witnesses John A.
3 Casazza, H. Charles Durick and William R. Hughes; Utah 4
Associated Municipal Power Systems (UAMPS) and Deseret 5
Generation & Transmission Co-operative (DG&T) witness 6
James Lim; UAMPS/ Washington City witness Douglas O.
7 Huntor Co - s.
da River Energy Distributors Association 8
(CREDA) an
-CA, ett a_1_. witnesses Randall P. Goff and 9
Gordon T.C.
Taylor; and Federal Energy Regulatory Commis-10 sion (FERC) witness Louis A. Schuppin.
11 My rebuttal testimo,ay will r vess the following:
12 1.
The transmission capace
.nto Arizona /New 13 Mexico and California from Utah, and the 14 statements by Dr. Taylor (Exhibit No. 178) and 15 Mr. Durick (Exhibit No. 80) that there are 16 three interconnections controlled by Utah Power 17
& Light Company (UP&L or Utah Power) from the Northwest to the Southwest; 18 2.
Near-term additions within Western Systems 19 Coordinating Council (WSCC), and the statements 20 regarding these additions by Dr. Taylor and Mr.
21 Durick; 22 3.
The Southern Island import limit and statements 23 f Dr. Taylor and Mr. Durick concerning the 24 boundary bisecting the WSCC system.
25 26 1
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i J.
D. Tucker 3'-
1 4.
Incremental flow impacts of UP&L and PP&L
)
2 transactions on IPC, and the statements by Mr.
3 Casazza (Exhibit No. 51) suggesting 4
west-to-east incremental flows in alleged 5
violation of the 1980 Transmission Service 6
Agreement (TSA) between IPC and PP&L; 7
4.
The Ben Lomond nomogram and. minimum swing 8
voltage criterion, and the statement by Mr.
9 Hunter (Exhibit No. 45) criticizing UP&L's use 4
10 of a.85 voltage criterion in determining 11 transmission capacity north of Ben Lomond, Mr.
12 Hunter's testimony concerning certain UAMPS 13 cities north of Ben Lomond, and the beneficial 14 transmission impact of new transmission addi-15 tions on the Ben Lomond nomogram; 16 5.
Losses and reliability, and the statement-of 17 Mr. Lim'(Exhibit No. 49) concerning UP&L's 18 wheeling of power from IPC to Washington City 19 and its dileged effect on losses and reliabili-20 ty; and 21 6.
The Laramie River exchange suggested by Mr.
22 Goff (Exhibit No. 118) between UP&L and Western 23 Area Power Administration (WAPA).
24 25 26 8
d J.
D.
Tucker
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TRANSMISSION CAPACITY 2
INTO ARIZONA /NEW MEXICO AND CALIFORNIA 3
QUESTION 4
Dr. Taylor testified (Exhibit No. 178, pp. 34 and 5
- 41) that there are three interconnections controlled by 6
UP&L from the Northwest to the Southwest totalling 1700 7
MW of transmission capacity.
Mr. Durick testified 8
(Exhibit No. 80, pp. 22-24) that the merged company will 9
control a disproportionate share of the transmission 10 capacity from the Northwest into California / Southern Nevada and Arizona /New Mexico.
Are these witnesses 11 correct?
12 ANSWER '
13 No.
They disregard existing non-UP&L firm transmis-14 sion commitments on the IPP transmission system, the 15 transmission system south of Glen Canyon, and the trans-16 mission systems south and west of Four Corners.
A.'. s o,
17 their conclusions reflect what I believe is an inappro-18 priate philosophy as to transmission control.
19 QUESTION 20 What is that control philosophy?
21 ANSWER 22 Their philosophy seems to be that if a transmission 23 path is owned by more than one company whose lines are in 24 series (one path connects to another path, and another, 25 etc.), and one of the c.ompanies is the merged company,
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D. Tucker 5.
1 control is assumed to vest only in the merged company.
2 In this way, they are able to attribute to the merged 3
company what appears to be a relatively high level of 4
control.
5 QUESTION 6
Is this philosophy an appropriate one?
7 ANSWER 8
No.
In reality, each of the owners in series has an 9
equal measure of control over the transmission path.
10 Transactions can move in both directions over the trans-11 mission path.
As a result, parties anywhere in the chain 12 of facilities have equal control over the use of the 13 entire path.
The mutual dependent relationships among 14 these parties dictate that they not arbitrarily exercise 15 that control to exclude others.
UP&L and PP&L together 16 do not have anywhere near the control over transmission 17 facilities that these witnesses suggest.
Beyond the narrow consideration of the use of transmission for bulk 18 19 power sales, there is, by necessity, a high degree of 20 cooperation required between the parties for successful 21-system operation.
Arbitrary exercise of control by one of the parties will create problems on the larger issue 22 of dealing with system reliability and response to system 23 24 emergencies.
25 QUESTION 26 Would acceptance of this "upstream-downstream" l
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7 J.
D.
Tucker 1 philosophy have any implications for other companies in 2
the Northwest?
3 ANSWER 4
Absolutely.
IPC and MPC both own links in certain 5
key transmission paths.
In the case of IPC, its owner-6 ship is so strategically located that application.of the 7
upstrean-downstream philosophy would mean that IPC would 8
control most of the transmission from the Northwest 9
(Washington, Oregon and Idaho) down the eastern transmis-10 sion corridor.
11 QUESTION 12 Will the merger result in any transmission paths 13 being controlled by the merged company that are not now 14 controlled by UP&L and PP&L?
