ML19259C459
| ML19259C459 | |
| Person / Time | |
|---|---|
| Site: | 05000471 |
| Issue date: | 05/21/1979 |
| From: | Legrow P, Weiner B BOSTON EDISON CO. |
| To: | |
| References | |
| NUDOCS 7906220116 | |
| Download: ML19259C459 (59) | |
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UNITED STATES OF AMERICA 77* p NUCLEAR REGUIATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD
)
In the Matter of )
)
BOSTON EDISON COMPANY, et al. ) Docket No. 50-471
)
(Pilgrim Nuclear Generating Station, )
Unit 2 )
)
)
. APPLTCANTS' SUPPLEMENTAL TESTIMONY ON NEED FOR PILGRIM 2 2281 280 7906220)/6 j
UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD
)
In the Matter of )
)
BOSTON EDISON COMPANY, et al. ) Docket No. 50-471
)
(Pilgrim Nuclear Generating Station, )
Unit 2 )
)
)
- APPLTCANTS' SUPPLEMENTAL TESTIMONY ON NEED FOR PILGRIM 2 2281 281 de
APPLICANTS' SUPPLEMENTAL TESTIMONY ON NEED FOR PILGRIM 2*
PANEL 1 PANELISTS : Benjamin H. Weiner, Vice President-Power Supply Administration, Boston Edison Company Philip A . Legrow, Gener tion Planning Engineer, Boston Edison Company Donald V. Bourcier, Chief of Load Forecasting, New England Power Planning Arthur W. Barstow, bbnager of Generation Planning, New England Power Planning PA,g( 2 PANELISTS : F. Cort Turner, Vice President, Arthur D. Little,
- Inc.
^
Nigel Godley, Manager-Energy Economics Section, Arthur D. Little, Inc.
David Hanna, Energy Economics Section, Arthur D.
Little, Inc.
- Intervenors Commonwealth of Fbssachusetts Contention 6, Cleeton Contention H, Ford Contention M 2281 282
9 PANEL 1 m
O 2281 283 We
1 Q. Mr. Weiner, please state your name and business address.
2 A. Benjamin H. Weiner, Boston Edison Company, 800 Boylston 3 Street, Boston, Massachusetts .
4 Q. What is your present position?
5 A. I am Vice Pres. dent - Power Supply Administration.
6 Q. What positions ~ have you held with Boston Edison Company?
7 A. I began my employment with Edison in 1953 as an Electrical 8 Engineer. In 1957, I was assigned to the President's staff 9 and, in 1969, I was promoted to the position of Assiscant 10 to the President. In April 1973, I was appointed Vice 11 President - Power Supply Administration.
12 Q. Please describe the responsibilities and duties of these 13 positions.
14 A. Since joining the President's staff, my duties have inc luded 15 the negotiation and prepara tion of bulk power purchase and 16 sale agreements, including system and unit sale contracts 17 and joint ownership arrangements covering various types of 18 generation - hydroelectric, fossil and nuclear. I have also 19 negotiated and prepared contracts dealing with transmission 20 rights and charges. Since becoming Vice President, I have 21 also assumed general responsibility for all of Edison's 22 bulk power supply purchases and sales and rates for 23 wholesale for resale sales. Additionally, I am Edison's 2281 284
1 representative on the New England Power Pool (NEPOOL) 2 Working Committee as well as an Alte rnate member of the 3 Executive Committee. These positions require me to keep 4 closely informed on the various activities of 'NEP00L 5 including the operation of the New England Power Exchange 6 (NEPEX) and the New England Planning Staff (NEPLAN), as 7 well as new generation scheduled by other New England 8 companies and other ma tters relating to bulk power supply ,
9 in New England.
10 I am a member of the Company's Rate Committee which examines
. 11 all proposals relative to rate schedules. The Company's 12 NEPEX Billing Group and its Coordinating and Expediting 13 Division, which has the responsibility for scheduling all 14 the Company's major construction rcograms , except for 15 nuclear, report to me.
16 Q. Would you briefly describe your educational and professional 17 background?
18 A. I received a Bachelor of Science degree in Electrical 19 Engineering from the University of Massachusetts in 1953.
20 I have completed the Harvard Business School Program for 21 Management Development. I am a Registered Professional 22 Engineer in the Commonwealth of Nbssachusetts.
23 Q. Mr. Weiner, what is the purpose of your testimony?
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1 A. My testimony is to demonstra te tha t bringing Pilgrim 2 on 2 line at its currently scheduled in-service date of 12/85 3 is necessary in order to assure adequate reliability levels 4 in New England. I will also demonstrate that even at 5 lower growth rates than those currently projected, there 6 are benefits to installing Pilgrim 2 in 12/85 as scheduled.
7 These benefits include cost savings to New England electricity 8 consumers, a reduction in dependency on an expensive and 9 potentially unreliable supply of oil, which is the further-10 ance of national and regional energy policies and goals.
11 Q. Mr. Legrow, please state your full name and business 12 address.
13 A. My name is Philip A. Legrow of Boston Edison Company, 800 14 Boylston Street, Boston, Massachusetts 02199.
15 Q. Wha t is your present position and responsibilities with 16 Boston Edison Company?
17 A. I am a Generation Planning Engineer in Boston Edison's 18 Engineer.i.ng, Planning and Research Department. My res-19 ponsibilities include the analysis of any of the Company's 20 generation costs, both short and long term, and the 21 conduct of long range generation planning studies.
22 Q. Please describe your educational background and experience.
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1 A. I received a Bachelor of Science degree in Electrical 2 Engineering from Nor2heastern University in 1972, where 3 I held memberships in Eta Kappa Nu, Tau Beta Pi, and 4 Phi Kappa Phi, scholastic honor societies. I received 5 a Master of Science degree in Electrical Engineering from 6 Northeastern University in 1973. I have been employed in 7 Boston Edison's Generation Expansion Group since completion 8 of my studies in 1973.
9 Q. Mr. Legrow, what is the purpose of your testimony?
10 A. I performed the production costing and economic analyses 11 underlying Mr. Weiner's testimony regarding the life-of-12 unit oil and dollar savings associated with a 12/85 Pilgrim
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13 2 in-service date as compared with a 12/88 in-service date.
