ML20147B450
| ML20147B450 | |
| Person / Time | |
|---|---|
| Site: | Allens Creek File:Houston Lighting and Power Company icon.png |
| Issue date: | 12/08/1978 |
| From: | Haines F ENERGY, DEPT. OF |
| To: | Knighton G Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 7812150293 | |
| Download: ML20147B450 (25) | |
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Department of Energy Washington, D.C. 20461 DECEMBER 8, 1978 Mr. George W. Knighton, Chief Environmental Projects Branch 1 Division of Site Safety and l Environmental Analysis U.S. Nuclear Regulatory Commission Washington, D. C. 20555
Dear Mr. Knighton:
This is the Economic Regulatory Administration's (ERA) response to your letter of February 24, 1978, to Mr. William Lindsay of the Federal Energy Regulatory Commission, requesting comments on the Nuclear Regula- ,,
tory Commission's (NRC) Draft Supplement to the Final Environmental Statement (FES) related to the proposed issuance of a construction permit to the Houston Lighting and Power Company (HLP) (Applicant) for the -
construction of the Allens Creek Nuclear Generating Unit No. 1 (Docket No. 50-466).
Mr. Lindsay has requested that the staff of the Economic Regulatory Administration (ERA) provide comments on the need-for-power section of the Draft Supplement. Consequently, these comments are forwarded on ,
behalf of the Department of Energy's Assistant Administrator for Utility Systems, ERA. The analysis was developed by the staff of the Power ,
Supply Planning Branch, Division of Power Supply and Reliability, Office of Utility Systems. Our comments are in compliance with the requirements of the National Environmental Policy Act of 1969, and the August 1, 1973 Guidelines of the Council on Environmental Quality; they are directed to the need for capacity represented by the Allens Creek project, and to related bulk power supply matters concerning system reliability.
In addition, because of DOE's national r ,onsibilities to effect an absolute, overall reduction in the use c. natural gas and oil to generate .
electricity, the fuel consumption implications of the HLP generating system have also been calculated. All future comments from the DOE regarding a test of need for power for all Environmental Impact Statements will include .-
a forecast and evaluation regarding the effectiveness with which the applicant is reducing its oil and gas dependence.
D h 931215065(3 s\
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i As NRC indicated in the Draft Supplement to the FES, the Allens Creek l Nuclear Generating Station Unit No. I will provide a net electrical I
output capacity of 1146 MW. Please note, however, that our analysis throughout reflects only a 1130 MW net output capacity for Allens Creek No. 1, as was reported by HLP through the Electric Reliability Council of Texas (ERCOT).
The Draf t Supplement shows a projected in-service date of March,1985 for Allens Creek No. 1. The site of the proposed generating station is located in the southern part of Austin County, Texas, immediately west of the Brazos River and about 45 miles west of the center of Houston. The station is to be wholly owned by the HLP.
In preparing our comments, we have considered not only the analysis and data in the FES, but also the Applicant's Environmental Report and its supplements, and those related reports made in accordance with the Federal Energy Regulatory Commission (FERC) Statement of Reliability and Adequacy of Electric Service (Docket No. R-632, Order 383-4), FERC's staff analysis of these documents and other related FERC information.
As a first analytical approach, the applicant's need for bulk power was evaluated relative to long term-energy considerations and to such other considerations as projected peak demand, scheduled capacity additions, projected reserves, and projected annual generation, for the period 1984 through 1987.
We have further enlarged our analysis by using individual unit generation and system performance data for the HLP service area, to compute a series of system simulations relating to: production cost savings through operation of Allen's Creek, system fuel consumption with or without this capacity addition, and system reliability.
These separate analyses are presented in depth, as Part I and Part II of the accompanying report.
Briefly summarized, the conclusions reached in the course of our study are as follows:
- 1. The capacity additions scheduled for the HLP system, including the Allens Creek Nuclear Generating Station Unit 1, appear minimal in view of projected customer requirement, if reliable service is to be supplied.
- 2. The installation of Allens Creek No. I would significantly reduce the HLP system dependence on oil and on natural gas.
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- 3. In addition to examining HLP data, we have reviewed the long-range planning program submitted to the DOE on April 1, 1978 by ERCOT, of which HLP is a menber, and we find that the new generating capacity planned by HLP would be of benefit to the Reliability Council in terms of regional power system reliability.