15 ANSWER 16 No, and this is true whether or not one accepts the 17 upstream-downstream philosophy.
18 QUESTION Is there any reason that utilities in the Northwest 19 should have any greater difficulty after the merger in 20 obtaining access to the Southwest than they had prior to 21 22 the merger?
ANSWER 23 No.
To the extent these companies control the 24 25 26
J.
D.
Tucker '
1 transmission today, the same will be true after the 2
merger.
I know of no reason that they will be less able 3
to obtain transmission to the Southwest.
4 QUESTION 5
If we were to accept Mr. Durick's conclusions as to 6
the extent to which the merged company controls transmis-7 sion facilities, would that fact foreclose other compa-8 nies in the Northwest from power sales in the Southwest?
9 ANSWER 10 No.
Exhibit No. 82 shows that there is substantial 11 non-PP&L capacity in the Pacific AC Intertic, the Pacific 12 DC Intertie and other lines shown on that Exhibit.
Mr.
13 Durick argues that much of that capacity is otherwise 14 committed.
To the extent that is true, it is not as a 15 result of any action by PP&L or UP&L.
16 QUESTION You indicated that Mr. Durick has, in effect, played 17 18 down the importance of the transmission capacity con-19 trolled by others, alleging that it is largely committed 20 already.
Did he make the same point with respect to the transmission facilities that he considers to be con-21 22 trolled by the merged company?
ANSWER 23 No.
He points out that commitments of Bonneville 24 Power Administration (BPA) capacity on the west and WAPA 25 26 capacity on the east are highly committed, but he does
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't J.
D.
Tucker 1 not discuss the extent to which the facilities attributed 2
to the merged company are committed or otherwise unavail-3 able.
As a result, the capacity figures on Exhibit No.
4 82 substantially overstate the capacity over which the 5
merged company has control, even under the 6
upstream-downstream philosophy.
Dr. Taylor has made the 7
same error in his testimony.
They both attribute to the 8
merged company too much capacity in the IPP DC line 9
(through the Mona Substation), the Sigurd-Glen Canyon 10 line and the Pinto-Four Corners line.
11 QUESTION 12 How have they erred with respect to the IPP DC line?
13 ANSWER 14 Mr. Durick (Exhibit No. 82) attributes 1000 MW 15 non-firm and 320 MW firm from this line to the merged 16 company, Dr. Taylor (Exhi. bit No. 178, p. 14) attributes 800 MW.
Both are in error.
While the capacity from Mona 17 to IPP is 800 MW, and from IPP to the southwest is 1920 18 19 MW, there is access to Mona and IPP other than through the UP&L facilities.
Moreover, the uncommitted capacity 20 on the IPP transmission path is only 193 MW.
As a 21 22 result, the total available access to the southwest through Mona is 193 MW and, even under the 23 Upstream-downstream philosophy, UP&L does not control any 24 f it, as I will explain below.
The facilities to which 25 I refer are shown in Schedule No.
1, Exhibit No. 212.
26
t J.
D. Tucker 1 QUESTION 2
Please explain the limitations on availability of 3
capacity in the IPP DC transmission path.
4 ANSWER 5
Of the 1920 MW capacity in the DC line, 1600 MW is 6
committed to the delivery of IPP power, 80 MW is commit-7 ted to a firm sale by DG&T to the City of Anaheim, and 47 8
MW is committed to a similar sale to the City of River-side.
This leaves only 193 MW of uncommitted firm 9
10 transmission capacity on this path (1920 -1600-127 = 193).
QUESTION 11 Why is it that UP&L does not control this 193 MW of 12 capacity?
13 ANSWER 14 Even using the upstream-downstream philosophy for 15 assigning control, UP&L does not control the access to 16 this capacity because it is not in series with alterna-17 tive paths to IPP.
There are two non-UP&L paths into the 18 Mona or IPP Substations.
One is the Bonanza-Mona 345 kV 19 line owned by DG&T, which is connected to the Colorado 20 system.
The other line is the IPP-Gonder 230 kV line, 21 which is owned by the Intermountain Power Agency (IPA).
22 These lines have sufficient capacity to fully utilize the 23 193 MW.
Dr. Taylor (Exhibit No. 178, p. 40) dismisses 24 the Bonanza-Mona line because of perceived transmission 25 constraints from Montana to Wyoming to Colorado.
Mr.
26 l
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3 J.
D. Tucker 1 Durick appears to have ignored the Bonanza-Mona line 2
completely.
Dr. Taylor (p. 41) and Mr. Durick (p. 13) 3 also dismiss the IPP-Gender line because the switch is 4
presently open at Gonder.
5 QUESTION 6
Are Dr. Taylor and Mr. Durick correct in dismissing 7
the Bonanza-Mona line because of a perceived transmission 8
constraint from Montana through Wyoning to Colorado?
9 ANSWER 10 No.
That perceived constraint does not affect the 11 ability of many suppliers to obtain access to Mona 12 through Bonanza.
Therefore, the merged company will not 13 have control over access to Mona.
Moreover, the 14 scheduled completion of the Spence-Tnermopolis line later 15 this year will increase the transfer capability in the 16 Montana-Wyoming area.
17 QUESTION 18 What is the status of the IPP-Gonder line?
19 ANSWER 20 The IPP-Gonder line will be closed when relay 21 modifications are completed to insure tripping of the 22 IPP-Gonder line when the IPP-Mona lines trip.