14 Q. Mr. Bourcier, please state your full name and business 15 address.
16 A. Donald V. Bourcier, New England Power Planning (NEPLAN),
17 West Sp;ingfield, Massachusetts.
18 Q. Wh_t position do you hold at NEPLAN?
19 A. I am Chief of Load Forecasting, responsible for forecasting 20 long-range electric energy and peak demands for the six 21 state New England region; I also participate in the develop-22 ment of the annual New England Load and Capacity Report.
23 Q. Would you describe briefly your educational and professional
'- 24 background?
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1 A. Fram 1960 to.1962, I attended the American International 2 College in Springfield, M'a ssachusetts, and I graduated 3 in 1964 from the University of Connecticut in Storrs ,
3 4 Connecticut, with a Bachelor o" Science degiee in
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5 Economics. From 1964 to 1966, I studied at the University 6 of New Hampshire in Durham, New Hampshire, and received 7 a Master of Science degree in Resource Economics. I then 8 worked for the United Illuminating Company in New Haven, 9 Connec ticut , as a statistical economist with responsibility 10 for developing the long-range forecast of electric energy 11 sales and revenue. From 1970 to 1972, I worked for the 12 Remington Electric Shaver Division of Sperry-Rand Corporation 13 in Bridgeport, Connecticut, as a Senior Marketing Research 14 Analyst. At Remington, I daveloped sales forecasting models 15 and conducted consumer market research studies. Since 16 October 1972, I have worked for New England Power Flanning 17 developing and applying methodology for forecasting New 18 England's electric energy and peak demands. I am a past 19 member of the American Marketing Association and the 20 American Sta tistical Association. I am the current chairman 21 of the Load Forecasting Task Force of the NEP00L Planning 22 Committee.
23 Q. Have you written any articles or books in the field of 24 economic analysis?
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1 A. I am co-author of a United States Department of Interior 2 Publication entitled "An Economic Analysis of Public Water 3 Supply."
4 Q. Have you previously testified in this proceeding?
5 A. Yes. In Applicants Direct Testimony on Need for Power 6 following Transcript page 2647.
7 Q. Mr. Bourcier, what is the purpose of your testimony?
8 A. The purpose of my testimony is to identify and present 9 the current NEP00L load forecast. The forecast is 10 presented and explained in three documents:
11 1) NEP00L Forecast for New England, 1979-1989, 12 NEPLAN, Fhrch 1, 1979.
13 2) Report of the NEPOOL Load Forecasting Task Force 14 on the NEP00L Model-Based Forecast of New England 15 Electric Energy and Peak Load, 1979-1989, NEPLAN, 16 bhrch 1, 1979.
17 3) New England Load and Capacity Report, 1978-1989, 18 NEPLAN, April 1, 1979.
19 Q. Mr. Barstow, please state your name and business address.
20 A. Arthur W. Barstow, New England Power Planning (NEPLAN),
21 174 Brush Hill Avenue, West Springfield, Massachusetts.
22 Q. What position do you hold there?
23 A. I am Manager of Generation Planning.
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1 Q. What is your educational background?
2 A. I received a Bachelor of Science degree in Electrical 3 Engineering fram the University of Pbssachusetts in 1951 4 and a Masters degree in Business Administration from 5 American International College in 1964. I have also taken 6 several courses including Power System Engineering from 7 the General Electric Company while an employee there. I 8 am a Registered Professional Engineer in the State of New 9 York and a member of the Power System Engineering Committee, 10 System Planning Subcommittee and several working groups and 11 task forces of the Power Engineering Society of the Institute 12 of Electrical and Electronic Engineers.
13 Q. Would you please describe your work experience?
14 A. In 1951, I went to work as an electrical engineer in the 15 electric design department of the Kellex Corporation in 16 New York City. From 1953 until 1958, I worked for the 17 General Electric Company as a test engineer in various 18 utility related equipment departments for two years, then 19 as a design engineer in the Large Motor and Generator 20 Department in Schenectady, New York for two years and then 21 as a Utility Application Engineer for a year in Schenectady.
22 In 1958, I went to work in the electrical planning department 23 of Western Massachusetts Electric Company in Springfield, 24 Ma ssachusetts. I worked in distribution and transmission
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1 planning until 1960. In 1960, the Connecticut utilities 2 and Western Ma ss. Electric Company (the same companies 3 now served by the CONVEX Satellite of NEPOOL) started 4 generation planning as a group using Westinghouse Electric 5 Company's computer programs entitled Power-Casting. I 6 was appointed to be the Western buss. Electric Company 7 (WMECO) representative in that endeavor. In 1961, while 8 servinn in that capacity, I was transferred to the 9 Connecticut Valley Power Exchange (the dispatch center 10 for Western Mass. Electric Company and the Hartford Electric 11 Light Company) in North Bloomfield, Connecticut and became 12 Systems Operations Engineer. In 1963, while still serving 13 in the generation planning effort for WMECO with Westinghouse, 14 I was transferred back to Western Mass . Electric Company 15 and became Electrical Planning Engineer. In 1964, New 16 England wide generation planning was initiated and I was 17 asked to head it up as Chairman of the Generation Task 18 Force. A t the same t Lme , I was made Interconnection 19 Planning Engineer for Western Mass. Electric Company.
20 In 1968. when NEPLAN was formed, I was one of the three 21 engineers assigned to its startup and to be responsible 22 for generation planning. I am currently Chairman of the 23 Generation Task Force. In addition, I have assisted in 24 the initiation of the load forecasting effort at Pool
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f 1 level. I have co-authored IEEE papers and a number of v
2 New England Genera tion planning reports on the subj ect of 3 ' genera tion planning and related subj ects .
4 Q. Mr. Barstow, what is the purpose of your testimony?
5 A. The purpose of my testimony is to present fa)the capacity 6 aspects of the most recent NEP00L Load and Capacity Report, 7 (b)NEP00L's generation reliability criterion as it is 8 reflected in the determination of NEP00L's required reserves ,
9 and (c)NEP00L's studies relating to cost vs. reliability, 10 and planning for load growth uncertainty.
