ML20153F646

Prefiled Testimony of Jd Tucker Re Application of Pacificorp to Consent to Transfer of Licenses

ML20153F646
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Site:	Trojan File:Portland General Electric icon.png
Issue date:	01/08/1988
From:	Tucker J UTAH POWER & LIGHT CO.
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Text

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fA' 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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PREFILED TESTIMONY OF JAMES D. TUCKER 8805110012 880509 PDR ADOCK 05000344 T

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EXHIBIT NO. 12 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION

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Utah Power & Light Company

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PacifiCorp

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Docket No. EC88-2-000 PC/UP&L Merging Corp.

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PREFILED-TESTIMONY OF JAMES D. TUCKER ON BEHALF OF UTAH POWER & LIGHT COMPANY PACIFICORP PC/UP&L MERGING CORP.

January 8, 1988

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UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Utah Power & Light Company

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PacifiCorp

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Docket No. EC88-2-000 PC/UP&L Merging Corp.

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AFFIDAVIT STATE OF UTAH

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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 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; aad that he adopts these answers as his own.

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s James D. Tucker SUBSCRIBED AND SWORN to before me this 6+. day of January, 1988.

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Notary Public i

My Commission Expires Residing at:

December 4, 1989 Salt Lake County, Utah

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SUMMARY

OF TESTIMONY OF JAMES D. TUCKER.

t ISSUES ADDRESJI.Q

's-1.

Description of UP&L and PP&L transmission systems.

2.

Organization and function of the Western. Systems Coordinating Council (WSCC).

3.

Interactions in an interconnected electrical system.

4.

UP&L transmission limitations.

5.

Regional transmission capabili*.ies.

6.

Transmission operating constraints.

7.

Potential new transmission.

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f CONTENT AND CONCLUSIONS r

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Descriotion of UP&L and PP&L Transmission Systems l

UP&L's transmission system generally runs north to south and j

includes transmission line voltages up to 345 kV from Idaho and Wyoming on the north to New Mexico and Arizona on the south.

PP&L owns a substantial 230 kV network in Wyoming and two 345 kV transmission lines which extend from the Bridger generation plant to the Idaho Power Company's Borah and Kinport Substations.

PP&L also owns a 500 kV transmission line from the Midpoint substation in Idaho to the Malin Substation near the northern California border.

PP&L slso has various contract entitlements.

PP&L's

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Wyoming coal-fired plants are used to meet PP&L's Wyoming load

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t requirements and to provide for its Northwest loads as well.

As a result, PP&L's transmission and contract rights are used in an east'to vest direction.

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PP&L and UP&L are interconnected at Naughton.

Transmission

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additions, including a phase shifter, will increase the transfer

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capability of the interconnection.

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Western Systems Coordinatina Council (WSCC)

UP&L and PP&L are integrated with other utilities in the vestern United States into the WSCC.

WSCC, a voluntary i

t organization encompassing essentially all of the electric j

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s. utilities in the-vestern United States, vestern Canada and a portion of northwestern Mexico, was organized to fester inter-utility cooperation and thereby maintain the reliability of the interconnected bulk power system.

Interactions in an Interconnected Electrical System Because there is no storage of electrical energy, electrical transmission systems are intentionally looped or paralleled, thus providing multiple paths between the load and the generation.

The trade-off for this increased reliability is the loss of control over the actual electrical path used by the electricity.

Power flowing on paths other than on designated contract paths is called "loop flow."

i Loop flow can be controlled within li,mits by a phase shifting transformer or phase shifter.

Actual power flow is thereby directed to the line on which it is scheduled to be moved.

The phase shifter to be installed at Naughton vould be operated such that the actual flow between the present PP&L Wyoming area and the UP&L area vould be the same as the scheduled flow.

PP&L schedules its Wyoming generation to serve its Oregon f

area load since PP&L has insufficient generation in Oregon to meet its load in that area.

If PP&L is able to purchase generation in the Northwest area, then it could reduce generation

_4 in Wyoming, thereby reducing the vesterly flow from Wyoming to Oregon.

If the Wyoming generation vere, in turn,-scheduled to j

UP&L across the Naughton phase shifter, the loop flow impact on other utilities vould be minimized.

The merger vill not result

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in any worsening of loop flow conditions.

UP&L Transmission Limitations UP&L has recently completed studies which show that there is a transfer capability limit on the amount of power that the UP&L system can receive from the Northwest simultaneously with the amount of power being delivered from Naughton.

The simultaneous transfer capability into the Ben Lomond area vest of Naughton is, as a result, limited, since it is expected that as a result of the merger the transmission vest of Na,ughton vill be more fully utilized between the merging utilities.

Existino Recional Transmission Caqabilities r

Through a map, the major load and generation resource areas t

of WSCC and the relative size of the transfer capabilities are explained.

Transfer capabilities from the racific Northwest into California are described.

Approximately 8% of the total capacity i

into the California market : rom the Northwest would be controlled by the merged company.

6 Of the total capacity of 5620 MW from Arizona into California, UP&L and PP&L do not own or control any capacity.

As a result, the merging companies control less than 4% of the existing capacity into California from the Northwest and Arizona combined and the merger would not increase that control.

Approximately 5000 MW of new transmission is being constructed into the California area.

The merged company would control only 10-15% of that new capacity.

Transmission operatino Constraints The safe, simultaneous operating limit of all of the lines into California is less than the sum of the individual contract path limits.

As the flov from Arizona to California increases, the flow on the AC Pacific Intertie must be reduced to stay within a safe operating range.

Similarly, the maximum transfer capability from Arizona to California is reduced to 4200 MW vhen the flow on the AC Pacific Intertie is 3200 MW.

Other constraints result from the requirement, under certain circumstances, to isolate Arizona, New Mexico, California and Southern Nevada from the WSCC System; from the limited availability of the transmission lines from the Four Corners area into Califiornia and Phoenix and from minimum generation requirements from plants physically located in California.

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t In addition to UP&L's transmission into the Four Corners l

i area, the Western Area Power Administration and Colorado-Uto Electrical Association have transmission from Colorado into the i

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Four Corners area with capacity comparable to that owned by UP&L into Four Corners.

UP&L has no assurance of firm access to the California market.

Even into the Four Corners area, UP&L competes with 4

Colorado utilities.

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Potential New Transmission

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Other transmission lines are being studied and evaluated for

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possible construction that would provide access into the California market.

With thousands of megawatts of transmission l

l capacity additions being discussed, the relative portion of the

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western transmission-network controlled by the merged corporation i

is certain to diminish.

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J. D. Tucker 1-y QUESTION 2

Please state your name.

ANSWER 3

James D. Tucker.

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QUESTION 6

What is your business address?

ANSWER 7

g My business address at Utah Power & Light Company 9

(Utah Power or UP&L) is 1407 W.

North Temple St.,

Salt 10 Lake city, Utah.

