ML19343B836

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Testimony on Behalf of Util Re Energy Alternatives.Info Re Planned Generation Additions,Sys Capability,Load Purchase Power & Reserve for 1977-1990 Encl
ML19343B836
Person / Time
Site: Allens Creek File:Houston Lighting and Power Company icon.png
Issue date: 12/18/1980
From: Guy J
HOUSTON LIGHTING & POWER CO.
To:
Shared Package
ML19343B832 List:
References
NUDOCS 8012300675
Download: ML19343B836 (20)
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t f DIRECT TESTIMONY OF l DR. J. D. GUY.

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! ON BEHALF OF HOUSTON LIGHTING ~&-POWER COMPANY' RE ENERGY ALTERNATIVES I

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DIRECT TESTIMONY OF DR. J. D. GUY RE ENERGY ALTERNATIVES

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1 Q. Please state your name and position. '

2 A. My name is J. D. Guy and I am employed as Manager 3 of Corporate Planning at Houston Lighting & Power Company 4 (HL&P).

5 Q. Please describe your educational background.

6 A. I have B.S. and Ph.D. degrees from Texas A & M

! 7 University and an M.S. degree from the University of New t

l 8 Mexico in Electrical Engineering. Additionally, I have 9 taxen a number of undergraduate and graduate level courses 10 in economics, finance, and accounting at the University of 11 Houston.

12 Q. Please describe your work experience following 13 graduation from college.

l Following graduation from Texas A & M, I worked.

A.

14 f r four years at HL&P in the Engineering Department; leaving 15 i

HL&P in 1974, I worked at the Atomic Energy Commission as a 16 Power Systems Engineer until 1976. For the past four years, 7

g I have been employed by Houston Lighting & Power Company in g

the Corporate Planning Department and was promoted to Manager l

ae a e , 1980. In this capacity, 20 I am responsible for developing HL&P's long range corporate plans.

Q. What is the purpose of your testimony?

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.- r n A I. A 1 A. First, I will update the Allens Creek Environmsntal 2 Report Supplement with respect to EL&P's demand forecast and 3 the planned capacity additions necessary to meet the pro-4 jected load. I will expi un how the Allens Creek project 5 fits into the company's plans for future generation addi-6 tions. I will explain that we are precluded from construct-7 ing new gas or oil fired generating facilities and that, g therefore, our only alternatives are to construct new nuclear, g coal, and lignite plants. In addressing the contentions on 10 conservation and alternative energy sources, I will be 11 joined by a panel of witnesses who have addressed various 12 parts of the contentions. Dr. Anderson will provide an 13 independent analysis of future demand for electricity on g uTAP's system. Dr. Perl will explain that the various con-

,_ servation measures recommended by the intervenors cannot 2

g eliminate the need for the Allens Creek project. In the

,7 process of that analysis, he considers the energy conserva-tion measures suggested by TexPirg and demonstrates that rather than reducing the need for Allens Creek, these con-servation measures would increase the need for the project because they would increase the need for base load capacity on HLiP's system. Dr. Perl also compares the costs c f the t coal, lignite, gas, and nuclear alternatives and establishes 23 that among these alternatives, nuclear power is the least 24

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1 expensive source of electricity. Dr. Hamilton will address l 2 the comparative health effects of coal, lignite, and nuclear -

3 plants. Dr. Woodson will testify that it is not feasible to 4 replace the capacity of Allens Creek aith a plant that is 5 fueled by the burning of solid waste. Mr. Simmens will 6 testify that the construction of interconnections with 7 neighboring utilities does not present a possibility of 3 reducing reserve margins and thus obviating the need for the 9 Allens Creek project.

10 Q. Please describe the Company's current demand and

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11 capacity forecast.

12 A. The Allens Creek Environmental Report Supplement 13 filed in May, 1978, contains a thorough description of 14 HL&P's method of forecasting demand. Figure S.l.1-3 in the 15 Supplement shows the actual car, bility and peak demand data 16 fr m 1963 through 1976 and forecasted data for 1977 through 3_i 1987. I have attached hereto as Applicant Exhibit No.

( G- ), a a e showing t.he actual peak demand for 1977 13 g

through 1980 and the forecasted peak demand for 1981 through l , 1991, and the reserve margins in each year.

t 40 Q. Has the Company changed its scheduled generation additions shown at page SH-100 of the ER Supplement?