23 QUESTION 24 Why has it taken so long to close this line?
25 ANSWER 26 The relay modifications are not particularly
J.
D.
Tucker 1 difficult, but have been slow to materialize.
My obser-2 vation is that no one is pressf.ng for completion of these 3
modifications because there is little value in transmis-4 sion capacity to the IPP as a result of the limited 5
uncommitted transmission capacity (193 MW) from IPP to 6
Los Angeles.
7 QUESTION 8
If there were a need to make a sale to California 9
entities at IPP through the IPP-Gonder line, do you think 10 it would expedite the relay modifications?
11 ANSWER 12 Yes.
13 QUESTION 14 Mr. Tucker, is the IPP-Gonder line shown on the WSCC 15 Non-Simultaneous Transfer Capability Diagram, Exhibit No.
16 13, Schedule No.
8, page 1?
17 ANSWER 18 Yes, it is shown as Path No. 40 with a transfer 19 capability of 200 MW.
20 QUESTION How do the Bonanza-Mona and IPP-Gonder lines affect 21 22 UP&L's influence on the 193 MW firm transmission capacity 23 through the IPP path to California?
24 ANSWER 25 UP&L cannot control this capacity.
This 26
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D.
Tucker '
1 transmission capacity can be fully utilized without using 2
UP&L or PP&L facilities, either through the IPP-Gonder 3
line or through the DG&T Bonanza-Mona line.
UP&L does 4
not control the IPP-Gonder switch; it is open at the 5
Present time by choice of the parties who control it, not 6
by UP&L.
Therefore, UP&L centrols zero megawatts of 7
capacity for the IPP transmission path, rather than the 8
800 MW claimed by Dr. Taylor or the 1000 MW appearing on 9
Mr. Durick's Exhibit No. 82.
10 QUESTION 11 At page 35, Dr. Taylor suggesta that Utah Power has 12 300 MW of access to WAPA, Nevada Power Company, Southern 13 California Edison, Los Angeles Department of Water &
14 Power (LADWP) and the Metropolitan Water District on the 15 Sigurd-Glen Canyon line through the Glen Canyon intercon-nect")n.
Exhibit No. 82 also shows 300 MW for that path.
16 Is :his a realistic characterization of the transmission 17 capability south of Glen Canyon?
18 ANSWER 19 No.
Utah Power has exporlenced little success in 20 making sales south of Glen Canyon.
WAPA fully utilizes 21 the transmission south of Glen Canyon for the Glen Canyon 22 generation and their own use.
23 QUESTION 24 Does Utah Power try to make firm or non-firm sales 25 south of Glen Canyon?
26
I J.
D. Tucker
- 13 1
ANSWER 2
Yes.
3 QUESTION-4 How successful have these attempts been?
5 ANSWER 6
UP&L has not made any long-term firm sales south 7
through the Glen Canyon interconnection in the last 10-15 8
years.
Furthermore, within the past five years, the 9
average hourly non-firm sales made at Gler Canyon has 10 only baen 3 HW.
OUESTION 11 On Page 39 of Dr. Taylor's testimony (Exhibit No.
12 13 178), he criticizes you for showing the Sigurd-Glen Canyon line between the Northwest and the Rocky Mt. area, 14 instead of Arizona.
Why is this line shown to the Rocky 15 Mt. area?
16 ANSWER 77 The lino is shown between the Northwest and the 18 Rocky Mt. area because it connects Utah Power with the 19 i
WAPA Upper Colorado Region, which is in the Rocky Mt.
20 area.
The Rocky Mt. area includes the Glen Canyon 21 9eneratin9 P ant and the Upper Colorado Region of WAPA.
l 22 O
S ON 23 Dr. Taylor (Exhibit No. 178, p. 41) combines the 24 capacity of the Sigurd-Glen Canyon line (300 MW) directly 25 with the capacity in the Pinto-Four Corners line (600 MW) l 26 9.
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D. Tucker
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as part of his calculation of the total northwest to 2
southwest transmission facilities.
Exhibit No. 82 also 3
attributes those capacities to those lines.
Is it 4
appropriate to merely combine these capacity numbers?
ANSWER 5
No.
The maximum simultaneous rating of these 6
transmission lines is 755 MW, as shown in Schedule No. 2 7
of Exhibit No. 212. This data was provided to the parties 8
in this proceeding, as a result of receiving copies of 9
the data responses of Applicants in the Utah merger 10 Proceedings, as response to Request No. 9 of the First 11 Data Request of the Committee of Consumer Services.
12 Under no circumstances could the transfer across the 13 combination of these two lines exceed this 755 MW.
14 Q
STION 15 Why can't the 755 MW limitation be excoeded?
16 ANSWER g
Operation above the limit will cause a series of 18 lines to trip if UP&L's Huntington-Pinto 345 kV line is 9
s fr m se M ce.
20 QUESTION Mr. Tucker, is there anything else that bears on the Companies' Control of transmission to the Southwest?
ANSWER Yes.
The history and current status of UP&L's firm 5
26
t J.
D.
Tucker 1 sales to Arizona /New Mexico and California areas disprove 2
the allegations of transmission dominance and transmis-3 sion leverage to extract excess profits.
UP&L does not 4
have a single megawatt of a firm sale on either of its 5
two transmission lines to Arizona or New Mexico.