11 QUESTION 12 What is your porition with Utah Power?

ANSWER 13 I am an electrical engineer currently employed as 14 15 the Manager of Transmission Planning for UP&L.

I am 16 responsible for *.he conceptual design of UP&L's trans-17 mission system.

gg QUESTION What is your educational and professional back-19 20 gr und.

ANSWER 21 I graduated Magna Cum Laude from Brigham Young 22 23 University in 1972 with a Bachelor of Science degree in Electrical Engineering.

I also received a Masters of 24 25 Engineering Administration from the University of Utah in 1979' 26 F5/001

J.D. Tucker OUESTION y

What are y ur duties at Otah Power?

2 ANSER 3

I have been associated with UPt.L since 1972.

In 4

1979 I be ame the Supervisor of the Transmission Planning 5

6 Department, and in 1985 I became Manager of Transmission 7

Planning.

I supervise eleven engineers.

The respon-8 sibility of our group is to perform technical studies and 9

analyses on the transmission system and to provide 10 technical support to Utah Power.

yy In addition, I am currently Utah Power's representa-tive t the Western Systems Coordinating Council (WSCC) 12 13 Planning Coordination Committee.

I am the past chairman of the WSCC Technical Studies Subcommittee where I served 14 from 1985 to 1987.

I have also been a member of the 15 16 Reliability Subec=mittee since about 1980.

I am one of 17 the two WSCC representatives on the North American Elec-yg t:ic Reliability Council (NERC) Engineering Committee.

QUESTION 79 20 Are y u a registered professional engineer?

ANSWER 21 Yes.

I am registered in the State of Utah.

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QUESTION g

What is the purpose of your testimony in this pro-24 25 C'*di"97 26 F5/001

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J. D. Tucker ;

ANSWER I have been asked to describe the transmission 2

system in the western United States as it relates to the 3

issues which have been raised.

These issues include:

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system.

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The transmission limitations in the northern 7

8 UP&L system.

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The general' transmission capability between 9

10 regi ns within WSCC.

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Operating constraints in the interconnected yy 13 WSCC transmission system.

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Potential transmissien projects and their 13 impact on access to regional markets.

74 QUESTION 15 Will y u ffer any exhibits in the course of your I,

16 17 testimony?

ANSWER g

Yes.

I have one exhibit, Exhibit No. 13, consisting i

79 f 11 Schedules.

It was compiled under my supervision 20 an direction.

21 QUESTION 22 Are yu f amiliar with the transmission system of 23 Pacific Power & Light Company (Pacific Power or PP&L) as 24 25 described in Mr. B ucher's testimony?

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J. D.' Tucker ANSWER y

Yes, I am.

2 OUESTION 3

Would you please briefly describe the UP&L and PP&L 4

transmissi n systems?

5 ANSWER 6

Yes, Schedule 1 of Exhibit No. 13 is a me.p of the 7

western United E :ates which includes a simplified rep -

g resentation of the UP&L and PP&L transmis: tion system.

9 10 The UP&L system is shown in red and the PP&L system is shown in blue.

Also represented on the map are dashed 11 yg lines representing transmission contract enti 1tments of PP&L, as testified to by Mr. Boucher.

A more detailed 73 transmission map of the western United States appears as 14 Schedule 7 of my Exhibit.

15 As illustrated on Schedule 1,

UP&L's transmission 16 17 system generally runs north to south and includes trans-mission line voltages up to 345 kV frem Idaho and Wyoming gg on the north to New Mexico and Arizona on the south, 19 Pacific P wer wns a substantial 230 kV network in 20 Wy ming and two 345 kV transmission lines which extend 21 from the Bridger generation plant to the Idaho Power 23 Company's (IPC) Borah and Kinport Substations.

Pacific Power also owns a 500 kV transmission line from the 24 Midp int substation in Idaho to the Malin Substation near 25 the northern California border.

As testified to by Mr.

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J.D. Tucker Bcucher, PP&L has various entitlements of transmicsion y

capacity.

Pacific Power has a 1600 megawatt (MW) con-2 tract entitlement across the IPC system for PP&L's 3

Wyoming generation in an east to west direction as 4

pr vided in a 1980 transmission service agreement between 5

IPC and PP&L.

PP&L also has transmission entitlements in 6

7 the AC Pacific Intertie and various wheeling agreements g

with Bonneville Power Administration (BPA).

9 Although PP&L has generation resources in the Pacific Northwest (Northwest), these resources are not 10 ty sufficient to cover PP&L's Northwest load responsibility.

12 Pacific P wer has constructed and participates in Wyoming 13 coal-fired plants to meet PP&L's Wyoming load requirement and to provide resources for its Northwest loads.

14 Th'#*f PP&L's transmission and contract rights are 15 used in an east to west direction.

The PP&L system has been interconnected with Utah y7 P wer since the early 1960's at UP&L's Naughten Sub-18 station.

New transmission additions including a phase 79 shifter will be installed, as testified to by Mr.

20 Boucher, to increase the transfer capability of this 3y intere nnection.

22 OUESTION 23 i

Are the UP&L and PP&L syctems interconnected with 24 25 ther utilities in the western United States?

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J. D. Tucker..

ANSWER y

Ye.

The utilities in the western United States are 2

integrated into the Western Systems Coordinating Council 3

4 system.

Schedule 2 of Exhibit No. 13 is a copy of the 1987-1988 Biennial Report of WSCC.

5 QUESTION 6

Would you briefly describe the organization and 7

g function of WSCC7 ANSWER 9

Yes.

The Western Systems Coordinating Council is a 10 11 voluntary organization which has 61 members encompassing 12 essentially all the electric utilities in the western 13 United States, western Canada and a portion of northwest-ern Mexico.

The total WSCC generation capability is 14 15 r ughly 145,000 MW or approximately 20 times the merged 16 mpany's generation capability.

Most of the intervening western utilities or organizations are members of WSCC, 17 as are UP&L and PP&L.

A list of the WSCC members is yg 19 shown on page three of Schedule 2, WSCC was organized in August of 1967 to foster 20 gy inter-utility cooperation, thus providing a forum for the 22 rdination of operation and planning activities of the

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e 23 member systems.

The primary purpose of this coordination 24 is to maintain the reliability of the interconnected bulk 25 p wer system.

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J. D. Tucker I QUESTION y

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2 Y u menti ned that WSCC is a voluntary organization, j

How does this organization foster inter-utility ' coop-3 l

eration?

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6 Inter-utility cooperation is fostered by focusing i

7 the attention of all the member systems on a common goal.

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8 WSCC has coordinated various programs.

One example is a

-9 program to mitigate the adverse impact of loop flow, 10 which I will discuss later in this testimony.

The WSCC yy Reliability Criteria for System Design is another example 12 f inter-utility cooperation fostered by WSCC.

Schedule 13 3 of my Exhibit is a copy of these criteria, f

00ESTION f

14 15 Please describe this Schedule.

f MSWR 16 17 These criteria are the basis for transmission system gg design in the western United States.