A. Our planned generation additions are developed on a continuing basis. The schedule shown at page SH-lCO has I 1

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changed several times since publication of the ER Supplement.

2 The most current schedule is shown on Applicant Exhibit No.

3 (JDG-2) which lists the new plants presently being 4 planned or under construction, the estimated unit capability, 5 the fuel type and the scheduled in-service date of each s plant.

7 Q. Does this construction program provide HL&P with a sufficient capability to maintain adequate reserves through  ;

9 1988?

10 A. No. HL&P has had to enter into contracts to purchase ca.pacity from neighboring utilities in order to 33 meet its reserve requirements. These agreements include:

3 (1) a contract between HIE 2 and the City of Austin to pur-chase 500 megawatts of capacity in 1980 and 800 megawatts from 1981 through 1987; and (2) a contract between HL&P and

.o the' City Public Service Board of San Antonio to purchase

, o, from 200 megawatts to 500 megawatts between 1982 and 1987.

,7 Exhibit JDG-1 shows the effect of these purchases on RTAP's reserves. A summary of the purchased power presently under contract is shown in Applicant Exhibit No. (JDG-3).

20 Q. What is the current schedule for Allens Creek?

21 A. Allens Creek is now scheduled to be in commercial 22

' operation in 1988, but after the peak of that year. That is 23 why' I have shown it coming on line in 1989 in Applicant 24 Exhibit No. _ (JDG-2). ,

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  • 1 Q. What is the impact on reserve margins if Allens 2 Creek is delayed?

3 A. If we are unable to bring the Allens Creek project 4 or. line in 1989, our reserve margin would drop to 9.3 per-5 cent. The reserve margin would be 10.7 percent in 1990 if 6 Allens Creek is not in operation by then.

l 7 Q. Is it possible to cover this shortfall in reserves a through additional capacity purchases?

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! 9 A. While we have been able to cover some of our short 10 fall in reserves through purchases from other companies, the n reserve margins shown in Exhibit JDG-1 are dependent upon l Allens Creek coming on line before the peak season in 1989.

g It is possible that we can continue to make up for some of 13 g the shortage in reserves through capacity purchases if

,_ Allens Creek is delayed to 1990 or beyond. However, 1990 s

may be an extremely Critical year, because most of the excess capacity which we have been able to purchase is either oil or gas-fired capacity that is being displaced by cheaper base load coal units. Much of r.his excess capacity may not ce available for sale due to either the unavailabil-ity of fuel and/or the legal prohibitions on its use.

Secondly, by 1990, projected load growth in the systems 22 supplying the capacity will have eroded the excess capacity 23 to the extent that these systems are no longer willing to l

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1 make commitments of firm capacity sales. For instance, as ' '

shown in the July, 1980, National Electric Reliability 2

3 Council report, the installed reserve margin of ERCOT is 4 expected to fall from 46 percent in 1979 to 19 percent in 5 1990.

6 Q. Is there a cost penalty associated with delaying Allens Creek in reliance upon capacity peichases from other 8 electric utilities?

A. Yes. There is a tremendo.ts penalty both in terms 9

of escalation and replacement fuel costs. The plant costs 10 l 11 will escalate by about $100,000,000 each year that it is 12 delayed and the differential fuel costs would average at least $500,000,000 each year, based on present cost estimates 13 of replacement fuels. So, if Allens Creek were delayed only 34 ne year to 1990, there would be a cost penalty of about 5

$600,000,000. I reiterate that by 1990, the excess gas and l , o, oil capacity previously available for purchase will largely disappear so we cannot continue to defer Allens Creek in 3

g reliance upon such excess capacity.

, Q. Would you please explain why HL&P cannot construct l

new generating capacity to be fueled by natural gas or fuel l

! oll?

22 A. In 1978, Congress passed the Powerplant and In-23 dustrial Fuel Use Act, 42 U.S.C. $8301 et seg. This Act 24 l  !

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.t. s 1 yrohibits HL&P from constructing new power plants that use 2 either petroleum or narural gas as a p _ mary energy source.

3 The Act also provides that natural gas will not be used as a 4 primary energy source in any existing power plant after 1

1 5 January 1, 1990.

l l 5 Q. Are you familiar with the exemptions permitted 7 under the Act?