This is 6
not because UP&L doesn't'have generation excesses, nor 7
the desire to make such firm trrasactions, but it is 8
clearly a reflection of existing transmission constraints 9
beyond UP&L's control.
The facts speak for themselves.
10 UP&L cannot control the 193 MW available on the IPP DC line.
It has no firm sales south of the Glen Canyon 11 12 interconnection and only occasional non-firm sales.
It has.no firm sales south of Four Corners, but does make 13 14 non-firm sales whenever non-firm transmission capacity out of Four Corners is available and economic.
15 16 In fact, the transmission utilization south of IPP, Glen Canyon and Four Corners is just as real and limiting 17 as the transmission utilization south of Montana into the 18 Rocky Mt. area, which Mr. Durick states (Exhibit No. 80, 19 20 PP. 15-17) makes the Montana path infeasible for North-
. west transfers to Arizona /New Mexico through the Colorado 21 area.
22 WESTION 23 On page 35 of his testimony (Exhibit No. 178), Dr.
24 Taylor makes the statement, "Northwest and Intermountain 25 utilities with a path on the Pacific Intertie have access 26 i
l
J.
D. Tucker k to California utilities, but generally not to Arizona or 2
New Mexico utilities."
A similar statement is made by 3
Mr. Durick (Exhibit No. 80, p. 11).
Mr. Hughes (Exhibit 4
No. 84, p.
39), quotes Mr. Durick that all "viable paths 5
with available capacity from the Northwest to Arizona /New 6
Mexico require access to UP&L or the PP&L Wyoming sys-7 tem." Do you agree with these statements?
8 ANSWER 9
Absolutely not.
These witnesses have all disregard-10 ed the transmission capacity (3200 MW AC and 1956 MW DC) 11 from the Northwest to. California which can subsequently 12 be used to move power to the Arizona area through the 13 California-Arizona /New Mexico interties.
The trans-14 mission capacity is in excess of 2000 MU from California 15 to Arizona /New Mexico (Exhibit No. 13, Schedule No.
9, p.
16 3,
line 32) and would likely be available since the 17 Predominant flow of power is from the Arizona /New Mexico area to southern California.
Any schedules from the 79 California area to Arizona /New Mexico would reduce line 19 1 adings.
Therefore, the assertions that the UP&L path 20 is the only path from the Northwest to Arizona /New Mexico 21 is not the fact.
22 23 Some of BPA's capacity on the Pacific Interties will 24 be allocated according to the Long-Term Intertie Access P licy, as discussed by Mr. Boucher.
The draft access 25 Policy provides IPC with 87 MW of long-term firm Intertic 26
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D.
Tucker
accesa.
In addition, IPC and MPC will have the right to 3
share in the allocation of additional capacity that BPA 4
will likely make available.
5 6
NEAR-TERM ADDITIONS 7
QUESTION 8
Dr. Taylor (Exhibit No. 178, p. 50) and Mr. Durick 9
(Exhibit No. 80, p. 24) discuss near-term transmission 10 additions.
Do you agree with their testimony?
11 ANSWER 12 I disagree with Dr. Taylor, who does not believe 13 that the Third AC Pacific Intertie will be completed in 14 the near term.
Mr. Durick also disagrees with Dr.
15 Taylor.
However, the three of us do agree that the DC 16 Uprate (Exhibit No. 13, Schedule No.
9, p.
- 8) will be 17 completed in the near term.
18 QUESTION 19 How much transmission capacity from the Northwest to 20 the California / Southern Nevada area would be added by 21 these additions?
22 ANSWER 23 The DC expansion project and the Third AC Pacific 24 Intertie would add 2630 MW of capacity (1600 MW Third AC 25 Pacific Intertie and 1030 DC expansion) to the existing 26 5156 MW capacity (3200 MW Pacific AC Intertie, 1956
J.
D. Tucker
- 18 4
1 Pacific DC Intertie) on the Pacific Intertiec.
The total 2
capacity of the Pacific Interties would be 7786 MW.
3 Of the new 1600 MW AC Intertie capacity, the merged 4
company will have firm rights to 100 MW.
Portland 5
General Electric and BPA are negotiating on how to split 6
700 MW.
The remaining 800 MW will most likely be avail-7 able for firm subscription or ownership by other North-8 west utilities.
Of the new 1030 MW HVDC capacity, BPA 9
and the Long-term Intertie Access Policy will dictate 10 usage.
11 The substantial increase will certainly improve the 12 transmission situation from the Northwest to Califor-13 nia/ Southern Navada and thereby also to Arizona /New 14 Mexico.
There is in excess of 2000 MW of transmission r
15 capacity from the California / Southern Nevada area to the 16 Arizona /New Mexico area.
Since the predominant flow is 17 from Arizona to California, it would take a transfer far 18 in excess of the 2000 MW to fully utilize that capacity.
19 Mr. Durick testified (Exhibit No. 80, p.
- 10) that 20 Idaho Power has not encountered major obstacles in 21 acquiring transmission service to the northern te.ruinals j
l of the Pacific Interties.
As I stated earlier, there is l
22 23 no reason for this to change after the merger.
24 25 26
5 J.
D. Tucker -
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1 SOUTHERN ISLAND IMPORT LIMIT 2
QUESTION 3
Mr. Durick's Exhibit No. 81 shows a boundary drawn 4
through several major WSCC transmission lines.
What 5
underlying assumption has he made when drawina the 6
boundary in this manner?