11 Q. Mr. Weiner, would you describe the current New England load 12 and capacity projections?
13 A. The results of the most recent NEP00L load forecast 14 are presented in Exhibit NP-33. The NEPOOL forecast 15 projects a 3.8% compound annual growth rate in peak load 16 from 1979/80-1989/90. Exhibit NP-34 presents the latest 17 schedule for major generating capacity additions planned 18 for the next decade. Exhibit NP-35 presents the total Ic capability, peak load, and reserve percentages, assuming 20 all of the in-service dates in Exhibit NP-34 are realized 21 (with Pilgrim 2 in 12/85) and alternately, with the assump-22 tion that Pilgrim 2 is delayed until 12/88. With Pilgrim 23 2 in-service in 12/85, Exhibit NP-35 shows that the New 24 England reserve margin will be at or below the minimum 25 desired level. If Pilgrim 2 is delayed to 12/88, reserve 2281 292
1 margins will be inadequate and reliability will be impaired .
2 Exhibit NP-36 graphically illustrates the loads and capacities 3 planned for the next decade. If these planned units in 4 New England are delayed, New England will not have sufficient 5 generating capacity to maintain system reliability. The 6 Sears Island unit has encountered opposition, particularly 7 from the Maine Public Utilities Commission Staff, on the 8 basis of economics and environmental considerations. The 9 NEPCO units are just now beginning the licensing process 10 and the proposed site has not yet been acquired. Signifi-11 cant delays in each of these units must be considered a 12 distinct possibility. With such potential delays it would 13 not be prudent to delay Pilgrim 2 beyond 12/85.
14 Q. Mr. Barstow, please explain how NEPOOL determines how much 15 reserve capacity is required.
16 A. The NEP00L Management Committee establishes a generation 17 reliability criterion. Given this criterion, as well as 18 a knowledge of the pool's operating procedures, the 19 characteristics of the units in the existing system, and a 20 knowledge of the plans for expanding the system, it is 21 possible, using reliability computer programs, to determine 22 the total generating capacity reserves required.
23 Q. What is the NEP00L generation reliability criterion?
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1 A. NEPOOL has adopted a criterion which calls for the 2 installation or purchase of sufficient capacity to assure 3 that it will be unnecessary to physically disconnect 4 customers (i.e., disconnect supply feeders) more frequently 5 than once in ten years.
6 Q. On what basis did NEP00L select the one day in ten years 7 disconnecting customers' criterion?
8 A. In a study completed in 1974, we were able to develop risk 9 profiles for different reliability levels by relating 10 various criteria to the way the system is actually operated.
11 These profiles were checked against operating experience.
12 Specifically, in the period from January 1971 through 13 October,1973 there were 19 voltage reduction incidents 14 in the pool created by insufficien t available capacity 15 whereas the reliability program estimated 13.48 to 21.84 16 incidents. SLnilarly, there were four radio and TV appeal 17 incidents compared to a projected 1.99 to 3.19 incidents.
18 And there were zero disconnection incidents whereas the 19 program estimated 0.32 to 0.58 or in the zero to one 20 incident range. Had the actual, valid pool experience been 21 longer, there would undoubtedly have been actual disconnec-22 tion incidents. The sample was terminated with October, 1973 23 because of the subsequent excess reserve situation brought 24 about by the oil embargo.
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1 With the criterion selected, the following frequency of 2 occurrence is expected:
3 Voltage Reductions -
7-8/yr.
4 Radio-TV appeals -
Approx. 1/yr.
5 Disconnect Customers -
0.1/yr. (or 1 every 10 years) 6 Lower reliability levels resulted in a greater number of 7 expected occurrences in each category with only limited 8 savings in cost of electricity to the customer. (Costs of 9 outages to the customer were not considered) . Accordingly, 10 the one day in ten years customer disconnection was con-11 sidered to be a reasonable pool generation planning criterion 12 which effectively balance system cost in the form of reserve 13 requirements with reliability expressed in terms of the 14 expected need for voltage reductions, radio and TV appeals 15 and actual customer disconnection by rotation of feeders.
16 Thus, the NEPOOL Executive Committee decided that this was 17 the reliability criterion to which the system should be 18 ~ designed.
19 Q. Having established the reliability criterion, would you 20 please describe the procedure used to determine the NEPOOL 21 capacity requirements?
22 A. Required reserve margins are based on calculations of the 23 probability of occurrence of insufficient generating 2281 295
1 capacity to meet the anticipated loads. These calculations 2 are performed by NEPLAN for the pool. Once the reliability 3 tr culations have been completed and the results reviewed 4 by the NEPOOL Planning and Executive Committees, the 5 NEP00L Objective Capability is established. The Objective 6 Capability is the amount of capacity (load plus required 7 reserves) deemed necessary by the Executive Committee to 8 meet the Pool's reliability criterion.
9 Q. Has the Executive Committee established the NEPOOL Objective 10 Capabilities for the power years 85/86, 86/87, 87/88, 88/89 11 and beyond?
12 A. No, but this is expected to occur this year. However, 13 reasonable prelbminary estimates are available for the 14 reserve level required to meet the pool reliability criterion 15 in that period.
16 Q. What is your estimate of the reserve level required to meet 17 the reliability criterion in the period 85/86 to 88/89 18 and beyond?
19 A. On the basis of expanding under the Pool's generation mix 20 guidelines, recent reliability studies indicate, at this point 21 in time, that required reserves in the order of 23% to 28%
22 of peak load will be recommended to the Planning and 23 Management Committees. These reserves vary fram
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1 year to year depending on unit commitment and their 2 maturity trends.
3 Q. Mr. Barstow, what are the economic implications of 4 installation of nuclear capacity before it is required 5 to meet the NEPOOL reliability criterion?