3 A. Yes, I am very familiar with them. In fact, I 9 first became involved with this legislation when it was 10 proposed in the Spring of 1977. At that time HL&P began an 11 intensive effort to review and comment on the proposed 12 legislation. Subsequent to the passage of the Act I wts 13 involved in our review of and commenting on the DOE regula-l 14 tions implementing the Act. Most importantly, it has been 15 my continuing responsibility to evaluate the Act as it 16 affects HL&P's corporate planning.

17 Q. W uld you please explain the exemptions available g

under the Fuel Use Act and what their impact is on EL&P?

g A. There are a number of exemptions available under e c c may a , under certain showings on the part 20 of HL&P, either construction of new oil or gas-fired facil-ities or continued use of natural gas in existing facilities 22 past January 1, 1990. I have reviewed those exemptions for construction of new facilities and have concluded that thers 24 l

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AI .L 1 is no certainty that HL&P could meet the requirements for

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2 any exemption except the peak load exemption. However, this 3 exemption would allow only 1500 hours0.0174 days <br />0.417 hours <br />0.00248 weeks <br />5.7075e-4 months <br /> of use of the exempted 4 facilities and would hardly provide sufficient energy to 5 replace that expected to be available from Allens Creek.

6 Of the exemptions available under the Act for extended 7 use of natural gas in existing facilities, the only two for a which E&P may be able to qualify are the retirement and 9 synthetic fuel exemptions. The retirement exemption may 10 allow an additional five years of natural gas use provided 11 that E&P pledges to retire the exempted capacity at the. end 12 f the five year period. The synthetic fuel exemption may 13 all W up to ten years of natural gas use if E&P can make y the necessary showing that synthetic gas will be available and used at the end of the exemption period. E&P's current 3

la, plans anticipate the use of both these exemptions in order to realize the maximum economic utilization of its existing g

g gas-fired generating capability.

Q. Would the utilization of these exemptions affect g

the need for Allens Creek?

A. No, because the contemplated exemptions only pro-vide for extended use of existing facilities, the expected growth in system demand must be supplied by additional new capacity. The new capacity will consist of coal, lignite, 24

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l and nuclear units, including Allens Creek, which is an '{'

2 important and integral part of HL&P's planned generation -

3 mix.

4 Q. Please explain why there is no reasonable prob-5 ability that HL&P could get a permanent exemption to con-6 struct a new base load, gas-fired plant.

A. In order to qualify for such an exemption, EL&P 3

must show, in effect, that it cannot construct new coal, 9 lignite, or nuclear plants. Since we are planni.ng for and 10 constructing all three of these types of plants it would i

1; seem impossible to make the showing required for the perma-12 nent exemption for a new base load, gas-fired plant.

Q. What about the provision that indicates that there 13 l

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, may be an exemption to avoid violation of environmental 12

_ recuirements such as the Clean Air Act?

,, A. Obviously, we are planning and constructing new

_o coal and lignite plants both inside and outside our service

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area. As long as we have the capability to find sites where 13 we can construct new coal or lignite plants in compliance with the Clean Air Act, we simply cannot qualify for this exemption.

Q. In the FES Supplement the NRC Staff cites a study

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bv the Federal Power Commission which indicates that the t n I ,

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1 rate of development of natural gas supplies will be inadeO '

2 quate to meet current projections of demand. In its order 3 of November 13, 1980, the Board asked whether th,ere was more 4 recent information than that provided in the FES Supplement 5 on cost and availability of natural gas. Can you address 5 the Board's question?

7 A. With respect to the question of costs, I defer to g Dr. Perl. On the question of availability, I am not aware 9 of any studies which would serve as a basis to reverse the 10 conclusion drawn by the NRC Staff in Section S.9.1.2.1 of 11 the Final Supplenent to the Final Environment Statement 12 (FSFES).

13 Q. Are you aware of any studies which provide more j recent support for the conclusions in the FSFES?

14 15 A. In May, 1979, the Department of Energy published a g study known as National Energy Plan II, which is a compre-hensive study of U.S. energy problems. This study was 3

g prepared by DOE in accordance with Section 801 of the Depart-ment of Energy Organization Act. In NEP II, the DOE g

addresses the future supply and demand for natural gas and l

concludes that there is extreme uncectainty as to whether natural gas supply can satisfy U.S. demand through the year 2000. This prediction includes all sources of supply -

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1 conventional and unconventional, domestic and imported.