7 ANSWER 8
He appears to be assuming that the only relevant 9
suppliers to the CLlifornia/ Southern Nevada and Arizo-10 na/New Mexico areas are from Northwest generation.
QUESTION 11 Is this correct?
12 ANSWER 13 No.
The Rocky Mt. area is also a relevant supplier, 14 in addition, of course, to the substantial capacity 15 within the areas themselves.
WSCC is a diverse resource 16 and load region, geographically dispersed.
The Northwest 17 is a major supplier of inexpensive hydro power.
- However, 18 the hydro supply in the Northwest is variable and depen-19 dent on water conditions.
During an adverse water year, 20 a large part of WSCC and, in fact, the Northwest itself, 21 relies to a major extent on coal-fired resources from the 22 Rocky Mt. area.
Therefore, the transmission paths 23 c nnecting coal-fired generation areas must be consid-24
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1 QUESTION 2
Do you disagree with any of Mr. Durick's discussion P
3 of transmission paths and limits?
4 ANSWER 5
Yes.
As I previously testified (Exhibit Ns. 12, pp.
6 33-34), there is a total physical maximum import limit 7
into the Southern Island (California, Southern Nevada and 8
the States of Arizona and New Mexico).
I have modified 9
the boundary.used by Mr. Durick (Exhibit No. 81) to 10 identify the Southern Island, and included it as page 1 11 of Schedule No.
3, Exhibit No. 212.
The Southern Island 12 is the southern portion of WSCC.
Mr. Durick's boundary 13 Paths A through H are essentially consistent with the 14 boundary of the Southern Island, however, his boundary 15 Paths I through o should be replaced with a boundary 16 through a new path, which I have identified as Path P on a
17 my Schedule.
All power from the Northwest to the Arizo-18 na/New Mexico and California / Southern Nevada areas that 19 cross Mr. Durick's Paths I through o must ultimately pass 20 through Path P.
21 The revised boundary I have identified as Paths A 22 thcough H and P has an actual physical limit (3800 MW 23 1988 Spring) that is of enough concern to WSCC that its 24 capacity is determined through study by the WSCC Pacific 25
& Southwest Transfer (PAST) Capability Work Group for 26 each season.
This is a real boundary that is a limit for
J.
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Tucker.
1 sales to the Southern Island.
The Southern Island 2
boundary is a well-known constrained portion of the WSCC 3
system and, in fact, has a relay scheme which trips the 4
remaining AC lines when the AC Pacific Intertie is lost.
5 QUESTION 6
Dr. Taylor states (p. 48) that UP&L controls 23.8%
7 and PP&L controls 5.6% of the principal northwest to 8
southwest transmission paths.
Mr. Durick's analysis 9
suggests even greater control (p. 22-24).
Do you agree 10 with these percentages?
11 ANSWER 12 No.
Earlier in this testimony, I discussed the 13 historical and existing lack of transmission dominance as 14 evidenced by the luck of firm sales by UP&L.
15 I have made an evaluation of the total transmission 16 capacity into the Southern boundary that includes all 17 transmission capacity, regardless of prior commitments.
18 Included on page 2 of Schedule No.
3, Exhibit No. 212 are 19 the calculations which show that the sum of the total 20 transfer capabilities across the AC lines to the Southern Island is 4840 MW.
I have used the same transmission 21 22 capacities as Mr. Durick has presented on his AC lines 23 except the simultaneous 755 MW rating for the Sigurd-Glen 24 Canyon line and the Pinto-Four Corners line for reasons 25 that I have already discussed.
The capacity of Path P is 26 l
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- 1 the average of the ratings provided on Mr. Durick's 2
Exhibit No. 83, page 2 ([450+800]/2 = 625 MW).
3 QUESTION 4
Have you prorated this total transfer capability 5
across the AC lines into the Southern Island to the 3800 6
MW limit?
7 ANSWER 8
Yes, I have.
A slight adjustment is required for 9
the 3800 MW limit, as explained on page 3 of the Sched-10 ule, which results in the actual flow limit being 3729 MW 11 when the transfer limit is reached in the PAST load flow 12 study.
This proration is shown in Column (E) of page 2.
13 QUESTION 14 Mr. Tucker, does the flow on DC lines reduce the 15 3800 MW limit?
16 ANSWER 17 No.
DC lines continue to operate, even if the WSCC 18 system is islanded.
Therefore, the capacity of DC lines 19 is added to the 3800 MW AC import limit.
For this 20 reason, I have included the capacity of both the DC 21 Pacific Intertie and the IPP DC line, and assigned the 22 1920 MW capacity of the IPP DC line to IPA /LADWP, its 23 owner.
24 QUESTION 25 What are the results of this analysis?
26
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D. Tucker
- 23 1
ANSWER 2
This analysis (Schedule No.
3,
- p. 2) demonstrates 3
that when all transmission (7605 MW) is considered ac:ross 4
the legitimate boundary of the Southern Island, UP&L 5
controls 7.6% (582 MW) and PP&L controls 4% (308 MW), the 6
sum of which is 11.7% (due to rounding) (890 MW).
This 7
demonstrates that neither the individual companies, nor 8
the merged company, has a significant degree of control 9
of the transmission system to the Southern Island.
10 QUESTION 11 Mr. Durick (Exhibit No. 80, p. 26) and Dr. Taylor 12 (Exhibit No. 178, pp. 68-71) discuss impediments to the 13 construction of new transmission lines in WSCC.