Our analysis indicates a clear need for the Allens Creek station. The details of the study are enclosed. Should you have any questions regarding the analysis, or the supporting data, we would be pleased to furnish our background information.
Sincerely, eq '
hb$
an D. a e Chief, Power Supply Planning Branch Economic Regulatory Administration
Enclosure:
as stated b
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Part I Bulk Power Load and Capacity Analysis Allens Creek Nuclear Generating Unit No. 1 1985-1987
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Part I - BULK POWER LOAD AND CAPACITY ANALYSIS 6
This section summarizes th9 studies of the peak demand and generating capacity projected for the HLP system. The period covered in the analysis extends from the present through 1987; only summer peak demand and capacity reserves are considered in the analysis.
Table 1 presents the 1978-1967 annual increases in summer peak demand projected by ERCOT, by HLP, and by the balance of the ERCOT systems after the HLP loads have been deducted. The table shows that the projected growth rate of HLP summer peak demand is less that of ERCOT as a whole, and also less than that of all other ERCOT systems combined. Further, the average ten-year growth rate of HLP (4.87% annually) is less than the national average annual increase (5.18%) projected by the nine Regional Electric Reliability Councils in their April 1, 1978 reports to the Department of Energy. The HLP growth rate projected is believed to be reasonable, and possibly conservative.
2 TABLE 1 ERCOT and HLP Projected Annual Summer Peak Demands 1978-1987 1! HLP
! ERCOT MINUS HLP Year ERCOT MW Growth MU Growth MW Growth (Percent) (Percent) (Percent) 1978 28,949 9,175 19,774 1979 30,561 5.57 9,675 5.45 20,886 5.62 1980 32,341 5.82 10,325 6.72 22,016 5.41 1981 34,152 5.60 10,775 4.36 23,377 6.18 1982 36,024 5.48 11,300 4.87 24,724 5.76 1983 38,034 5.58 11,800 4.42 26,234 6.11 1984 39,804 4.65 12,275 4.03 27,529 4.94 1985 41,930 5.34 12,925 5.30 29,005 5.36 1986 44,074 5.11 13,500 4.45 0,574 5.41 1987 46,389 5.25 14,075 4.26 32,314 5.69 Average -
5.38 -
4.87 -
5.61 1/ Electric Reliability Council of Texas. Summer peak load as projected in Item 3A of its April 1, 1978 report to U.S. Dept. of Energy.
2/ Houston Lighting & Power Co., a member of ERCOT. s, ,,
Summer peak load as projected in HLP report on 'a FPC Form 12E-2, as of March 31, 1978.
3 The projected increases in HLP generating capacity from 1978 thru 1987, and the total sydtem capacity, are shown in Table 2.
TABLE 2 Houston Lighting & Power Company Projected Generating Capacity Additions 1976-1967 Generating Capability As of December 31, 1977 = 10170 MW Projected Additions 1/ Total-System Capability Unit Capacity W Date (MW)
W. A. Parrish No. 5 660 Mar. 1978 10,830 W. A. Parrish No. 6 660 Mar. 1979 11,490 W. A Parrish No. 7 570 Jun. 1980 12,060 STN /No. 1 385 Oct. 1980 12,445 STN / No. 2 385 Mar. 1982 12,830 Allens Cregk No. 1 1,130 Mar. 1985 13,960 3
Coal Unit _/ 750 Mar. 1986 14,710 1987 14,710 1/ From Electric Reliability Council of Texas (ERCOT) report to U.S. Dept. of Energ) on Coordinated Bulk Power Supply Programs, April 1, 1978, Item 2-B; Houston Lighting and Power Co., Form 12E-2 Report as of March 31, 1978, Schedule 3; public announcement by HLP on May 30, 1978.
2/ South Texas Nuclear Project Shared by Houston Lighting 6 Power Co., San Antonio Public Service Board, Central Power
& Light Co., City of Austin Electric Utilities. The capacity shown is Houston's share.
3/ Unit planned but not authorized. Location not stated.
The generating capacity reserves of HLP arc shown in Table 3, computed from the data of Tables 1 and 2. From 1982 on, the HLP reserves are significantly less than the 15% usually considered the minimum desirable for systems whose generating capacity is all thermally-based. It is evident, of course, that construction of
4 the Allens Creek plant can have no effect on the 1982-84 reserve a margins, but even with the Allens Creek capacity the HLP reserves for 1985 and later will be smaller than those needed for reliable service.