6 A. The NEP00L Generation Task Force and the NEPLAN Staff 7 report " Cost Versus Reliability Study For The Years 8 1983/84-2000/01," November, 1978, (an update of the 1974 9 reliability study) concludes that when the system is far 10 from its economic generation mix, such as is the present 11 case for New England, capacity installed to improve the 12 mix which results in more than the minimum required to
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13 meet the reliability criterion can be economically justified.
14 The higher the reliability level, the lower the overall 15 costs due to the early installation of nuclear capacity.
16 Considerable amounts of oil are saved in the higher 17 reliability cases as nuclear units are installed earlier 18 than in the other cases. For example, a 10 years / day LOLP 19 reliability level saves 207 million barrels of oil compared 20 to 1.0 year / day LOLP level (which approximates the present 21 NEP00L criterion) resulting in a reduction of 13.5% of the 22 oil used in the 1.0 year / day LOLP case.
23 In addition, the February 1978 NEP00L Generation Task Force 24 and the NEPLAN Staff report " Planning for Load Growth 2281 297
1 Uncertainty (Recognizing Unit Lead Times)" demonstrated 2 that there is a considerable economic penalty associated 3 with planning to a particular load growth rate and having 4 to install short lead-time capacity if the system experiences 5 a higher load growth race than that on which the expansion 6 was based. In addition, there is an economic benefit 7 associated with planning to a high load growth rate and 8 actually experiencing a lower growth rate. Those savings 9 are attributable to the early installation of nuclear 10 capacity which enables the substitution of nuclear supplied 11 energy for the more costly fossil supplied energy. The 12 early installation of these nuclear units also results in 13 considerable oil savings when compared to the generation 14 expansion pa ttern designed j ust to meet the actual load 15 growth rate.
16 Q. Mr. Weiner, what are the economics of delaying Pilgrim 2's 17 in-service date?
18 A. The present worth of the cost differences due to delay in 19 the in-service date for Pilgrim 2 favor installation at the 20 earliest possible time independent of reliability require-21 ments. For example , for a 3 year delay, assuming that all 22 other planned units are brought in on schedule, 12/85 23 installa tion results in net present worth savings of
$1070 million (in 1986 dollars) to New England consumers
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24
. 25 over the life of the project. In spite of higher costs 2281 298
1 in the first several years, the oil dollars saved 2 rapidly turn the deficiency into a savings. The break-3 even year for net present worth savings is 1989, only 4 four years a f ter installa tion. ,
5 In addition to .the loss of savings, the delay of Pilgrim 6 2 will increase our dependence on oil as a source of 7 electricity. New England will burn an additional 12 8 million barrels of oil for each year of delay. The outlook 9 for future oil supply is not encouraging, and such increased 10 oil consumption clearly contradicts national energy policy 11 and the regional interest.
12 Q. Have you evaluated the sensitivity of this economic analysis 13 to different peak-load growth rates?
14 A. At the request of the NRC Staff we analyzed the impac t of 15 a 12/85 installation date versus 12/88 assuming a 3.4%
16 peak load growth. The 3.4% growth case yielded present 17 worth savings of $806 million (in 1986 dollars) over the life 18 o f the proj ec t . The breakeven year was 1991. We have also 19 analyzed a 3.0% growth rate for New England, comparing 20 a 12/85 and 12/88 in-service date. The 3.07, growth case 21 yielded present worth savings of $776 million /in 1986 22 dollars) over the life of the project. The breakeven year 23 was also 1991. We have no t explicitly analyzed the impac t 24 of a 12/85 installa tion date versus a 12/88 installation
., 25 da te assuming a peak load growth ra te higher than 3.8%.
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1 It is not unreasonable to expect that a strong economic 2 recovery in New England might lead to load growth that 3 would exceed our current proj ections. At a higher load i
4 growth rate the present worth savings accruing to the 5 earlier in-service date would be even greater due to the 6 increased necessity of relying on increasingly expensive 7 oil-fired generation.
8 Q. Mr. Legrow, would you please describe the analyses that 9 resulted in the savings presented by Mr. Weiner?
10 A. The results presented by Mr. Weiner flow from year by 11 year comparisons of the capital costs of Pilgrim 2 and 12 New England-wide fuel costs for Pilgrim 2 in-service dates 13 of 12/31/85 and 12/31/88, and for New England forecasted 14 load growth rates of 3.8% (the current NEPOOL forecast),
15 3.4% and 3.0%. These annual differences in capital charges 16 and fuel costs were summed, and the accumulative present 17 worth at Boston Edison's projected marginal cost of 18 money was taken to yield the life-of-unit savings 19 associated with the 1985 in-service date. These annual 20 differences, totals, and accumulative present worths are 21 set out in Exhibits NP-37, NP-39, and NP-41 for the 3.8%,
22 3.4% and 3.0% growth rates, respectively. Also estimated 23 were the barrels of fuel oil displaced due to 1985 as 2281 300
1 opposed to 1988 installation of Pilgrim 2; these 2 estimates are shown as Exhibits NP-38, NP-40 and 3 NP-42 for the 3.8%, 3.4% and 3.0% growth rates, 4 respectively. The major assumptions inherent in 5 the development of Exhibits NP-37 through NP-42 are 6 listed in Exhibit NP-43.
7 Q. Would you describe in more detail the derivation of 8 your " Capital" and " Fuel" cost columns of Exhibits 9 NP-37, NP-39 and NP-41?
10 A. To generate the " Capital" column, which is common to 11 all three exhibits, annual capital recovery, income tax, 12 and investment tax credit charges were added to annual
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13 projections of property taxes and nuclear fuel carrying 14 charges for the 28-year book life of the unit for each 15 in-service date, and the differences taken. The 16 negative entries for years 1986-1988 reflect the 17 absence of capital charges for the 1988 in-service case, 18 while the 1989-2013 entries reflect the higher capital 19 costs of the delayed (1988) unit. It is assumed that, 20 under current Massachusetts law, property taxes end with 21 the end of book life (2013 and 2016 for the respective 22 in-service dates,.
23 The " Fuel" savings for the various load growths were 24 calculated by modeling the NEPEX system on the Company's
. 25 production costing program over the years 1986-1993.