They have been I

19 appr ved and accepted by the WSCC members.

Adherence to these criteria by the member systems gives reasonable 20 i

assurance that the reliability (which is the ability to j

21 22 e ntinu usly supply load) of the network vill be main-23 tained even during a transmission outage.

These criteria recogni:e that an outage in one 24 25 member system may, in fact, adversely impact a neighbor-26 ing system, and they establish the extent to which a f

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y system may impact another neighboring system for distur-bances of various levels of severity.

2 QUESTION 3

4 Do you believe that the Western Systems Coordinating 5

Council has been effective aa an organization?

ANSER 6

Yes.

Even though WSCC is a voluntary organization, 7

it is very ef fective.

The organization's goal is to g

9 resolve problems of mutual concern and many years of 10 experience dem nstrate that the combined effort and yy mutual agreement have been effective.

12 INTERACTIONS IN AN INTERCONNECTED ELECTRICAL SYSTEM 73 QUESTION 14 Are ceasional adverse impacts common in an inter-15 16 e nnected electrical system?

ANSWER y7 Yes.

However,

e benefits derived from intercon-gg 19 nected system operation far exceed the adverse impacts.

OUESTION 20 Please explain how adverse impacts occur in an 21 22 interconnected system, ANSWER g3 24 The adverse impacts result from a unique feature of electrical energy supply systems.

In an electrical 25 26 system, there is no storage of electrical energy.

As a F5/001

J. D. Tucker..

result, a customer cannot purchase in advance additional 1

2 energy f r use at a later time.

This means that when a 3

customer simply turns on an electrical switch, he placea 4

an order for electricity -- the order is processed, sent t

manufacturing, the product is manufactured, shipped 5

6 back to the consumer, and consumed -- all in less than a fraction of a second.

This is significantly different 7

from the purchase of any other kind of energy.

For g

9 example, when a person purchases gasoline, he maintains 10 1 cal storage of energy in the gas tank of his automo-bile.

There is additional storage at both the retail 11 location and the wholesale refineries.

As a result, a 12 13 momentary or even longer interruption in a supply pipe-74 line between an oil producer and the refinery would not 15 be n ticed by the e nsumer.

Without special design considerations, the same 16 would not be true of an electrical transmission network, 77 tg An outage in an electrical network would be noticed 79 ir=ediately because there le no energy storage.

The lack 20 f storage creates a time dependency for electric power t

21 that is unique to this industry.

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3 Because of the inherent physical differences in the 23 storage characteristics of non-electrical energy systems i

and electrical energy systems, the respective trans-34 s

'5 mission systems are designed and operated very different-26 ly.

Supply pipelines are designed using a radial or l

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t tree-type design.

In such a design the pipelines are not Perated in parallel.

In these systems, it is very easy 2

to control the flow of the fluid to a given destination 3

and, in fact, to trace the path used by the energy 4

5 system.

In contrast to this, electrical transmission 6

systems are not designed radially but, in fact, are 7

intentionally looped; in other words para 1191ed or t

g integrated.

The reason for looped design is to achieve the reliability and continuity of supply that other 9

10 energy delivery systems can achieve through storage.

When an electrical system is operated, multiple 11 13 parallel or looped electrical paths exist between the 13 load and generation, and the electric utilities do not generally have control of the path over which energy will 14 fl w in a 1 ped system.

However, a substantial gain in 15 l

j 16 reliability is achieved by such a design, in that a transmission line can be lost from service in a looped 17 network without affecting the ultimate supply of elec-gg 19 tricity to the customer.

cursTION 20 You have indicated that the trade-off for this gy 22 increased reliability in a looped network is the loss of i

control over the actual electrical path used by the l

23 24 electricity.

Could you please explain that?

use 25 Yes.

Since the systems are looped, there is, by 26 FS/001

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J. D. Tucker.

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y design, more than one electrical path from the generation to the load.

Because of a physical law of nature, Ohms 2

i Law, electricity will use all of the electrical paths 3

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between the generation and the load without regard to 5

wnership r c ntract rights.

While the relative propor-ti n f fl w is dependent up n the length and operating j

6 y ltage of each path, all paths, as a matter of physics, 7

g are used to transfer power from the generation source to the load source.

Despite the use of all the available 9

10 paths, one or more paths are generally designated by j

11 contract as the contract path or paths.

The power i

12 flowing on undesignated paths is called loop flow.

1 QUESTION 3

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4 Is a looped or integrated system a standard utility l

d**1 "?

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ANSWER gg Yes.

A looped design is the standard.

Intercon-y7 tg nection of regional systems beginning half a century ago 19 has made the modern power system possible.

It is under-l 20 stood that integrating or looping a system will result in 4

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21 parallel fl ws or loop flows on all other paths.

The 1

benefit is that a continuous supply of elec ricity is 22 maintained in the event of a transmission outage even 23 i

though there is no storage of electricity in the system.

24 As a resv.lt f the 1 ping design in the Wscc system, 25 j

e nsumers served by that system can be assured of 26 T5/001 2

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essentially a continuous supply of electricity, even though there are no mechanisms to store such energy.

The i

2 trade-off of loop flow is a small price to pay for such 3

reliability assurance, f

4 outSTIoN 5

6 Mr. Tucker, do you have a simplified illustration of 7

loop flow on an interconnected transmission system?

ANSWER g

Yes.

Schedule 4 of my Exhibit shows a hypothetical 9

10 network involving four different utilities identified as yy A,

B, C and D and interconnected with six transmission lines.

In addition to showing loop flow, this Schedule y;

13 will be helpful in explaining the termo contract path, 14 contract path limit or flow limit, actual power flow and 15 scheduled power flow, OUESTION gg Please describe the Schedule.

77 18 gSWER For illustrative purposes, this Schedule assumes gg that all the transmission lines are the same length and 20 the same voltage and have the same relative impedance or 37 resistance.

Also, it is assumed that the ownership of 22 the transmission lines is as shown and that each trans-23 24 mission line has a 200 MW capacity.

Assume that utility c wishes to sell 100 MW to 25 26 utility A.

The contract path is the transmission line i

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from utility C to utility A (line C-A), which is owned by y

utility C.

The contract path limit is the physical 2

simultaneous limit of the contract path which is 200 MW.

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No transaction should be made which exceeds the contract path limit, regardless of how the actual power flows.

5 The scheduled flow is the amount ofithe sale or 6

transaction that is contracted to flow on each trans-7 g

mission line.

In this example, the scheduled flow is 100 g

MW from C to A oc line C-A, and zero on all other lines, 10 since there are no other transactions in this example.

11 The actual power flow is the actual power that flows on each line.

As s-vn in this example, 61.5 MW flow on 13 the contract path, line C-A, and the remaining 38.5 MW 13 flow on the other lines.

The amount that flows on each y4 15 f the lines is a result of the relative line lencths and 16 ther characteristics of the system.