TABLE 3 Houston Lighting & Power Company Summer Generating Reserves 1978-1987 (Including all Generating Units Projected as April 1, 1978 updated to August 1, 1978.)1/of Year Capability Peak Load Reserves (MW) (MW) (MW) (Percent) 1977 10,170 8,645 1,525 17.64 1978 10,830 9,175 1,655 18.04 1979 11,490 9,675 1,815 18.76 1980 12,060 10,325 1,735 16.80 1981 12,445 10,775 1,670 15.50 1982 12,830 11,300 1,530 13.54 1983 12,830 11,800 1,030 8.73 1984 12,830 12,275 555 4.52 1985 13,960 12,925 1,035 8.01 1986 14,710 13,500 1,210 8.96 1987 14,710 14,075 635 4.51 1/ 1977 data actual, as reported on Form 12E-2 for July 1977. Data for 1978-1987 are projected: Peak loads from Form 12E-2 for March 1978, Schedule 5; capability based on generating unit installation as projected in ERCOT Planning Report dated April 1, 1978, Item 2-B and HLP report on Form 12E-2, March 1978, Schedule 3 (with subsequent adjustment in July, 1978, to reflect the May 30, 1978 announcement by HLP of cancellation of the Freestone project).
Table 4 shows the effect on HLP reserves if the Allens Creek capacity is not available as scheduled. In 1985, 1986 and 1987 the reserve margins at the time of summer peak demand, on the basis of current load projections, would be far less than the amount considered necessary for reliable service.
5 TABLE 4 Houston Lighting & Power Company Summer Generating Capacity Reserves 1984-1987
.(Without Allens Creek Nuclear Unit No. 1)
Year Capability Peak Load Reserves (MW) (MW)_ (MW) (Percent) 1984 12,830 12,275 555 4.52 1985 12,830 12,925 (95)17 1986 13,580 13,500 (80) 0.59 1987 13,580 14,075 (495) --
1/ The figure in parenthesis is the amount by which load exceeds capability. Percent reserve is meaningless.
The Houston Lighting and Power Company is intercor.nected with several other systems in Texas; among them are The Lower Colorado River Authority, Texas Power & Light Co., Central Power & Light Co.
The Draft Supplement to the Final Environmental Impact Statement does not discuss the possibility of capacity purchases as an alterna-tive to construction of the Allens Creek unit. Under the heading
" Power Sales and Purchases" (para. S. 8.3.2) the Draft Supplement l
) merely states that the HLP has no commitments for firm interchanges l
or purchases, and has not planned any such activity. We consider it advisable that HLP and the utilities to which it is or could be interconnected review the reliability and cost-related advantages of coordinated and interconnected operation. However, we do not consider that even a high degree of interconnected coordination would be a substitute for all of the 1130 MW that would be provided by the Allens Creek plant. Table 5 shows that the regional ERCOT reserves are projected to decline steadily from 1984 thru 1987. The 1987 margin of 17.81% would be reasonable for a system of ERCOT's size if
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it were strongly interconnected internally and operated as a i
single s y s ,t em , with some interconnections to other regional council areas. Because ERCOT is an electrically isolated region, ERCOT's regional reserves, -i f Allens Creek should not be constructed, would drop to a marginally adequate level in 1987, as shown in Table 6.
TABLE 5 Electric Reliability Council of Texas Summer Generating Capacity Reserves 1984-1987 (Including all Generating Units Projected as of April 1, 1978)
Year Capability Peak Load Reserves (MW) (MW) (MW) (Percent) 1984 50,550 39,804 10,746 27.00 1985 51,780 41,930 9,850 23.49 1986 53,168 44,074 9,094 20.63 1987 54,650 46,389 8,261 17.81 TABLE 6 Electric Reliability Council of Texas Summer Generating Capacity Reserves 1984-1987 (Without Allens Creek Nuclear Unit No. 1)
Year Capability Peak Load Reserves (MW) (MW) (MW) (Percent) 1984 50,550 39,804 10,746 27.00 1985 50,650 41,930 8,720 20.80 1986 52,038 44,074 7,964 18.07 1987 53,520 46.389 7,131 15.37 j With respect to the need to produ e electric energy, HLP appears to be justified in planning the construction of a base load generating unit with the 1130 MW capability projected for Allens Creek. If all construction is completed as projected, the average annual system capacity factors for the years 1978 thru 1987 would be as shown in
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Table 7. Since the capability shown in the table includes peaking i
units, which,are expected to operate at low capacity factors, the base load units would operate at actual capacity factors greater than the .557 .591 shown. That i s ., the HLP system would not appear to have any significant amount of excess capacity, from the stand-point of annual energy requirements, following the completion of the Allens Creek unit.