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1 The program was run twice for each load growth - once 2 with a 1/1/86 Pilgrim 2 in-service date, and once with a 3 1/1/89 in-service date. The in-service dates of all 4 other NEPOOL units were fixed at those published in the 5 New England Load and Capacity Report of April 1,1979.
6 The entries in the " Fuel" column are the annual differences 7 in the fuel costs of the entire New England system: for 8 1986 through 1988, with and without Pilgrim 2; fram 1989 9 to 1993 reflecting the differential in maturity of Pilgrim 10 2. The absence of entries after 1993 reflects the fact that, 11 given either in-service date, Pilgrim 2 will have reached 12 a mature capacity factor by 1994, and no basis exists for 13 the projection of production cost differences from that 14 point on.
15 Q. Mr. Weiner, you made earlier reference to the outlook for 16 future oil supply. Could you elaborate further on this 17 point?
18 A. Recent international events have had dramatic repercussions 19 on the world oil markets. Consequently supplies of imported 20 oil, upon which New England must depend, cannot be 21 regarded as secure. The lesson of the 1973-74 Arab oil 22 embargo was reinforced drama tically this winter by the 2281 302
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1 total cutoff of Iranian oil from the world market for 2 several months. The degree of overall U.S. dependence 3 on petroleum imports has increased to over 40%, and 4 the source oh most of these imports has shifted geo-5 graphically,from the Western Hemisphere to the Arab 6 Middle East and Africa, so that the security of oil 7 supplies is considerably lower than it was 5 years ago.
8 Since 1970, the world price of crude oil has risen from 9 spproximately $1 per barrel to almost $15 currently, 10 and the continuing ability of OPEC to impose its will 11 on the market has produced an increase of approximately 12 25% in the past few months alone. As a consequence of 13 the tightness of the market brought about by the 14 temporary Iranian cutoff, the March 1979 New York 15 Harbor contract price for residual fuel oil was about 16 45% higher than the March 1978 price. While such 17 variations in spot prices may magnify the effect of 18 temporary shortages, the actual OPEC floor price for 19 Saudi Arabian marker crude now stands at $14.55, while 20 other OPEC nations have generally set their prices 21 significantly higher. A recent oil delivery to Boston 22 Edison was priced at $17.60/ barrel, $5/ barrel or 40%
23 higher than the 1973 average cost of $12.60/ barrel. In 2281 303
1 addition, our principal supplier, Asiatic Petroleum 2 Company has formally put us on notice that fuel shortages 3 are possible at Mystic Station in the future. While we 4 have not as yet been denied delivery, we are on notice 5 that supply problems exist. Uncertainty over the longer 6 term is compounded, both as to price and assurance of 7 supply. While it is impossible for an electric utility 8 to significantly displace its reliance on oil in the 9 near term, we believe that the public interest demands that 10 we take all steps possible to reduce out oil dependency 11 over the longer term. Bringing Pilgrim 2 in service on 12 the earliest possible schedule will make a significant 13 contribution to that goal.
14 Q. You also mentioned consistency with Na tional energy policy.
15 What specific policies were you referring to?
16 A. When President Carter announced the first comprehensive 17 National Energy Plan in 1977, he articula ted Administration 18 Policy that dependence on fossil fuel imports be reduced 19 through a large-scale conservation effort tha t would check 20 the trend of increasing reliance on petroleum and natural 21 gas while providing time for the nation to develop alternative 22 energy supplies.
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1 In response, Congress passed a series of Acts [re ferred 2 to as the National Energy Act (NEA)] aimed at addressing 3 our nation's energy problems. One of these was the 4 Powerplant and Industrial Fuel Use Act of 1978 (EUA).
5 In passing the FUA , the Congress made the following Findings :
6 (1) the protection of public health and welfare, the preservation of national security, and the 7 regulation of int erstate commerce require the establishment of a program for the expanded use, 8 consistent with applicable environmental require-ments, of coal and other alternate fuels as primary 9 energy cources for existing and new electric power-plants and major fuel-burning ins tallations; and 10 (2) the purposes of this Act are furthered in cases in which coal or other altervate fuels are used by 11 electric powerplants and major fuel-burning installa-tions, consistent with applicable environmental require-12 ments, as primary energy sources in lieu of natural gas or petroleum.
13 In the definitions, Congress included uranium as an alter-14 nate fuel. Congress included in the Statement of Purposes 15 of the Act:
(1) to reduce the importation of petroleum and increase 16 the Nation's capability to use indigenous energy resources of the United States to the extent such reduction a 17 and use further the foal of national energy self-suffiency and otherwise are in the best interests of 18 the United States; (2) to conserve natural gas and petroleum for uses, 19 other than electric utility or other industrial or commercial generation of steam or electricity, fe r 20 which there are no feasible alternative fuels or raw ma ter ial subs titutes ;
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- 1 (3) to encourage and foster the greater use of coal and other alternate fuels, in lieu of natural 2 gas and petroleum, as a prLmary energy source;...
(6) to prohibit or, as appropriate, minimize the use 3 of natural gas and petroleum as a primary energy source and to conserve such gas and petroleum for 4 the benefit of present and future generations; ,
(7) to encourage the modernization or replacement 5 of existing and new electric powerplants and major fuel-burning installations which utilize natural gas 6 or petroleum as a primary energy source and which cannot utilize coal or other alternate fuels where to do 7 so furthers the conservation of natural gas and petroleum; ...
8 (11) to reduce the vulnerability of the United States to energy supply interruptions; 9 Bringing PilgrLa 2 on-line at the earliest possible date
. 10 (i.e., December, 1985) would be consistent with the intent 11 and purposes of FUA, and the National Energy Plan.