17 Loop flow is the difference between the actual power fl w and the scheduled power flow on a path or, put 18 19 another way, it is the amount of scheduled power that d es not flow on the contract path.

20 QUESTION 21 22 Is it p ssible to control the flow in a transmission 23 line and thereby eliminate loop flow?

NSWER 24 25 Yes, within limits.

By installation of a phase 26 F5/001

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shifting transformer, or phase shifter, it is possible to y

direct the' actual power flow to the line on which it is 2

scheduled,'and thereby eliminate the loop flow associated 3

with that transaction.

As Mr. Boucher has testified, our 4

5 pr p sed interconnection upgrade between UP&L and PP&L at 6

Naughton will include' a phase shifter.

This phase 7

shifter.will allow power transfers between the Wyoming and UP&L areas to be controlled so that little or no g

9 burden to other interconnected utilities will occur.

QUESTION 10-Is it a standard utility practice to install phase 11 73 shifters on interconnections to control power?

ANSWER 13 No.

In fact, only a few phase shifters exist in the 74 entire western United States.

Generally, intercon-15 nections are constructed and transactions take place 16 without installing phase shifters, 77 yg QUESTION How would the proposed phase shifter at Naughton 19 affect 1 p fl w alleged to be created by the merger?

20 ANSWER 21 The phase shifter would be operated such that the 22 23 actual flow between the present PP&L Wyoming area and the 24 UP&L area w uld be essentially the same as the scheduled fl w.

Therefore, little if any loop flow would be 25 created.

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D. Tucker.,

QUESTION y

Is it possible. for PP&L to purchase additional 2

generating resources in the Northwest and what affect 3

would this have on loop flow?

4 ANSWER 5

PP&L schedules its Wyoming generation to serve its 6

7 Oregon area load since PP&L has insufficient generation g

in Oregon to meet its load in that area.

If PP&L in-9 creased its Northwest purchases to serve its Oregon area 10 1 ad by 100 MW, for example, then an equivalent amount of yy PP&L's Wyoming resources would not be required to supply that load.

As a result, 100 MW of PP&L Wyoming gen-73 13 erat an w uld be unused, and the transmission requirement fror foming to the Northwest for this 100 MW would no g

1 nger be needed r used.

Reducing the amount otherwise 15 scheduled from Wyoming to the Northwest by 100 MW would 16 77 eliminate not only-the loop flow, but also the scheduled yg flow associated with the power that was formerly being scheduled.

While this creates system flow changes, the 19 20

. changes are a result of removing effects, not increasing effe ts.

21 QUESTION 22 If this 100 MW of PP&L's Wyoming power were, in 23 24 turn, scheduled to UP&L, what would be the impact on the 25 transmission system?

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ANSWER This schedule would be made across the Naughton 2

phase shifter, utilizing the UP&L/PP&L transmission 3

system and, thereby, minimizing the loop flow impact on 4

. ther utilities.

5 6

WSCC LOOP FLOW MITIGATION 7

g QUESTION g

Has WSCC addressed the problem of dealing with loop fl "i 10 ANSWER yy Yes.

WSCC has used various cooperative means of 12 13 ace mplishing loop flow mitigation in the past, and has a 14 proposal currently before the WSCC member systems.

Schedule 5 of Exhibit No. 13 is the current WSCC proposal 15 for loop flow mitigaticn and compensation, and a copy of yg the transmittal letter urging its adoption.

17 QUESTION g

Would you please describe the Schedule?

79 ANSWER 20 Yes.

WSCC has struggled with various ways to handle 21 the loop flow issue for the past 17 years.

All past 22 23 attempts to mitigate the impact of loop flow have cen-tered ar und schedule reductions or contribution of funds 24 25 by member systems whose schedules were creating loop fl w.

The current proposal adopts a no-fault approach.

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J. D. Tucker...

In this-approach, member systems make contributions of y

funds based on the proportion of total generation and 2

purchases as reported in FERC Form 1 (p. 401, lines 9 and 3

10).

These funds would be used to compensate or partial-4 3

ly compensate member systems who were required to reduce schedules as a result of loop flow.

It should be noted 6

that under this proposal there is a requirement for 7

g member systems to accommodate loop flow by the greater of 9

50 MW or 5% of the contract path limit before a claim can be made.

10 yy QUESTION Are Idaho Power Company and Montana Power Company 12 (MPC) members of WScc?

i 13 ANSWER 74 Yes.

15 ig QUESTION 77 Are they familiar with this proposal?

ANSWER yg Yes.

This proposal has been discussed at various 19 20 utility meetings and the transmittal letter to all WScc representat'ves, page one of this Schedule, was mailed on i

31 October 30, 1987.

22 23 QUESTION 24 Mr. Tucker, does the Reliability Criteria for System 25 Design, previously introduced as Schedule 3 of your 26 Exhibit, contain any statements concerning loop flow?

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ANSWER y

Yes.

As stated on page three, "Loop flow is an 2

3 haracteristic of interconnected AC systems and inherent the mere presence of loop flow on circuits other than 4

those of the transfer path (contract path) is not neces-5 6

sarily an indica -ion of a problem in design or in 7

scheduling practice."

g QUESTION

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9 Mr. Tucker, would you please summarize your con-10 clusions concerning the impact of the merger and result-11 ing schedules on loop flow?

ANSWER 12 Yes.

Loop flow is a normal and expected result of 13 14 operation within an interconnected electrical network.

15 The increased reliability benefits gained from operation 16 within an interconnected network far outweigh the nega-17 tive aspects of loop flow.

WSCC is an appropriate and w rkable forum for utilities to discuss and implement 18 yg loop flow mitigation measures such as the one that is 20 currently before the member systems.

21 The merger, in and of itself, will not result in any 22 w rsening f 1 p fl w c nditi ns.

Indeed, the impact 23 will either be harmless or positive when compared to the 24 status quo.

Pacific Power and Utah Power have committed t

the installation of a phase shifter at the Naughton 25 26 interconnection point to minimize the loop flow created F5/001

c y

'J.

D.

Tucker,,

by schedules between PP&L generation in'Wycming and Utah y

P wer.

This would be an improvement over operation in 2

today's system without the phase shifter, wherein sched-3 ules from PP&L generation in_ Wyoming to UP&L presently 4

reate 1 p fl w n the paralleling systems.

5 6

UP&L TRANSMISSION LIMITATIONS 7

g gESTION Mr. Tucker, have you identified any limitations on 9

the UP&L system which will be impacted by scheduling 10 yy power from PP&L's Wyoming generation to UP&L?

ANSWER 12 Yes, we have.

Generation from the PP&L-Wyoming area 13 to the UP&L system dela.vered at Naughton would require 14 the utilization of transmission facilities from Naughton.

15 UP&L has recently completed studies which show that there 16 is a transfer capability limit on the amount of power 17 that the UP&L system can receive from the Northwest yg utilities simultaneously with the amount of power from 79 the Naughton generation site.