TABLE 7 Houston Lighting & Power Company Projected Annual Generation and Capacity Factor 19ib-196i y
Average System Year Annual Energy Average Capability j Capacity Factor MWH MW 1978 51,218,035 10,500 .557 1979 54,411,877 11,160 .557 1980 58,574,336 11,968 .557
'981 61,245,651 12,445 .562 1982 64,401,421 12,638 .582 1983 67,136,335 12,630 .597 1984 69,644,071 12,830 .609 1985 73,185,373 13,395 .624 1986 76,477,999 14,335 .609 1987 79,779,373 14,710 .619 1_/ Average of capability at beginning and end of calendar year, including all projected units.
If the Allens Creek capacity is not available, the average system annual capacity factors for 1985-1987 would be as shown in Table 8. While individual unit annual capacity factors of the magnitude shown in Table 8 are not unusual, continued operation of an entire system at those values, for a period of 3 years or more,
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wculd not be customary. System operation at high capacity ,.
6 factors for letg periods reduces operating flexibility (and -
thereby may increase operating costs) and also reduces the time available for thorough maintenance programs. Inadequate maintenance is a major cause of reduced generating unit reliability.
TABLE 8 Houston Lighting & Power Company '
Proiected Annual Generation and Capacity Factor Excludine Allens Creek Nuclear Unit No. 1 ,-
1985-1987 Year Annual Energy Average Capability Average System *
(MWH) (MW) Capacity Factor O
1985 73,185,373 12,830 .651 1986 76,477,999 13,205 .661 '
1987 79,779,373 14,075 .647 ,,
It is also pertinent to remark upon the use of the Allens Creek nuclear plant as a means of reducing the c,onsumption of . -
j oil and natural gas. If it is assumed that the unit will perform at the average level of nuclear plants during their first few years of operation (see Table 9), the possible savings of fossil ,-
fuel would be as shown in Table 10 for the period April 1, 1985 , ,
thru December 31, 1987. i' h e savings would increase thereafter, as the capacity factor of Allens Creek increased.
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9 TABLE 9 Average Capacity factor of Nuclear Units First 2 years of Operation 0.47 Capacity Factor 3rd year of Operation 0.53 Capacity Factor 4th year of Operation 0.55 Capacity Factor 5th year and later 0.62 Capacity Factor (Source: Federal Power Commission News Release No. 23030, dsted March 28, 1977)
TABLE 10 Potential Savings in Fossil Fuel Consumption by Operation of Allens Creek Nuclear Unit No. 1 Year Annual Generation at Alternative Generation Requirements Allens Creek Nuclear Oil or Natural Gas Unit No. 1 (MWH) (Barrels) (Million Cu. Ft.)
1985 3,489,000 6,140,000 33,050 1986 4,652,000 8,190,000 44,070 1987 5,098,000 8,980,000 48,300
SUMMARY
In view of all the factors discussed above, The Economic Regulatory Administration considers that the 1130 megawatts of generating capacity represented by the proposed Allens Creek nuclear plant would contribute significantly to the reliability of the HLP system. In addition, the reduction in fossil fuel consumption through the use of nuclear fuel should be considered as an important factor.
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Part II Production Cost, Fuel Consumption, and Reliability Analysis Allens Creek Nuclear Generating Unit No. 1 1985-1987
Part II s Production Cost, Fuel Consumption, and Reliability Analysis i
This section contains a summary of the Economic Regulatory Administration findings on the potential impact of the Allens Creek Nuclear Generating Unit #1 on HLP system reliability, on the utility's pattern of fossil fuel consumption, and on system production costs.