Have 14 there been any substantial changes to the permitting 15 Process in the last ten years that make transmission 16 construction more difficult?
17 ANSWER 18 No.
19 QUESTION 20 How has the WSCC transmission grown?
21 ANSWER 22 The WSCC transmission system has grown significantly 23 during the past ten years.
In 1977, there were approxi-24 mately 77,000 transmission circuit miles in place within the WSCC.
By 1982, the total was nearly 94,000 circuit 25 miles.
By the beginning of 1987, there were over 104,000 26
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Tucker '
1 circuit miles in place, an increase of 36% from a decade 2
earlier.
3 4
INCREMENTAL LOOP FLOW IMPACTS 5
OF PP&L/UP&L TRANSACTIONS ON IPC 6
QUESTION 7
Mr. Casazza discussed the incremental effect:. on IPC 8
of various incremental schedules from and to the North-9 west from Wyoming and Utah (Exhibit No. 51, pp. 26-29).
10 What is an incremental power flow and how is it deter-mined?
11 ANSWER 12 13 Incremental power flow is determined by an analysis 14 that compares the flows on a series of transmission lines from a given set of conditions to the flows on the same 15 lines resulting from changing one condition.
The results 16 of the load flows are compared and the difference in 17 individual line flows--the incremental power flow, 18 whether an increase or a decrease--is attributed to the 19
{
condition changed.
20 QUESTION 21 Mr. Casazza claims that the IPC system will be used 22 in violation of the TSA since that agreement does not 23 give PP&L any right to transfer power from West to east g
(PP. 28-29).
He argues that the west-to-east incremental 25 26
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D. Tucker 1 flow changes shown in Exhibit Nos. 58-62 support his 2
claim.
Do you agree?
3 ANSWER
'4 No.
Mr. Casazza h'imself correctly indicates that 5
payments for transmission service are based upon the 6
quantity of transfers being scheduled and not the actual 7
flow on specific lines (p. 25).
This principle is in 8
conflict with his reasoning that incremental flows 9
through the IPC system create a new transmission service 10 obligation for the merged company to pay.
11 Incremental power flows are useful to determine the 12 incremental flow change on any line in the entire WSCC
,13 network.
However, the fact that there is a flow change 14 on a line in the network does not mean that there is an 15 obligation associated with that flow change.
16 The curtailment of an east-to-west power transfer 17 will, in an incremental power flow analysis, appear as an 18 incremental power flow from west to east, even though the 19 scheduled flow and the actual flow created by that 20 schedule continue to be from east to west.
I believe 21 this can be illustrated by an analogy.
Suppose that 22 there are two dams connected by a river, an upper dam and 23 a lower dam, and that a given amount of river flow is 24 normally scheduled between the dams.
If one wanted to 25 raise the level of water in the upper dam, this would be 26 done by reducing the scheduled river flow from the upper
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- 26 1
dam that would normally run into the lower dam.
While 2
this has the incremental effect of moving water from the 3
lower dam'to the upper dam, it does not mean that water 4
ran uphill.
The actual flow remained in the original 5
direction.
6 The same is true for transmission schedules between 7
PP&L's service territory in Wyoming (PP&L/ Wyoming) and 8
PP&L's service territory in the Northwest 9
(PP&L/ Northwest).
While a reduction in a schedule from 10 PP&L/ Wyoming to PP&L/ Northwest (say from 1600 MW to 1400 11 MW) has the effect of increasing the resources available 12 in the. Wyoming area (the 200 MW reduction), it does not
~
13 create a flow from west to east, and it does not mean 14 that these increased resources are Northwest resources.
15 In fact, these resources have always been located in the 16 Wyoming area.
17 The TSA, which Mr. Boucher will discuss, provides 18 for east-to-west schedules from PP&L/ Wyoming resources to 19 PP&L/ Northwest of up to 1600 MW.
Mr. Casazza suggests 20 that the merger will cause the use of IPC transmission in 21 a manner not allowed by the TSA.
Apparently he takes the 22 Position that a reduction in'the east-to-west schedule as 23 discussed above is actually a new schedule from west to east which requires additional compensation to IPC.
But 24 this is not true, as I have shown.
Moreover, the TSA 25 specifically allows the reduction of the east-to-west 26
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schedule below 1600 MW, and provides for an additional 2
payment if that reduction is below 1000 MW.
Thus, no 3
compensation other than that required by the TSA is 4
appropriate.
5 The operational capabilities yielded under the TSA 6
will be the same after the merger as exist in today's 7
system.
Mr. Casazza's incremental analysis does not 8
suppoit his conclusion that the merged company would 9
utilize the IPC system in a way not contemplated by the 10 TSA.
11 QUESTION 12 Mr. Casazza (Exhibit No. 51, p. 28) suggests that 13 the merged company may incur a transmission service 14 obligation to Idaho Power when the power is scheduled 15 between the UP&L system and the PP&L/ Wyoming system.
Do 16 you agree with this?
17 ANSWER 18 Absolutely not.
This notion is absurd.
UP&L and PP&L now own and will construct additional transmission 19 20 between UP&L and PP&L/ Wyoming, including phase shifting 21 transformers at Naughton, in order to minimize the 22 natural effects of loop flow.
The merged company has a right to use its transmis-23 24 sion system just as IPC, or any other utility, has a 25 right to use its transmission system.
This utility right is discussed by FERC Staff Witness Mr. Schuppin (Exhibit 26 L.
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1 No. 116, p.