This simultaneous limit 20 has been put into a chart known as a nomogram.

A 21 22 n m gram charts the safe transfer capability and is the standard WScc practice for displaying simultaneous limits 23 when they occur.

24 QUESTION 25 Do you have a nomogram which illustrates this 26 F5/001

J. D. Tucker,,

simultaneous limit?

y ANSWER 2

Yes.

Page 1 of Schedule 6 of my Exhibit is a. copy of a nomogram of the Naughton/ Northern' Utah system.

This 4

harts the simultaneous transfer capability into the Ben 5

Lomond area.

g 7

Page two of this Schedule is a diagram showing the transmission lines involved with this simultaneous g

transmission constraint and identifies the transmission 9

10 line paths that make up the axes for the nomogram.

The nomogram is constructed to identify the safe yy 12 operating region for flows on two different transmission 13 paths where there exists inter-dependence between the transmission capability of the two paths.

In this case, 14 the fl ws west from Naughton are plotted on the horizon-15 tal axis and the flows across the northern Utah system 16 (transmission lines associated with these flows are 77 yg listed on page two of this Schedule) are plotted on the vertical axis.

Only operation inside the nomogram is 79 20 acceptchie.

QUESTION 21 22 Why is there inter-dependence on these transmission 23 paths?

ANSWER 24 25 Transfer capabilities are determined by testing the 26 F5/001 i,_

1 J.D.

Tucker,,

system through simulating the system network response for y

a line utage.

If lines that are generally in parallel 2

to the tested outage are unloaded, then the parallel 3

. transmission is better able to support the outage being 4

tested.

The reverse is also true.

Therefore, the 5

n rthern Utah path, whose rating is 1000 MW when the flow 6

7 fr m Naughton to the west is low, must be de-rated to about 800 MW when the flow from Naughton to the west is g

9 high.

10 QUESTION How is this nomogram used to determine what, the 11 12 transfer capability is into Ben Lomond?

ANSWER 13 Since the flows on both paths ultimately come into 14 the Ben Lomond area, the constraint can be approximated 15 16 by limiting the flows into Ben Lomond to 1450 MW, which is the average of the Ben Lomond flows for the two corner 17 points of the nomogram.

yg QUESTION 79 20 Mr. Tucker, what do you conclude from this Schedule?

ANSWER 21 c

The transmission system north of Ben Lomond is 22 23 constrained to approximately 1450 MW and the simultaneous 24 transmission capability of the northern UP&L system, as defined n this Schedule, will be reduced from 1000 MW to 25 26 aPProximately 800 MW when the transmission west of F5/001

F-J.

D.

Tucker,

1 Naughton is utilized.

This will reduce UP&L's ability to imp rt power from the Northwest.

It is expected that as 2

a result of the merger,the transmission west of Naughton 3

will be more fully utilized for power exchanges between 4

th' **#9 "9 "tiliti*

1 5

6 EXISTING REGIONAL TRANSMISSION CAPABILITIES 7

g QUESTION 9

Mr. Tucker, do you have a Schedule which illustrates the transmission in the WSCC area?

10 ANSWER 11 12 Yes, Schedule 7 of my Exhibit No. 13 is the latest 13 WSCC 10-Year Map showing Planned Facilities through 1996.

QUESTION 14 Mr. Tucker, is it nectmsary to consider all trans-15 mission limitations within WSCC to understand the concep-16 tual transmission operation?

17 ANSWER 18 No, I don't believe so.

While each of these lines 19 is considered significant by its owners, and while many 20 of them are significant to the WSCC region, the conceptu-31 al essence of WSCC can be more clearly seen from breaking 22 d wn the WSCC map into a more simplified system.

Sched-23 ule 8 of my Exhibit shows a simplified schematic diagram 24 f the WSCC load control areas connected by lines 25 26 F5/001

f.

J.D. Tucker.,

representing the transmission paths or connections 7

between these areas.

2 QUESTION 3

Please explain this diagram.

4 ANSER 5

The transmission paths combine the significant and 6

numerous (in most cases) actual transmission lines 7

between the areas with the non-simultaneous transfer g

g capacities shown by each transmission path.

Each trans-10 mission path is identified by a circled path or con-nection number.

The specific transmission lines that 11 73 comprise the transmission path are listed by connection number n the following pages of the Schedule, 13 QUESTION y

Can the WSCC area transfer capabilities be further 15 simplified?

16 ANSWER 77 Yes.

Schedule 9 is an eleven-page Schedule illus-18 trating the essence of the existing WSCC transmission 79 apabilities between WSCC regions including the near-term 20 transmission additions.

WSCC divides the WSCC network 21 into the four regions depicted on this Schedule,

,&2 QUESTION 23 Please explain this Schedule.

3 ANSER 25 26 Page ne illustrates the four WSCC regions and the F5/001

J.

D. Tucker.,.

size of'the transfer capabilities between regions.

The y

size of the circle represents area generation and the 2

width of the transmission corridors is representative of 3

the transfer capability between regions.

The left side 4

shows the existing transfer capabilities, while the right 3

side shows the existing transfer capabilities including 6

the near-term transmission additions, 7

The following five pages of this Schedule tabulate g

the estimated transmission capacities shown on page one 9

and indicate the utility or utilities which own or have 10 entitlements in the transmission paths.

-yy OUESTION 12 Does the transfer capability of 6430 MW between the 13 Northwest region and the California region include only 14 the Pacific Interties from the Pacific Northwest to 15 California?

16 ANSWER 77 No, the 6430 MW transfer capability includes all gg transmission between the Northwest region and the yg california region.

This includes not only the Pacific 20 Interties, but also the transmission from Reno, Nevada 21 wned by Sierra Pacific Power Company (Sierra Pacific) to 22 California and the AC transmission from the Intermountain 23 t

P wer Pr ject (IPP) located in west central Utah.

The 24 Interm untain Power Project is in the California load 25 control area.

26 F5/001

J.

D.

Tucker,,

{

QUESTION W uld you briefly describe the transmisnion capacity 2

fr m the Pacific Northwest into California?

3 ANSWER 4

5 As shown on page two, the capacity of the two 500 kV 6

AC lines that comprise the AC Pacific Intertie (line #14) and the PP&L Weid Junction 115 kV line (line #16) are 7

g 3200 MW and 100 MW, respectively.

Also shown is the 500 kV DC Pacific Intertie (line #18) with a capacity of 1956 g

MW.

The total capacity of these transfer paths is 10 yy approximately 5256 MW.

OUISTION 13 How much of this 5256 MW of capacity is controlled 13 by PP&L or UP&L?

74 ANSWER 15 Pacific Power owns the 100 MW capacity in its 16 17 low-voltage line and has a 300 MW entitlement in the AC Pacific Intertie.

Utah Power has no rights on these yg lines.

As a result, the total capacity that would be yg controlled by the merged company directly into the 20 California market would be 400 MW, or approximately 8%.