The first portion of the analysia is focussed on the effects of potential schedule slippages in Allens Creek #1 construction, as shown below:
Case Scenario A Allens Creek #1 enters service in March 1985 (as currently scheduled by HLP)
B Allens Creek #1 enters service in March 1986 C Allens Creek #1 enters service in March 1987 D Allens Creek #1 cancelled The analytical technique used in this scenario analysis is the PROMOD II production costing computer program. All input data defining the HLP generating system were provided by HLP directly to the ERA staff. These statistical data appear in the appendices following.
It may be noted that in May, 19/8 HLP announced the cancella-J tion of plans to construct a two-unit lignite-fired plant (Freestone 1 and 2) which had been previously scheduled for 1983 and 1984 operation, as a joint venture project with an industrial partner.
Therefore, the capacity analyses appearing in this section do not
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include the 694 MW of capacity, represented by the Freestone units, 4
incorporated into earlier studies.
TABLE 1 Houston Lighting and Pewer Company Reliability Assessment: Loss-of-Load Hours 1965-1967 Loss-of-Load Case Scenarios 1985 1986 1987 (number of hours) (number of hours) (number of hours)
A Allens Creek #1 43.1 41.0 92.4 on line 3/85 B Allens Creek #1 156.8 41.0 96.9 on line 3/86 C Allens Creek #1 156.8 140.9 97.1 on line 3/87 D Allens Creek #1 156.8 140.9 277.8 cancelled Table 1 indicates that even with Allens Creek No. 1 in-service by March 1985, HLP would, on a probabilistic basis, have insufficient generat-ing capacity to meet projected system demands for a total of 43.1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> in 1985. Furthermore, without Allens Creek on line in 1985, the HLP system load could possibly exceed available generating capacity (including pre-arranged power transfers) for a total period of 156.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> -- the equivalent of 6.5 days -- during 1985. The analysis shows also that a one, two, or three-year delay in construction of Allens Creek #1 causes a three-fold increase in the annual, aggregated loss-of-load hours. (It should be noted that the
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reliability analyses presented here assume that the HLP system 4
can import up to 1,000 MW of capacity from surrounding ERCOT members under conditions of emergency.)
In addition to providing a critical link in maintaining the reliability of the HLP system, the installation of Allens Creek #1 would play a key role in reducing HLP dependence upon oil and gas.
As late as 1977, 100 percent of HLP generation was gas-fired.
HLP has advised us of a potentiai 75 percent reduction in the volume of contract natural gas available to the Company's system between now and 1985, but our analysis of the latest HLP generation expansion plans shows that approximately 80 percent of the utility's installed capacity would be dependent upon a gas fuel supply in 1985. Since a considerable percentage of this " gas-fired" capacity is also capable of burning some form of oil as an alternate fuel, it would be reasonable to expect an Ancrease in the amount of oil used on the HLP system after 1984, even with the installation of Allens Creek #1 by 1985.
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TABLE 2 Houston Lighting pnd Power Company Projected Annual System 011 Consumption 1985-1987 1985 1986 1987 Total Case (Thousands of Barrels)
A - Allens Creek #1 on line 3/85 63,982 59,403 63,992 187,377 B - Allens Creek #1 on line 3/86 74,603 63,640 64,241 202,484 C - Allens Creek #1 on line 3/87 74,603 73,509 67,803 215,915 D - Allens Creek #1 cancelled 74,603 73,509 78,221 226,333 This ERA analysis also indicates (as shown in Table 2) that a year's delay in completion of Allens Creek #1, from March 1985 to March 1986, could cause consumption of an additional 10.6 million barrels of oil by the HLP system during 1985, and of an additional 4.2 million barrels in 1986. A further delay in insta"lation --
to March 1987 -- would cause a cumulative increase of L'9.5 million barrels in HLP oil consumption for the 1985-1987 period.
Cancellation of the Allens Creek project would produce a cumulative increase in oil consumption of almost 40 million barrels from 1985 through 1987, on the HLP system, with a continuing impact of approximately 10 million barrels per year.
In toto, the installation of Allens Creek #1 would significantly affect the amount of oil consumed by the HLP system in the mid-eighties.
In addition to the favorable effects of Allens Creek #1 installation upon system reliability and oil consumption, already discussed, the addition of this unit would produce a significant reduction in HLP fuel costs. The utility has projected a price of
$0.45 per million BTU for the Allens Creek nuclear fuel, which is
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expected to be the lowest cost fuel option on the HLP system by I
the mid-eigh, ties.