16, lines 13-19), wherein he indicates that a 2
utility with one electrical path can schedule power "even 3
though much of the power could flow on alternate electri-4 cal paths".
5 When IPC changes an internal schedule between Hells 6
Canyon and Jim Bridger,. for instance, 30.9% of the change flows on transmission lines other than those of IPC.
7 8
QUESTION 9
Mr. Casazza alleges that "Pacific / Utah have present-10 ed no data or information on the transfer capability they have assumed between their three systems in their analy-11 sis, or the transmission capacity they need for complete 12
, integration" (Exhibit No. 51, p. 19).
Have you provided 13 such information?
14 ANSWER 15 Yes.
This was provided in Applicants' response to 16 Request No SE-7 of the FERC Staff, which Mr. Hunter 17 included as Exhibit No. 46 (Schedule 4) and consists of 18 studies and a description detailing the new transmission 19 additions between PP&L's Rock Springs area and UP&L's 20 Naughton Substation.
21 QUESTIO'J 22 Is this the transmission required to integrate 23 PP&L/ Wyoming resources with UP&L's resources?
24
^"8 25 Yes.
The studies detail how the additions will 26
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D. Tucker,
1 increase the capacity to 530 MW from'the present rating 2
of approximately 200 MW and discusses the effect the 230 3
kV additions will have on the 345 kV transmission west of 4
Bridger.
5 QUESTION 6
Do the new 230 kV additions increase the Bridger 7
West transfer capability?
8 ANSWER 9
,Yes, by approximately 75 MW.
10 QUESTION 11 Mr. Casazza indicates that the WSCC practice is "to 12 base charges for transmission service on the incremental 13 scheduled transfer for which service is being provided" 14 (P. 29, lines 21-22).
Do you agree?
15 ANSWER 16 I'm not sure what he means here.
If he is talking 17 about making payments based on incremental flows, I would 18 not agree.
Charges are based on the total schedule.
He 19 seems to recognize this when he states (p. 25, line 12) 20 that "(p]ayments for transmission service are based on i
21 the quantity of transfers being scheduled, not on the 22 total flow on specific lines."
I agree with this state-23 ment.
24 In the first instance (payments based on incremental 25 flows), obligations would be incurred to all intercon-26 nected systems because electricity flows on all
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1 electrical paths.
In the second instance (payments based 2
on schedules), payment is only made for the specific con-3 tract path, which is the practice within WSCC.
And the 4
fact that power flows across all electrical paths and 5
creates incremental flow changes in the entire WSCC 6
system is not a factor in determining transmission 7
service charges.
This is' called loop flow and, as I have 8
discussed at some length in my direct testimony, is a 9
reality of interconnected operation.
It is a required 10 concession to reap the annual $15 billion benefit to the 11 electric consumers of the United States that results from 12 interconnected and coordinated electric operations, as 13 estimated by Mr. Casazza (Exhibit No. 51, p. 10, line 5).
14 The merged company, however, proposes to minimize the 15 loop flow impact on other utilities through the installa-16 tion of phase shifters on the Naughton lines, as I stated r
17 in my direct testimony.
18 BEN LOMOND NOMOGRAM 19 AND MINIMUM SWING VOLTAGE CRITERION i
20 21 QUESTION 22 Mr. Hunter (Exhibit No. 45, p. 13) claims the cities 23 of Logan and Hyrum are located where they would not be.
24 affected by the Ben Lomond nomogram (north of con-straint), Exhibit No. 13, Schedule No.
6.
Do you agree?
25 26 i
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1 ANSWER 2
No.
The cities of Logan and Hyrum are located south 3
'of the northern system path constraint.
This transmis-4
<sion path is identified on page 2 of Schedule lic. 6, as 5
the Fishcreek-Goshen, Treasureton-Brady, Malad-Aastlesn 6
Falls and the Ben Lomond-Borah transmission lines.
Since 7
these cities are located south of this path, they vould 8
not alleviate the nomogram limit for schedules from the 9
north.
10 QUESTION 11 Several witnesses have objected to what they consid-12 er to be UP&L's refusal to wheel from IPC to Washington 13 City.
What was UP&L's transmission concern in regard to 14 that request for wheeling?
ANSWER 15 16 As stated in my direct testimony, UP&L was concerned that the transmission capacity on its northern system, 17 which has been fully utilized in the past, would be 18 reduced from 1000 MW to 800 MW.
19 QUESTION 20 Did UP&L consider the impact the merger would have 21 n its system?
22 ANSWER 33 In part.
When UP&L initially considered the impact 24 that the merger would have on its ability to wheel power 25 f r Washington City while maintaining its existing level 26 I
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of non-firm purchases from IPC, the effect on the UP&L 2
system was considered.
The increased flexibility that 3
the merged company would have in accepting deliveries 4
from the PP&L/ Wyoming area was not taken into account.
5 QUESTION 6
With the merger, will there be more flexibility to 7
provide wheeling for Washington City?
8 ANSWER 9
Yes.
The merged company will have more transmission 10 capacity with IPC than UPGL has independently.
As a 11 result, the merged company could take delivery of power 12 through the PP&L/ Wyoming interconnections with IPC and 13 deliver such power to the merged company's facilities in 14 Utah through the Naughton interconnection, if the exist-15 ing UP&L northern transmission system, as identified on 16 the nomogram (Schedule No. 6 of Exhibit No. 13), were constrained.