12 The early installation of Pilgrim 2 is also most important 13 from the standpoint of reducing our regional dependence on 14 imported residual fuel oil. Of the five contiguous DOE 15 Petroleum Administration for Defense (PAD) distric ts , the 16 most vulnerable to interruption of Laported oil supply is 17 District I, which is comprised of all of New England, New 18 York, Pennsylvania, New Jersey, Maryland, Delaware, West 19 Virginia, Virginia, North and South Ca rolina, Georgia and 20 Florida. In 1977, the total imports of all petroleum
. 21 products to this East Coast region was equal to more than 2281 306
1 15 times the total amount of imported petroleum products 2 of the next largest importing PAD district. When 3 considering only residual oil, PAD District I imports 4 were almost thirty times the amount imported by the next 5 highest district.(1) Because District I receives over 6 79% of its residual oil from foreign sources, it is 7 critical that this region's dependency on residual fuel 8 imports be reduced, if the goals of EUA/NEA are to be 9 met.
10 As discussed, these goals are to reduce our nation's 11 dependency on foreign petroleum Laports for non-essentia'l 12 uses, while continuing to ensure an adequate reliability 13 of service for electric generation. If Pilgrim 2 is 14 deplayed, not only are we needlessly consuming millions 15 of additional barrels of oil, at higher and higher prices, 16 but we cre also exposing ourselves to extreme political, 17 economic and social risks. Bringing Pilgrim 2 on-line 18 as scheduled in 1985 will contribute to the resolution 19 of problems associated with our regional vulnerability, 20 and ensure reliability of service to the consumer while 21 contributing to our national goal of energy independence.
(1) Energy Information Administration, Department of Energy, Energy Data Reports, Year 1977.
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tilH E7 CIAtJD IUiUCAST SIINAIN 1979-1989 1979-89 Grguni Anrual Actual Forecast Grtwth itate 1977 1975 109 1930 1931 198T 1953 198 M 985 1986 1987 1388 1987 (i)
(binchkmt Peak Insi (Mf)
IWonks! . Winter (Dec./Jan.) 14846 15100P
. Stumer 14234 14458 Heather (a)
Corrected . Winter (Dec./Jan.) 15363 15500P 16595 17266 18036 18822 19755 20668 21502 22267 22989 235', 24120 3.81
. Stamer 13712 14954 15569 16108 16714 17409 18113 18958 19784 20552 21275 21931 22495 3.75 Dieryy Sales to Ultirrute Customrs (G41)
. Total 72751 n/a 84276 87590 91249 95241 99318 104148 108843 113217 117285 120980 124144 3.95
. Ibsidential 18222 n/a 31631 32248 33260 34543 35721 37113 38450 39577 40572 41371 42007 2.88
. Irulustrial n/a n/a 22786 24143 25446 26397 27433 28670 29841 31035 32120 33220 34123 4.12
. Qumercial n/a n/a 28655 30006 31341 33072 34904 37066 39217 41234 43191 44962 46569 4.98
. Mismilaneous n/a n/a 1205 1194 1203 1228 1259 1299 1336 1371 1403 1427 1445 1.84 tbt Fnergy for Insi (GAI) (b) 79781 82800P 91861 95473 99462 103812 108256 113521 118639 123407 127840 131868 135317 3.95 Annual last Factor (%) 61.3 62.6P 63.2 63.1 63.0 63.0 62.6 62.7 63.0 63.3 63,5 63.8 64.0 Famnic/fuojraghic
. IMaalatim (000's) 12238 12256P 12337 12404 12491 12569 12654 12745 12839 12937 13029 13117 13206 0.68
. limscholds (000's) 4141 n/a 4301 4379 4467 4552 4637 4723 4810 4892 4972 5050 5129 1.78
. IWloyrrent (000's) (c) -
- 5377 n/a 5692 5844 5923 5988 6066 6150 6230 6300 6361 6423 6475 1.30
. Manufacturing (000's) n/a n/a 1469 1499 1513 1514 4525 1539 1548 1559 1563 1569 1565 0.64
. Nunnanufacturity (000's) n/a n/a 4202 4323 4389 4453 4520 4590 4661 4720 4777 4833 4889 1.53
. Unenploynent Iute (%) 7.5 n/a 6.4 5.8 5.9 5.8 5.6 5.4 5.3 5.3 5.4 5.4 5.4 -
M
. tbt Migratim (000's) n/a n/a 27 41 31 35 38 37 38 32 29 30 30 -
y
. Persmal Irwxxie (mils 69) S3195 n/a 56514 58947 61058 63010 65109 67299 69497 71754 73961 76196 78364 3.32 H N N N H Q n/a - not available Z
- P - Preliminary y (a) Correctim insed on Img-term historical peak weather crzulitions. w g (b) 11asal m merify sales to ultimate customrs anl nine geramt transmission aal distrilution line losses.
g (c) 'Ibtal sploynent incitales a[ proximately 21 thaunarsi kbs outside thw nylarmi (i.e. , ikM York armi Casala) .
Q
MAJOR NEW FNGl.Allil GEllERATlilG CAPAC11Y AlllliIl0lls (IIIR0llGil DEClMilER 1989)
SCliEllllLED CAPACITY lil-SERVICE COMPANY STAT 10ll FUEL MW AS OF II/79 MASS. MUNICIPALS ST0llY llR00K 011. 3'10 NOV 1981 MASS. MUNICIPALS STONY llR00K OIL 170 ll0V 1982 PilllLIC SERVICE CO. OF N.11. SEAllR00K 1 tillC 1150 APR 1983 PUBLIC SERVICE.CO. OF N. II. SEAllR00K 2 tillC 1150 Fell 1985 PIL6 RIM 2 NilC 1150 DEC 1985 BOSTON EDIS0N HILLS 10NE 3 (10C 1150 MAY 1986 NORTilEAST UTILITIES CENTRAL MAINE POWER CEARS ISI.AllI) C0AL 568 Il0V 1987 NEW ENGLMID ELECTRIC SYSTEM HEPC0 1 flut 1150 l10V 1987 Q NEW ENGLAND ELECTRIC SYSTEM llEPC0 2 HilC 1150 l10" 1989 z
- .n e
EXHIBIT NP-35 NEW ENGLAND SYSTEM CAPABILITIES AND ESTIMATED PEAK LOADS 1979-1909
% RESERVE AFTER ,
MAINTENANCE WITH
% RESERVE PILGRIM 2 POWER TOTAL PEAK AFTER INSTALLED YEAR CAPABILITY LOAD MAINTENANCE IN 12/88 1979/80 21,980 16,595 30.0 -
1980/81 21,982 17,266 26.8 -
1981/82 22,301 18,036 20.0 -
l 1982/83 22,626 18,822 19.5 - I 1983/84 23,773 19,755 20.3 -
1984/85 23,768 20,668 15.0 -
1985/86 25,8E9 21,502 20.3 15.0 1986/87 26,804 22,267 20.4 15.2 1987/88 28,421 22,989 23.6 18.6 1988/89 28,422 23,595 20.5 -
1989/90 29,574 24,120 22.E -
e 2281 310
tlEW filGLMID LOADS AtlD CAPACITifS 3r; _ AS OF APRIL 1979 il[PCo 2 l
tiS Ana P[N'1 S Mil LS10til. 3 SETBR00K 2 V 30 - PI _(iRIN 2 -
3 SEABROOK 1 v y
/
ST0flYllR00K CT l' / LOAD PLUS 23" m 26 - / prs [Ryc p ST0tlYBR00K CC ,
< r y -
CAPACITY -[ '
g 22 - ,
m s'
E y
,- WillTER PEAK LOAD M '
c2 18 _ '
B y'
/ [T1 l'I ~ .