TABLE 3 Houston Lighting and Power Company Projected System Production Costs 1985-1987 1985 1986 1987 Total Case (Millions of Constant 1978 Dollars)
A - Allens Creek #1 on line 3/85 1,358 1,396 1,466 4,220 B - Allens Creek #1 on line 3/86 1,482 1,418 1,468 4,368 C - Allens Creek #1 on line 3/87 1,482 1,535 1,492 4,509 D - Allens Creek #1 cancelled 1,482 1,535 1,602 4,619 As Table 3 indicates, the absence of Allens Creek #1 from the HLP system (because of either construction delay or cancellation) would increase system production expenses by approximately $130 million per year. This increase in fuel costs would be due entirely to a substitution of the next higher-priced fuels on the system (i.e. oil or gas-fired generation) to fill the Allens Creek
- 1 gap.
Summary
- 1. Because of the cancellation, last spring, by HLP for 694 MW of lignite capacity which had been due on line in 1983 and 1984, it is imperative that substitute generation capability for the increment of capacity represcnted by Allens Creek #1 be installed by March 1985, in order that the possibility of widespread power
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shortages in the Houston area in the post-1985 period may be avoided. Without the 1150 MW of Allens Creek #1 on line, it is
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unlikely that HLP would be capable of supplying all of its i
projected, peak demand for energy during the period from 1985 through 1987.
- 2. Additionally, the installation of Allens Creek #1 could reduce HLP oil consumption by approximately 10 million barrels per year. It would also serve to augment the supply l of energy on the HLP system in the light of a steadily decreas-ing availability of contract gas.
- 3. Finally, the net effect of the introduction of Allens Creek #1 in 1985 should be a significant reduction in fuel charges paid by HLP customers.
Conclusion The installation of Allens Creek #1 by 1985 is required for HLP maintenance of reliable electric service to customers, and to reduce the dependence of the HLP generating system on oil and natural gas.
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Part III Appendix Allens Creek Nuclear Generating Unit No. 1 1985-1987 l
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Appendix - Table 1 HOUSTON LIGHTING & POWER COMPANY PEAK DEMAND (MW) AND ENERGY (%3) FORECAST I 1978-1995 I
l - PEAK DEMAND ENERGY YEAR (MW) (ET x 1000) 1978 9,175 51,218 l
1979 9,675 54,412 1980 10,325 58,574 1981 10,775 61,246 1982 11,300 64,401 1983 11,800 67,136 1984 12,275 69,644 '
1985 12,925 73,185 1986 13,500 76,478 1987 14,075 79,779 1988 14,674 83,177 1989 15,300 86,720 1990 15,951 90,413 1991 16,631 94,264 1992 17,339 98,279 1993 18,077 102,465 1994 18,847 106,829 1995 19,650 111,380 NOTE: Peak demand and energy data from 1978 through 1987 was extracted from the FPC Form 12 submitted by Houston Lighting & Power Company on April 24, 1978. Projections from 1988 through 1995 were developed by applying a 4.3%
compound annual growth rate to the reported 1987 value.
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Appendix - Table 2 HOUSTON LIGHTINC & POWER COMPANY EXISTING CTNFRATING SYSTEM BASIC UNIT CHARACTERISTICS e
AV. H.R. HEAT PORCED INCREMENTAL AT PRIMARY RATE PIIED TAR.