2 Another comprehensive study was published by the National 3 Research Council in 1979. The title of this study is " Energy 4 in Transition 1985-2010." This study was prepared for the 5 Department of Energy under a contract initially entered into 6 by the Energy Research and Development Administration. The 7 Council's report contains a number of scenarios for natural 3 gas production through 2010. Under even the most optimistic 9 scenario they expect continued declines in both oil and gas 10 production through 2010. The report states that "the likeli-11 hood of reversing the slow decline in domestic oil and natural gas production is quite small, and the prospect of 12 compensating for this decline by continued growth of oil 13 imports is equally small, at least beyond a few years in the 34

,_ future." Finally, in a report prepared by the Department of 2

Energy in November, 1980, titled " Reducing U.S. Oil Vulner-6 ability, Energy Policy for the 1980's," the Department g

concluded that it is " highly unlikely that the production of g

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[ natural] gas can increase or even be held constant over the next 20 years."

Q. The November 13 order also raises a question as to 21 .

the environmental comparison between natural gas plants and nuclear plants. Has HL&P done any such comparison?

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1 A. We have not done a specific comparison; however', I 2 mn sure that natural gas plents would compare very favorably 3 to nuclear plants. Gas fired plants are clearly preferable 4 to coal and lignite because the sulfur and ash discharges l 5 are negligible. Likewise, there is a very minimal impact l

6 .scociated with the fuel cycle for gas plants. However, any 7 environmental comparison is meaningless because we cannot 3

build new Jas fired plants. The gas fired plant is just not 9 an option for us.

Q. Exhibit JDG-2 shows that HL&P is planning and 10 constructing nuclear, coal, and lignite plants. As Manager 11 f Corporate Planning, is it your view that the Company 12 should construct all three types of plants?

13 A. Yes, it is.

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,_ Q. From your perspective as a corporate plarner why is it desirable to have a diversity of generating plants on 6

3 the HL&T system?

i A. There are numerous reasons, but it basically comes

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I down to the fact that it is highly desirable to have a diversity of fuel supply. The point is illustrated b 2 our I experience. Up until the 1970's, we were totally dependent 21 upon natural gas for our fuel supply. As a result of short-ages of natural gas that developed in the early 1970's and the resultant legislative and regulatory prohibitions on the 24

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1 had been planned. The only short term remedy was to install 2 fuel oil capability in our generating plants. The price of -

3 fuel oil has, of course, skyrocketed in the past few years 4 and the Federal government has passed laws and regulations 5 designed to discourage further dependence on imported oil.

6 For the longer range, we also undertook an ambitious nuclear 7 program. Like all other companies in ttt United States, we S began experiencing substantial delays in our nuclear plants, 9 which caused us to focus on coal plants as an alternative.

10 We found that we could undertake construction and operation 11 of coal plants on a shorter schedule than nuclear plants.

12 This wa: a important consideration because of the tremen-13 dous load growth on E&P's system and because of our in-

,4 ability to construct new gas-fired generating facilities.

,_ We are now turning our attention to lignite plants because 3

g the fuel supply is relatively closer to E&P's service area and the cost projections for lignite fuel supply are much more stable than the Cost projections for Coal.

g Q. What is the benefit of a nuclear plant in terms of adding diversity to HL&P's system?

A. First, the cost of power produced by a nuclear plant is competitive with power produced by a coal or lignite plant. Furthermore, a nuclear plant is not as vulnerable as 24 i

l I a coal plant to escalations in fuel costs. The fuel cosis

2 associated with operation of a nuclear plant amount to about 3 27 percent of the total electricity cost whereas the fuel 4 costs of a coal plant amount to about 65 percent of the 5 total electricity costs. Thus, escalations in fuel cost 6 have less effect on total cost of power from a nuclear 7 plant. Furthermore, the cost of western coal at the mine is a usually subject to considerable escalation and there is a g considerable risk of escalation in the cost of transporting 10 coal. Indeed, the cost of transporting coal from the West 11 (Wyoming and Montana) is much greater than the purchase

. 12 price of the coal itself. For example, for the first nine I .

l 13 months of 1980, the average price paid by HL&P for coal was 510.60/ ton, while the rail tariff averaged $18.83/ ton.

74 These transportation costs reflect rates as they were prior 3-t deregulation. The transportation costs following deregula-l 6 tion are likely to be an even greater portion of the total.