co s,
~
Y 10 - 5 2-
/2 /3 /'l /5 7Ii 77 78 75858l' 82 83 8'I 85 86 8l 88 8q YFAR
Exhibit NP-37
_ f1EP00L MODEL LOAD GROWTH CASE (3.8%)
SAVIf4GS ASSOCIATED WITH IflSTALLIflG PILGRIM 2 If1 1985 VS. 1988 (S000
~
1986 Dollars Capital Fuel Total Acc. P.W. (10.83%)
1986 (409,125) 300,715 (108,410) (108,410) 1987 (397,989) 378,364 ( 19,625) (126,117) 1988 (384,241) 398,372 14,131 (114,613) 1989 170,882 73,418 244,300 64,841 1990 173,752 55,653 229,405 216,886 1991 166,472 62,252 228,724 353,667 1992 162,858 10,647 173,502 447,287 1993 157,040 28,863 185,903 537,794 1994 151,554 - 151,554 604,369 1995 145,932 - 145,932 662,209 1996 139,262 - 139,262 712,012 1997 137,570 - 137,570 756,403 1998 136,791 - 136,791 796,229 1999 135,518 - 135,518 831,830 2000 131,319 - 131,319 862,957 2001 130,917 - 130,917 890,956 2002 128,859 - 128,859 915,822 2003 121,559 - 121,599 936,993 2004 116,188 - 116,188 955,246 2005 108,684 - 108,684 970,652 2006 108,041 - 108,041 984,470 2007 106,526 - 106,526 996,763
~
2008 104,634 - 104,634 1,007,657 2009 101,370 - 101,370 1,017,181 2010 99,076 - 99,076 1,025,580 2011 96,954 - 96,954 1,032,995 2012 94,069 - 94,069 1,039,486 2013 91,312 - 91,312 1,045,172 2014 169,815 - 169,815 1,054,713 2015 154,385 - 154,385 1,062,538 2016 139,895 - 139,895 1,068,937 2281 ;12
Exhibit NP-38 NEP00L MODEL LOAD GROWTH CASE (3.8%)
FUEL SAVINGS ASSOCIATED WITH INSTALLING PILGRIM 2 IN 1985 VS. 1988 12/85 Pi'.. 2 12/88 Pil. 2 a bbl. of oil
- MWh MWh MWh 1986 5,925,052 - 5,925,052 9,875,087 1987 5,940,987 - 5,940,987 9,901,645 1988 6,261,031 - 6,261,031 10,435,051 1989 6,748,033 5,941,885 806,148 1,343,580 1990 6,747,004 5,940,027 806,977 1,344,962 1991 7,043,476 6,236,731 806,745 1,344,575 1992 7,059,043 6,759,561 299,482 499,137 1993 7,0.25,455 6,725,908 299,547 499,245 Totil 011 Savings 35,243,282 bbl.
- Assumes 10,000 Btu /kWh, 6 MBtu/ bbl.
2281 ;13 e
Exhibit NP-39 NRC 3.4% GROWTH CASE SAVINGS ASSOCIATED WITH INSTALLING PILGRIM 2 IN 1985 VS. . 388
($000)
~
~
1986 Dollars Capital Fuel Total Acc. P.W. (10.83%)
1986 (409,125) 242,340 (166,785) (166,785) 1987 (397,989) 278,080 (119,909) (274,976) 1988 (384,241) 311,208 ( 73,033) (334,433) 1989 170,882 52,227 223,109 (170,546) 1990 173,752 49,291 223,043 ( 22,718) 1991 166,472 40,902 207,374 101,296 1992 162,858 8,766 171,624 193,901 1993 157,040 9,007 166,047 274,741 1994 151,554 - 151,554 341,315 1995 145,932 - 145,932 399,155 1996 139,262 - 139,262 448,958 1997 137,570 - 137,570 493,349 1998 136,791 - 136,791 533,176 1999 135,518 - 135,518 568,777 2000 131,319 - 131,319 599,903 2001 130,917 -
130,917 627,902 2002 128,859 - 128,859 652,768 2003 121,599 - 121,599 673.940 2004 116,188 - 116,188 697 193 2005 108,684 - 108,684 701,599 2006 108,041 - 108,041 721,416 2007 106,526 - 106,526 733,710 2008 104,634 - 104,634 744,640 2009 101,370 - 101,370 754,128 2010 99,076 - 99,076 762,526 2011 96,954 - 96,954 769,941 2012 94,069 - 94,069 776,433 2013 91,312 - 91,312 782,119 2014 169,815 - 169,815 791,659 2015 154,385 - 154,385 799,485 2016 139,895 - 139,895 805,884 2281 314
Exhibit NP-40 NRC LOAD GROWTH CASE (3.4%)
FUEL SAVINGS ASSOCIATED WITH INSTALLING PILGRIM 2 IN 1985 VS. 1988 12/55 Pil. 2 12/88 Pil. 2 A bbl. of oil
- MWh MWh MWh 1986 5,941,612 -
5,941,612 9,902,687 1987 5,941,897 -
5,941,897 9,903,162 1988 6,258,764 - 6,258,764 10,431,273 1989 6,746,244 5,940,968 805,276 1,342,127 1990 6,744,419 5,936,950 807,469 1,345,782 1991 7,041,752 6,237,278 804,474 1,340,790 1992 7,064,867 6,766,109 298,758 497,930 1993 7,040,378 6,743,325 297,053 495,088 Total 35,258,839
- Assumes 10,000 Btu /kWh, 6 MBtu/ bbl.