DUTAGE MIN. CAP. FUEL PENAt.TY OEM OEM UNIT RATE CAPACITY (MW) HEAT RATES (BTJ/KWH)
MIN. MID. MAI. MIN. MID. MAR. (BTU /FWH) USFD FACTOR ($/WK) ($/MWM)
MAME NO. TYPE (%)
W.A. Parrish 1 ST 3.50 90 148 177 9.129 9.860 10.982 10.155 Cas 1.070 29.100 .27 2 ST 3.50 90 148 177 9.129 9.860 10.982 10.155 Cas 1.070 29.100 .27 3 ST 3.50 150 235 278 8.625 11.658 14.907 10.370 Cae 1.050 45.700 2>
4 ST 4.77 360 497 565 8.650 10.599 12.351 9.850 Coe 1.060 92.800 .22 5 ST 12.00 335 539 660 R.640 9.435 10.742 10.070 Coat 1.080 103.400 .22 CTI CT 19.00 13 - 14 11.3R0 13.467 14.749 10.420 Can 1.600 2.300 .15 Cedar Sayou i ST 4.77 400 633 7'O 9.357 9.750 10.290 9.862 Can 1.010 34.200 .22 2 ST 4.77 400 633 750 9.357 9.750 10.290 9.862 Cae 1.010 34.200 .22 3 ST 4.77 400 633 750 9.357 9.750 10,290 9.R62 Gas 1.010 34,200 .22 P.M. Robinson 1 ST 4.77 270 384 441 R.990 10.ORI 11.076 9.530 can 1.040 72.400 .22 2 ST 4.77 270 384 441 9.243 9.995 10.718 9.770 Cao 1.030 72.400 .22 3 ST 4.77 360 497 565 9.057 10.113 12.114 9 RRO Can 1.040 92.800 .22 4 ST 4.77 400 5" 750 9.357 9.750 10.290 9.862 Caa 1.030 123.200 .22 CTI CT 19.00 13 14 11,3R0 13.467 14.749 10.420 can 1.600 2.300 .15 Creens Bayou 1 ST 3.50 20 , 72 12.502 10.163 14.061 20.699 Can 1.100 11.800 .27 2 ST 3.50 20 55 72 12.502 10.163 14.061 20.699 Can 1.100 11.800 .27 3 ST 3.50 60 95 112 9.707 10.777 12.305 11.250 Caa 1.100 18.400 .27 4 ST 3.50 60 95 112 11.006 11.220 11.526 11.315 Cn= 1.ORO 18.400 .27 5 ST 4.77 200 342 413 8.760 11.906 15.838 10.840 Cam 1.040 67.800 .22 73 & 74 CT 19.00 48 96 120 10.067 8.556 11.200 14.600 Cao 1.170 19.700 .15 81 & 82 CT 19.00 48 96 120 10.067 8.556 11.200 14,600 Cas 1.170 19,700 .15 83 & R4 CT 19.00 48 96 120 10.067 8.556 11.200 14.600 Cam 1.170 19.700 .15 ST 3.50 40 61 71 2.642 13.373 26.298 13.258 Can 1,900 11.700 .27 T.R. Wharton 1 2 ST 3.50 130 199 234 9.037 11.007 13.138 10.415 Can 1.040 38.400 .22
- 3. 31. 32. 33, 34 CC 19.00 90 211 271 8.R64 9.321 10.769 9.600 Cae 1.020 44.500 .22
- 4. 41. 42, 43, 44 CC 19.00 90 211 271 8.864 9.321 10.769 9.600 can 1.020 44.500 .22 51 & 52 CT 19.00 48 96 120 10.067 8,556 11.200 14.600 Cam 1.200 19.700 .15 53 & 54 CT 19.00 48 96 120 10.067 8.556 11.200 14.600 Cam 1.200 19.700 .15 55 & 56 CT 19.00 48 96 120 10.067 8.556 11.200 14.600 Cas 1.200 19.700 .t5 CT! CT 19.00 13 - 14 11.3R0 13.467 14.74R 18.703 Cas 1.600 2.300 .15 l
Appendix Table 2 HOUSTOM LIGHTINC h POWER COMPANT ERISTING CENERATING SYSTFM RASIC UNIT CHARACTERISTICS (cont.)
e FORCED AV. H.R. HEAT CUTAGE INCRFNFNTAL AT PRIMARY RATE FRIED TAR.