21 BPA e ntr is 2100 MW on the AC Pacific Intertie and all 22 f the DC Pacific Intertie.

The proposed long-term 23 intertie access policy may ultimately allocate a small 24 mn unt of additional capacity to PP&L, as described by 25 Mr. Boucher.

26 F5/001

• P tt J. D. Tucker..

4 y

QUESTION W uld you please describe the existing transmission 2

capa ity from Arizona into california.

3 ANSWER 4

As shown on page three, the total capacity between 5

Ariz na and california is 5620 MW (line #32).

Utah Power 6

and Pacific Power do not own or control any of this 7

8 capacity.

g QUESTION Mr. Tucker, what do you conclude concerning the 10 11 present transmission capacity into the california market?

ANSWER 12 I conclude that the merging companies control less 13 than 4% of the exis'.ing transmission capacity into 14 california, and the merger would not increase that 15 16 percentage.

QUESTION 37 Mr. Tucker, will near-term additions alter this ig situation?

19 ANSWER 20 While the near-term additions will increase the g

transmission capacity into california, they will not 22 23 materially affect the merged company's share of trans-mission to the california area.

The right hand side or 24 25 page one of Schedule 9 shows the transfer capabilities vith the near-term additions.

26 l

F5/001

i.

J. D. Tucker.

The tabulations' included illustrate-ownership' land control of the paths.

Also included in this Schedule, beginning at page seven, is a geographic description of 3

the near-term additions including the approximate _com-4 pletion time, possible participants and an estimate of 5

the capacity.

6 The geographic descriptions included in this Sched-7 ule demonstrate that there are near-term facilities g

9 planned which will dramatically increase the transfer 10 capability into the California area.

QUESTION yy Please~ describe the 345 kV line from Sigurd to Las 12 13 Vegas shown on page seven of this Schedule, indicating its capacity and purpose.

14 15 gSm 16 This 345 kV line will be constructed by UP&L for two 17 purposes:

1) to reinforce the transmission capacity into its southwestern Utah load area, and 2) to establish an 18 interconnection between Utah Power & Light Company and yg 20 Nevada Power Company (NPC).

Agreements have been signed 21 between UP&L and NPC providing for a 50 MW sale at 100%

1 ad factor (all the time) from Utah Power to Nevada 22 23 Power Company.

In addition to this base-load capacity, the agreement provides for 90 MW of peaking capacity 24 25 during the f ur summer months.

26 F5/001

t J.

D. Tucker 28 -

The transmission facilities constructed in Nevada y

w uld be owned by NPC and the transmission facilities in 2

the State of Utah would be constructed by Utah Power and 3

probably owned jointly by UP&L, the Utah Associated 4

Muni ipal P wer Systems (UAMPS) and Deseret Generation &

5 Transmission Co-operative (DG&T).

Negotiations are 6

currently underway to establish ownership percentages or 7

transmission contract rights in this new transmission 8

line.

g 10 QUESTION Do the negotiations between Utah Power, UAMPS and 11 DG&T deal only with capacity on the 245 kV line from 12 13 Sigurd to the Nevada border?

ANSWER 74 No.

Utah Power has included in its offer to DG&T 15 and UAMP3 capacity from UP&L's Mona Substation to i.ts 16 Sigurd Substation.

This would provide a complete trans-g 18 raission path from Mona to the UAMPS' municipal loads in southwestern Utah.

UAMPS' stated purpcse for participa-19 tion in the transmission line betwewn Sigurd and south-20 western Utah is to secure transmission capacity for 21 UAMPS' members, including Washington Cit, which are 22 1 cated in the southwestern portion of the State of Utah.

23 OUESTION 24 What is the capacity of this line?

25 26 F5/001

v.

J. D.

Tucker,,

ANSWER The line will have a 400 MW rating from Utah to the 2

southwestern Utah load area.

However, the interchange 3

capability with Nevada Power Company will be limited to 4

250 MW.

5 QUESTION g

7 Please describe the DC Pacific Intertie uprate shown g

on page eight of this Schedule.

ANSER 9

10 BPA has committed to uprate the DC Pacific Intertie from 1956 MW to 2986 MW, an increase of 1030 MW.

They 11 y2 expect to accomplish this uprate by 1990.

QUESTION 13 Is the merged company participating in this uprate1 14

^" 8 " E 15 No.

16 OUESTION 77 Please describe the new AC transmission line, ig referred to as the Third AC Pacific Intertie, shown on 19 20 page nine f this Schedule.

ANSWER 21 The Third AC Pacific Intertie is a 500 kV AC trans-22 mission line from the California / Oregon border to the 23 Tesla substation in the center of California.

This line 24 w uld add 1600 MW of capacity from the Northwest to the 25 California area.

26 F5/001

J.

D.

Tucker,,

QUESTION p

W uld the merged company have any entitlement in 2

this line?

3 ANSWER Yes.

When the total Ac intertie capability is 5

6 in reased beyond the 3200 MW rating, PP&L will receive an additional 100 MW entitlement.

This would result in a 7

total PP&L entitlement of 400 MW on the AC Pacific g

Intertie.

However, all but 28 MW of this capacity is 9

10 e mmitted to existing long-term contracts.

QUESTION yy Mr. Tucker, would you please describe the 500 kV 12 transmission line between the IPP area and McCullough 13 shown on page ten of this Schedule?

14 ANSWER 15

'4'h i s line would be constructed by Los Angeles l

yg 77 Department of Water & Power.

Utah Power would partici-pate in ownership or contractual rights in this line, but yg the extent of that entitlement has not yet been de-79 termined.

NPC, UAMPS and DG&T are also likely joint 20 participants in the line.

The construction of this line 3

is planned in the 1993 time frame and its capacity would 22 be app: ximately 1000 MW.

23 QU STION 24 Please describe the Palo Verde-Devers No. 2 line 25 shown on page eleven of this Schedule.

26 F5/001

J. D. Tucker _,,

4 ANSWER y

This is a 500 kV line from the Palo Verde' Substation 2

near Ph enix t the Devers Substation near Los Angeles 3

with a capacity rating of 1000 MW.

4 oUESTIon 5

W uld the merged company have any entitlement in 6

this line?

7 ANSWER g

No.

g 10 QUESTION What is the t o t a ". increased capacity of these 11 near-term additions irdo the California area and what 12 13 approximate percentage would the merged company control?

ANSWER y4 The n n-simultaneous total increase in capacity into 15 the California area would be approximately 3900 MW from 16 the Northwest and 1000 MW from the Arizona /New Mexico 77 13 regions for a total increase of about 4900 MW.

PP&L's increase in the Pacific Inter tie is 100 MW.

I 19 Utah Power will have ownership or contractual rights in 20 21 the IPP-McCullough line.

The contract entitlements have nt been established.