17 In addition, the transmission construction associat-18 ed with the merger increases the transmission capacity of 19 20 the merged system.
QUESTION 21 Does this mean that UP&L will not have to curtail 22 non-firm purchases from Idaho as a result of wheeling for 23 Washington City?
24 ANSWER 25 No.
We anticipate that under certain conditions 26
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curtailments will be required.
2 QUESTION 3
Will the proposed Naughton transmission additions 4
increase the transmission capacity between Naughton tsnd 5
Ben Lomond?
6 ANSWER 7
Yes.
These transmission additions will increase the 8
stability of the Naughton plant and, therefore, increase 9
the transmission capacity into Ben Lomond.
A nomogram 1C study has recently been conducted to determine the 11 operating constraints from Wyoming and Idaho without 12 these proposed transmission additions (the earlier study, 13 Schedule No. 6 of Exhibit No. 13 included those addi-14 tions).
The results of this nomogram study, Schedule No.
15 4,
Exhibit No. 212, illustrate that the constraint into 16 Ben Lomond is approximately 100 MW lower when the pro-17 posed Naughton transmission additions are not included in 18 the study.
19 QUESTION go Mr. Hunter (Exhibit No. 45, pp. 13-14) criticizes 21 your use of a.85 swing voltage criterion in determining 22 the transmission capacity north of Ben Lomond (nomogram, Exhibit No. 13, Schedule No. 6).
Is this Utah Power's 23 normal criterion?
24 25 A[{SWER
'es.
In fact, it has been used for years in the 26
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design of the UP&L system and in joint studies with the 2
municipally-owned Intermountain Power Project.
I have 3
included a letter from LADWP detailing this voltage 4
criterion to be used in IPP studies as Schedule No.
5, 5
Exhibit No. 212.
6 7
LOSSES & RELIABILITY 8
QUESTION 9
Mr. Lim (Exhibit No. 49, pp. 35-37) claims that 10 UP&L's wheeling of power from Idaho Power to Washington 11 City will result in reduced line losses for UP&L.
Is his 12 analysis correct?
13 ANSWER 14 No.
Mr. Lim has based his analysis on the histori-cal schedules rather than historical line flows between 15 Idaho Power and Utah Power to estimate the "percentage of 16 time" that power is actually transferred from south to 17 north.
Line losses are related to actual flows, not 18 scheduled flows.
As testified to by Mr. Casazza (Exhibit 19 20 No. 51, p.
25, line 21-23), Mr. Schuppin (Exhibit No.
21 116, p.
- 16) and myself, the actual flow across a trans-mission path can be quite different from the scheduled 22 flow and, in fact, may be in the opposite direction as a 23 result of loop flow from other systems.
24 WSCC clockwise loop flow, which flows from north to 25 26 south on the UP&L system, and operation of the WAPA phase JL
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D. Tucker 1 shifters to control clockwise loop flow will increase the 2
actual flow from IPC to UP&L.
This would decrease the 3
percentage of time the actual flows in the northern UP&L 4
transmission system are from south to north.
This makes 5
Mr. Lim's estimate of the loss benefit inaccurate and 6
also makes the prediction of actual flows futile.
7 QUESTION e
Mr. Lim alleges that the transfer of power from IPC 9
to UP&L for Washington City will improve system reliabil-10 ity (Exhibit No. 49, p. 37).
Do you agree?
11 ANSWER 12 No.
All WSCC systems will operate within the limits 13 of the WSCC Reliability Criteria either with or without 14 this transfer.
If an actual system limit is reached, 15 either with or without this particular transfer, adjust-16 monts will be made to alleviate the operating concern.
17 Therefore, there is no beneficial or adverse impact on 18 reliability for this transfer.
19 LARAMIE RIVER EXCHANGE 20 21 QUESTION Mr. Goff (Exhibit No. 118, p.
- 14) suggests that WAPA 22 and UP&L could work out an exchange agreenent so that 23 Laramie River or Craig power could be delivered to UP&L 24 fr m Colorado.
Is this possible?
25 26
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D. Tucker.
1 ANSWER 2
No.
In order for an exchange of power to be feasi-3 ble, the transfer requirements must be in opposite 4
directions.
In this case, the intended uses are both 5
into the UP&L system and, therefore, would be in the same 6
direction.
Thus, an exchange could not be made.
7 UP&L's 140 MW transmission capacity from Vernal to 8
Ashley is fully utilized with deliveries of Colorado
~
9 River Storage Project (CRSP) power to WAPA customers in 10 Utah.
11 QUESTION 12 Mr. Tucker, does this conclude your rebuttal testi-13 mony?
14 ANSWER
~
15 Yes, it does.
16 17 18 19 20 21 22 23 24 25 26 w,
i 3--
D UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Utah Power & Light Company
)
PacifiCorp
)
Docket No. EC88-2-000 PC/UP&L Merging Corp.
)
)
ss.
COUNTY OF SALT LAKE )
James D. Tucker, being first duly sworn, deposes and says:
that he has read and is familiar with the contents of the foregoing Rebuttal Testimony of James D. Tucker; that if asked the questions contained in said Testimony, the answers and response hereto would be as shown in said Testimony; that the facts contained in said answers are true to the best of his knowledge, information and belief; and that he adopts these answers as his own.
,/*
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AWA 4. -
y James D. Tucker SUBSCRIBED AND SWORN to before me this 22nd day of February, 1988.
E
'2a Notary Public
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My Commission Expires RM iding at:
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