UNIT RATE CAPACITY (MW) HEAT RATES (RTU/KVN) MIN. CAP. FUEL PFNAI.TY O&M 06M iqAME NO. TYPE (I) MIN. MID. MAX. MIN. MID. MAX. (BTU /KWH) 'ISED FACTOR ($/UK) ($/MWM)
Miras Clarke 1 ST 3.30 20 36 44 5,R42 16,645 32,775 15,600 Cas 1.250 7,200 .27 2 ST 3.50 20 36 44 5,892 16,645 32.775 15,600 Cne 1.250 7,200 .27 3 ST 3.50 40 68 82 271 22,417 50,930 16,880 Cas 1.000 13,500 T 4 ST 3.50 40 68 R2 271 22.4i? 50,930 16 RRO Cae 1.000 13,500 .27 CTI-6 CT 19.00 76 81 84 11,905 13,843 15,033 18,694 Can 1.600 13,800 .15 Webster 1 ST 3.50 60 95 112 10.993 11,155 11,36R 11.180 can 1.050 18,400 .27 2 ST 3.50 60 95 112 11.060 11.077 11.096 11.070 Cae 1.050 18,400 .27 3 ST 3.50 160 303 375 9,173 9,670 11,231 10,600 Cne 1.070 61,600 .22 CT CT 19.00 13 - 14 11,390 13,467 14,748 10,420 Cao 1.600 2,300 .15 See Bertron 1 ST 3.50 90 144 171 9,263 10,037 11,193 10,425 Can 1.060 28,100 .27 2 ST 3.50 90 144 171 9,760 10.188 10,913 10,600 Cas 1.030 28,100 .27 3 ST 3.50 130 193 225 9,878 10,045 10,259 10,130 Ces 1.020 37,000 .22 4 ST 3.50 130 193 225 9,737 10.106 10.542 10,170 Cao 1.029 37,000 .22 CTI & 2 CT 19.00 38 40 41 10.517 11.046 11.280 17,610 Cne 1.600 6,700 .15 Deep Water 7 ST 3.50 90 148 177 10,274 10,519 10.982 10,R00 Cas 1.100 29,100 .27 1
i
- - j Appendix - Table 3 HOUSTUN 1.ICHTING & POWER COMPANY FUTURE CENERATING ADDITIONS 3 BASIC UNIT CHARACTERISTICS 8
FORCED AV. H.R. HEAT gy_
OUTAGE INCREMFNTAL AT PRIMARY RATE FIIED TAR. SERVICE UNIT MATE HEAT RATES (R_TU/KWH) MIN. CAP. RIEL PENALTT OEM O&M M0/ TEAR NAME NO. M (1) MIN. CAPACITY MID. (MW). MAN. MIN. MID. MAN. (BTU /KVH) USED FACTOR ($/WR) ($/MWM)
U.AePatriah 6 ST 14.0/12.0 335 539 660 8,640 9,435 10.742 10,070 Coal 1.000 108.600 .22 1/79 7 ST 14.0/12.0 300 475 570 8,360 9,766 11,658 10.183 Coat 1.000 93.600 .22 3/80 8 ST 14.0/12.0 300 475 570 8.360 9,766 11,658 10.183 Coal 1.000 93.600 .22 3/86 Allen *a Creek i NS 18.0/16.0 643 991 1,130 10,190 10,243 10,420 10,570 Urse 1.000 51,600 .22 3/85 2 NS 18.0/16.0 643 981 1.130 10,190 10,243 10,420 10.570 Uran 1.000 51,600 .22 1/86 South Texas 1 WS 18.0/16.0 231 332 385 10,076 10,608 11,152 10,420 Uran 1.000 17,600 .22 1/81 Freject 2 NS 18.0/16.0 23t 332 385 10,076 10.608 11.152 10,420 Uran 1.000 17.600 .22 3/82 Unnamed 1 ST 14.0/12.0 400 633 694 8,543 9.798 11,488 11,115 3.ig 1.000 31,700 .22 5/83 Lignite 2 S' 14.0/12.0 100 633 694 8,543 9,798 11.488 11.115 Lig 1.000 31,700 .22 3/84 A , 1 ST 14.0/12.0 507 802 950 8,360 9.766 11,658 10.183 Coal 1.000 93.600 .22 3/88 2 ST !=.0/12.0 507 802 950 8,360 9,766 11,658 10.183 Coat 1.000 93,600 .22 3/89 3 ST 14.0/12.0 507 802 950 8,360 9,766 11,658 10.183 Coal 1.000 93.600 .22 3/93 4 ST 14.0/12.0 507 802 950 8.360 9,766 11.658 10.183 Coal 1.000 93,600 .22 3/94 j i
B i ST 14.0/12.0 507 802 950 8.360 9,766 11,658 10.183 Coal 1.000 93.600 .22 3/90 l 2 ST 14.0/12.0 507 802 950 8.360 9.766 11,658 10,133 Coal 1.000 93.600 .22 3/91 3 ST 14.0/12.0 507 802 950 8,360 9.766 11,658 10.183 Coal 1.000 93,600 .22 3/95
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