Utah Power would maintain owner-22 23 ship rights in the Sigurd to Nevada line, although the 24 amount would be subject to negotiation for joint owner-25 ship between UP&L, UAMPS and DG&T.

I estimate that the 26 i

F5/001

J. D. Tucker,,

merged company entitlement in these lines would be in the y

600 MW range.

2 Therefore, of the roughly 5000 MW of new trans-3 mission being constructed into the California area, the 4

merged company would control only 10-15% of that new capacity.

6 7

TRANSMISSION OPERATING CONSTRAINTS g

OUESTION 9

Mr. Tucker, you testified earlier concerning the 10 11 major transmission lines into the California area market.

'Are there any operational constraints whfch may restrict 12 the opportunity to make firm sales or sales in general 13 into the California area?

14 ANSER 15 Yes.

The total flows into the California area are 16 ccnstrained to operate within a nomogram.

WSCC has 77 i

formd a committee whose sole purpose is to evaluate the yg simultaneous transmission constraints into the Califor'nia 79 area.

These include the AC Pacific intertie and the AC 20 transmission lines between Arizona and California.

This 21 e mmittee is the Pacific and Southwest Transfer Capabil-22 ity (PAST) Work Group.

23 The safe, simultaneous operating limit of the AC 24 Pacific Intertie and all f the lines between Arizona and 25 California is less than the sum of the individual 26 F5/001

J. D. Tucker,

contract path limits.

This may require that power y

transfers be reduced under certain operating conditions.

j 2

The PAST Work Group publishes simultaneous limits for 3

these paths for each season.

These limits are published 4

n a n m gram.

A n m gram harts the safe transfer 5

capability and is the standard practice of illustrating 6

simultaneous transfer limits.

The PAST winter nomogram 7

for 1987-1988 demonstrates that the maximum transfer g

7 capability from Arizona to California is approximately 9

4200 MW when the flow on the AC Pacific Intertie is 3200 10 MW.

(This assumes that three units of Palo Verde are yy operating and that there is approximately 200 MW of flow 17 a r ss the Utah-Colorado boundary towards Arizona and New 13 Mexico.)

As the flow from Arizona to Californic. in-14 creases, the ficw on the AC Pacific Intertie must be 15 reduced in order to stay within a safe operating range.

16 QUESTION y7 A.m e there any other constraints or lin.iutions on yg the total import into the California and Arizona areas?

19 20 ANS q Yes.

In addition to the nomogram studies, the PAST 21 W rk Group determines the total maximum import into the 22 Southern Island (California, Arizona and New Mexico).

23 OUESTION 24 Mr. Tu ker what is the basis for this limit?

25 26 l

F5/001

J.D. Tucker.

ANSWER y

When the AC Pacific Intertie is lost, an automatic separation scheme goes into effect which opens (trips) 3 the transmission systems between Utah / Colorado and 4

between Ari'ona/New Mexico.

This leaves Arizona, New Mexic California and southern Nevada completely sep-6 arated from the rest of the WSCC System.

The total 7

8 imp rt into the Southern Island must be restricted so that generating capacity in the Southern Island is 9

10 sufficient to prevent under-frequency firm load shedding when this occurs.

The winter 1987-1988 rating of this 11 12 limit is 3800 MW during heavy load hours.

QUESTION 13 Are there operating constraints that affect the 13 13 ability to make sales in the California anf. Arizona markets from the Four Corners area?

16 y7

, ANSWER Yes.

There is an operating constraint in th4.1 gg transmission system from the Four Corners area into 79 California and Phoenix.

As a result of this constraint, 20 utilities with access to Four Corners, either through 21 Utah or Colorado, find themselves at an effective dead 22 end in reaching the California market for firm trans-23 mission capacity.

However, when operating conditions 24 permit, it is possible to make non-firm sales to the 25 26 F5/001

.j,'

J. D. Tucker.

California and Phoenix areas from' the Four Corners 1 cation..

2 QUESTION 3

Mr. Tucker, would you describe this constraint?

4 ANSER 5

Yes.

The F ur Corners participants (neither PP&L 6

nor UP&L is a participant) publish a nomogram for the 7

8 safe operation of the Four Corners transmission system.

The transmission limit from the Four Corners area to 9

10 Phoenix and California is approximately 2250 MW.

Since 77 this capacity is essentially utilized by the Four Corners 12

_ generation (2035 MW) and because the participants reserve s me apa ity to accommodate clockwise loop flow, firm 13 transmission capacity from the Four Corners area to

[

14 either Phoenix or California is very limited.

15 QUESTION l

16 17 You have indicated that there is little if any firm j

gg transmission capacity from the Four Corners area.

Is 79 there any non-firm transmission capacity available?

[

ANSER 20 Yes.

On a non-firm basis, UP&L and the other 21 utilities that are interconnected at Four Corners are 22 23 -

able to make surplus sales.

This is dependent upon 24 perating conditions at Four Corners, 25 gurSTIoN i

Are there other operating constraints which limit 26 F5/001

- -. - - -.-.2

J. D. Tucker...

the opportunity to make sales into the California area?

y ANSWER 2

Yes.

California has Certain minimum generation requirements to provide voltage support in the California 4

area, and must maintain capacity for spinning reserves.

The result is that some generation located in California 6

must be operating at all times.

These and other operat-7 g

ing constraints have a tendency to decrease the amount of 9

power that California can purchase from outside the California area.

10 QUESTION yy Please describe the transmission system between 73 Colorado and the Four Corners area.

73 3NSWER i

14 Because of the load conersi bour.daries used for the 15 WSCC regions, this transmission is not shown on Schedule 16 9.

However, the transmission between Colorade and the

3. /

Four Corners area includes the Western Area Power Admin-yg istration's (WAPA) Curecanti-Shiprock 230 kV line and the 79 Craig-San Juan 345 kV line which was just energized by 20 WAPA and Colorado-Ute Electrical Association 3

(Colorado-Ute) in the summer of 1987.

These lines are 22 similar to the transmission owned by UP&L into the Four g

Corners area.

The estimated capacity of these lines is 24

• • 0~'0***

25 26 F5/001

J. D. Tucker.

QUESTION What is the transmission between Utah and Arizona?

2 ANSWER 3

UP&L has a 345 kV transmission line from Pinto to 4

Four Corners which has a capacity of 600 MW and a 230 kV 5

line from UP&L's Sigurd Substation to WAPA's Glen Canyon 6

Substation (reported in the Rocky Mt. region).

Since 7

WAPA fully utilizes the capacity _ south of Glen Canyon, g

9 the Sigurd-Glen Canyon line effectively has no ability to 10 deliver p wer to Arizona on a firm basis, and very little n a n n-firm basis.

As a result, Colorado-Ute and WAPA 11 13 have essentially equal transmission capability into the Four Corners area as does Utah Power.

13 OUEST10N g

Mr. Tucker, what do you conclude fror: this dis-15 16 cussion of transmisrion operating constraints relative to 77 marker.ing opportunities in the California area?