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We hope to get some protection from these transportation costs by building mine-mouth lignite plants in Texas.

g However, there is a limited supply of economically recoverable O

lignite deposits for which leases have been sufficiently consolidated to support all of the new power plants which l must be built in Texas in the next few years to supply the 23 expected increases in electric demand.

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1 Q. Does that complete your testimony? '

2 A. Yes.

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b DiennnA AAA4b4nne 11001_100n1 Generation Additions, System Capability, Load, Purchase Power, and Reserve

\ 1977-1990 Reserves Without With Purchase Purchase Peak (1) Installed (2) Purchase Power Power Year Demand (MW) Capability (MW) Power (MW) (;MW) (%) (MW) (%)

1977 8445* 10170 0 1725 20.4 1725 20.4 1978 9114* 10828 0 1714 18.8 1714 18.8 1979 9336* 11193 0 1857 19.9 1857 19.9 1980 10266* 11763 500 1497 14.6 1997 19.5 1981 10700 11763 800 1063 9.9 1997 19.5 1982 11375 11763 1300 388 3.4 1688 14.8 1983 11700 12303 1200 603 5.2 1803 15.4 11975 12688 1000 713 6.0 1713 14.3 1984' 12625 13160 1300 535 4.2 1835 14.5 1985 1986 13050 14245 1000 1195 9.2 2195 16.8 14845 1200 1270 9.4 2470 18.2 1987 13575 14150 15445 0 1295 9.2 1295 9.2 1988 1989' 14675 17175 0 2500 17.0 2500 17.0 15050 17787 0 2737 18.2 2737 18.2 1990 15750 18387 0 2637 16.7 2637 16.7 1991 (1) Does not include interruptible demand.

(2) Does not include purchase power.

  • Antual naak demand.

Generation Additions, System Capability, Load, Purchase Power, an<l Reserve 1977-1990 Reserves Without With

, Purchase Purchase 4' Peak (1) Installed (2) Purchase Power Power Year ' Demand (MW) Capability (MW) Power (MW) (.MW) (%) (MW) (%)

1977 8445* 10170 0 1725 20.4 1725 20.4 1978 9114* 10828 0 1714 18.8 1714 18.8 1979 9336* 11193 0 1857 19.9 1857 19.9 1980 10266* 11763 500 1497 14.6 1997 19.5 1981 10700 11763 800 1063 9.9 1997 19.5 1982 11375 11763 1300 388 3.4 1688. 14.8 1983 11700 12303 1200 603 5.2 1803 15.4 1984 11975 12688 1000 713 6.0 1713 14.3 1985 12625 13160 1300 535 4.2 1835 14.5 1986 13050 14245 1000 1195 9.2 2195 16.8 1987 13575 14845 1200 1270 9.4 2470 18.2 1988 14150 15445 0 1295 9.2 1295 9.2 1989 14675 17175 0 2500 17.0 2500 17.0 1990 15050 17787 0 2737 18.2 2737' 18.2 1991 15750 18387 0 2637 16.7 2637 16.7 (1) Does not include interruptible damand.

(2) Does not include purchase power.

  • Actual peak demand.

Applicant Exhibit No. (JDG-1)

Plannad Additions (1981-1990)

Estimated Fuel Scheduled In-Unit Name Capability (MW) Type S.ervice Date

'W. A. Parish 8 540 Coal 1983 South Texas Project 1 385 Nuclear 1984 Limestone 1 700 Lignite 1985 South Texas Project 2 385 Nuclear 1986 Limestone 2 700 Lignite 1986

, XLN 1 600 Lignite 1987 i

XLN 2 600 Lignite 1988 XLN 3 600 Lignite 1989 Allens Creek 1130 Nuclear 1989 i Undefined 1 700 Lignite 1990 Undefined 2 600 Lignite 1991 Applicant Exhibit No. (JDG-2 )

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Purchase Power Contracts, 1981-1990 e a (MW) ,"

City of CPSB of Year Austin San Antonio Tctal 1981 800 0 800 1982 800 500 1300 1983 800 400 1200 1984 800 200 1000 1985 800 500 1300 1986 800 200 1000 1987 800 400 1200 1988~ 0 0 0 1989 0 0 0 1990 0 0 0 4

l P.D icant Exhibit no (JDG-3) t

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