ANSWER 16 19 Alth ugh there is substantial transmission capacity into the California area, these constraints, particularly 20 fr m Four Corners, restrict firm sales to California and 21 Phoenix.

Because of the severe transmission limitations 22 out of the Four Corners area, UP&L has no assurance of 23 firm access to the California market.

Utah Power, in 24 fa t, e mpetes with the Colorado utilities who have 25 26 similar transmission capability to the Four Corners area.

F5/001

.....~

J. D. Tucker.

/

POTENTIAL NEW TRANSMISSION

^

QUESTION Mr.' Tucker, in addition to the near-term' facilities that you have previously discussed, are there other 4

transmission lines which may be Constructed which would Provide access'the California market?

6 ANSWER 7

g Yes, there are.

Undoubtedly many of these lines will be constructed.

9 QUESTION 10 Do you have examples of new transmission being 11 33 studied and evaluated for possible construction?

ANSWER g

Yes, potential transmission lines are shown in 74 s hedule 10 of my Exhibit.

15 QUESTION 16 Please describe the Northwest-Mead !500 kV DC line 77 shown on page one of this Schedule.

yg ANSWER yg 20 There is renewed discussion concerning a new 2500 kV I

DC line from the Northwest to Mead (Las Vegas area).

21 22 This facility would have a capacity of 2200 MW and would likely be constructed to. accommodate seasonal exchanges 23 between the desert Southwest and the Pacific Northwest.

24 25 The p ssible timing for completion of this line is the 26 F5/001

_._-. _.-__.-_.--__-_ _, ~. - -. _ - -

J.D. Tucker 39 -

mid-1990's.

This line seems to be the fall-out from y

earlier discussions of the Inland Intertie.

2 The Inland Intertie project, shown on page two of 3

this Schedule, was a joint study project with approxi-4 5

mately 27 utilities to construct a transmission line 6

between the Boise-Midpoint area in Idaho and the Mead-Las 7

Vegas area in Nevada, with a capacity of between 1600 MW and 2200 MW.

Its completion date would have been the 8

mid-1990's and its purpose was to facilitate seasonal 9

10 exchanges between the Northwest and the Inland Southwest utilities.

Recently several major participants announced 3y that they were withdrawing from the project which has 13 13 sparked renewed interest in the Northwest-Mead 500 kV DC line.

14 15 QUESTION Please discuss the Sierra Pacific interconnection 16 17 with Sacramento Municipal Utilities District (SMUD) shown ;

ig on page three of this Schedule.

ANSWER 19 20 Sierra Pacific and SMUD have studied a 345 kV 21 transmission line across the Sierra Mountains from Reno, Nevada into the California area.

This transmission line 22 33 would have an approximate 400 MW capacity and is planned 24 f r service in the early 1990's.

25 QUESTION 26 Mr. Tucker, are there other transmission lines which F5/001

J.D. Tucker a

may affect the overall operation of WSCC that are cur-y rently being discussed?

2 ANSWER 3

Yes.

One important line is the proposed Canada tie 4

between Washington Water Power Company (WWP) and BC Hydro 5

6 shown on page four of this Schedule.

This transmission 7-line is currently in the permitting-stage and is planned fr perati n in the mid-1990's.

The capacity of this 8

1 9

interconnection would be approximately 1000 MW and would 10 certainly increase the access to relatively inexpensive 17 Canadian hydroelectric power.

Neither UP&L nor PP&L have 12 an entitlement in this-proposed line.

CUE 8 TION 13 14 Are there other proposed lines which are important t

the California Market?

15 ANSER 16 l

Yes.

There a:e two other transmission lines in 17 yg Colorado which may affect access to the southwest and California markets.

These are the Craig-Bonanza 345 kV 19 4

line shown on page five of this Schedule and the uprate 1

l 20 f the Curecanti-Shiprock line from 230 kV to 345 kV 21 22 perati n shown on page six of this Schedule.

The 23 increased capacity from Colorado to the Four Corners area 24 pr vided by the uprate f the Curecanti-Shiprock line would increase Access to the Four Corners area.

The 26 Craig-sonan=a 345 kV line could be useful in delivering 4

F5/001

J.'D. Tuckor.

e, resources from Colorado and Wyoming across the' DG&T y

2--

system t UP&L's Mona Substation.

The California market could be accessed through Mona to the proposed IPP-McCullough 500 kV line.

4 5

one additi nal line that has been reviewed by Sierra Pacific and Nevada Power Company is an interconnection 6

between their utilities which would follow the Nevada 7

g border between Reno and Las Vegas, as shown on page seven 9

of this Schedule.

10 ourSTIoN Are you aware of any other transmission additions yy 13 that affect transmission capacity to the California area?

ANSWER 13 Yes.

The first is a 600-mile transmission line from 14 the Boise area to Las Vegas, proposed by Western Power 15 Inc. which is backed by Idaho industrialist, J.R.

16 17 Simplot.

This transmission line, shown on page eight, w uld have a capacity of approximately 2500 !!W.

The 18 19 second is a new transmission line from Midpoint, Idaho to the IPP area being planned by IPC, MPC and WWP shown on 20 21 P'9' "i"**

Schedule 11 is a copy of news releases from Western 22 P wer Inc. discussing the purpose and background of the 23 24 Simpi t line and a report published in the news data service entitled "Clearing Up" which discusses the 25 26 IPC-MPC-WWF transmission route from Midpoint to IPP.

F5/001

~

ta J.

D.

Tuckor,

QUESTION y

How might the IPP-Midpoint line affect transmission 2

apa ity and access into the California area?

3 ANSWER 4

It would be Constructed to provide new transmission capacity from the Inland Northwest (Idaho, Montana and 6

Washington) to the IPP area presumably to access the 7

g California area through the contemplated construction of 9

the IPP-McCullough 500 kV transmission line.

QUESTION 10 Mr. Tucker, what do you conclude from this dis-yy ussion of all of the new transmission that is being 12

~

g Considered in the western United States?

ANSWER g

I

" 1"d* th"t

""D'**"ti*'

^" ""*"

f "*" C"P" itY 15 into the California and Arizona areas is being planned 16 and actively pursued.

With literally thousands of 77 yg megawatts of planned transmission capacity additions yg being discussed, the merged corporation's relative 20 p rtion of the western transmission network, which would be small upon consummation of the merger, would be 21 certain to diminish.

22 OUESTION 23 24 From a technical standpoint, is it possible for UP&L r PP&L. either by themselves or combined, to control or 25 limit the construction of new transmission into the 26 F5/001

= :.

i.s

~e..

J. D. Tucker California and Arizona areas?

y ANSWER 2

No.

.3 QUESTION 4

_Mr. Tucker, does this conclude your direct testimo-5 6

"Y7 ANSWER 7

Yes, it does.

8 9

10 11 m

12 13 14 15 16 17 18 19 20 j

21 22 23 24 25 26 F5/001

_ _ _ _ _