2281 A5
Exhibit NP-41 3.0% LOAD GROWTH CASE SAVINGS ASSOCIATED WITH INSTALLING PILGRIM 2 IN 1985 VS. 1988
($000 1986 Dollars Capital Fuel Total Acc. P.W. (10.83%)
1986 (409,125) 233,325 (175,800) (175,800) 1987 (397,989) 264,795 (133,194) (295,978) 1988 (384,241) 299,278 ( 84,963) (365,148) 1969 170,882 48,883 219,765 (203,717) 1990 173,752 47,280 221,032 ( 57,221) 1991 166,472 39,022 205,494 65,668 1992 162,858 12,512 175,370 160,294 1993 157,040 16,496 173,536 244,780 1994 151,554 - 151,554 311,355 1995 145,932 - 145,932 369,195 1996 139,262 - 139,262 418,998 1997 137,570 - 137,570 463,36~
1998 136,791 - 136,791 503,21.
1999 135,518 - 135,518 538,816 2000 131,319 - 131,319 569,943 2001 130,917 - 130,917 597,942 2002 128,859 - 128,859 622,808 2003 121,599 - 121,599 643,979 2004 116,188 - 116,188 662,233 2005 108,684 - 108,684 677,639 2006 108,041 - 108,041 691,456 2007 106,526 - 106,526 703,749 2008 104,634 - 104,634 714,643 2009 101,370 - 101,370 724,167 2010 99,076 - 99,076 732,566 2011 96,954 -
96,954 739,981 2012 94,069 - 94,069 746,473 2013 91,312 - 91,312 752,159 2014 169,815 - 169,815 761,698 2015 154,385 - 154,385 769,525 2016 139,895 - 139,895 775,923 2281 al6 e
Exh ib i t NP-42 3.0% LOAD GRO'n'TH CASE FUEL SAVINGS ASSOCIATED WITH INSTALLING PILGRIM 2 IN 1985 VS. 1988 12/85 Pil. 2 12/88 Pil. 2 a bbl. of oil
- MWh MWh MWh 1986 5,941,611 - 5,941,611 9,902,685 1987 5,939,522 - 5,939,522 9,899,203 1988 6,257,471 - 6,257,471 10,429,118 1989 6,744,706 5,938,480 806,226 1,343,710 1990 6,743,760 5,934,781 808,979 1,348,298 1991 7,041,397 6,235,255 806,142 1,343,570 1992 7,066,308 6,766,134 300,174 500,290 1993 7,044,431 6,744,450 299,981 499,968 Total Oil Savings 35,266,842 bbl.
- Assumes 10,000 Btu /kWh, 6 MBtu/ bbl.
2281 17 e
e
Exhibit NP-43 MAJOR ASSUMPTIONS EMPLOYED IN ECONOMIC ANALYSIS OF DELAYED INSTALLATION General rate of inflation: 6%/ year Boston Edison cost of money: 10.83%
Fossil Fuel price forecast: July 1978 A. D. Little report, except inflation assumed to remain constant at 6% rather than dipping to 4% after 1989.
Nuclear fuel price forecast: Internal Boston Edison forecast, consistant as to input assumptions with the July 1978 A. D. Little report.
Sample current dollar. fuel prices: ($/MMBtu) 1986 1988 1990 1992 1994 No. 6 oil. 1% S 5.162 6.474 8.120 9.561 11.257 No. 6 oil, 2.2% S 4.720 5.906 7.390 8.695 10.230 No. 2 oil 6.087 7.564 9.400 11.033 12.948 Coal 2.655 2.946 3.270 3.774 1.413 Pilgrim 2, 12/85 C.O. .780 .829 1.121 1.330 1.579 Pilgrim 2, 12/88 C.O. - -
1.102 1.133 1.493 Load Model: 59% load factor all cases; peak loads:
- 1. as published in the April 1, 1979 New England Load and Capacity Report and other NEP00L documents
- 2. 1985/86 winter peak of 19,510, extrapolated at 3.4%/ year as specified by the NRC's Oak Ridge Model.
- 3. 1978/79 weather-adjusted winter peak, extrapolated at 3.0%/ year.
Pilgrim 2 capital costs: $1,895 million in 1985, $2.5 billion in 1988 Pilgrim 2 book life: 28 years Pilgrim 2 tax life: 16 years Pilgrim 2 depreciation method: double declining balance, switching to straight line Effective income tax rate: 51.38%
Pilgrim 2 property tax assumptions: Plymouth annual budget growth: 10%
2281 al8
Plymouth valuation growth: 10%/ year Classification implemented in FY 1980 Nuclear capacity factor maturation:
1st year capacity factor: 59%
2nd year: 59%
3rd year: 62%
4th year: 67%
5th year: 67%
6th and following years: 70%
Future capacity additions to meet load plus 23% required reserves through 1993:
nuclear, similar to Pilgrim 2. All planned units listed in the April 1, 1979 New England Load and Capacity Report installed on the schedules indicated therein.
2281 :19 t
4
PANEL 2 2281 220
1 Q. Mr. Turner, will you please state your name and place of residence?
2 A. My name is F. Cort Turner and I reside in Cambridge, Massachusetts.
3 Q. By whom are you employed?
4 A. I am employed by Arthur D. Little, Inc., Cambridge, Massachusetts.
5 Q. What is youi educational background? -
6 A. I received 'uadergraduate and graduate degrees in chemical engineering 7 and in management from the Massachusetts Institute of Technology.
8 Q. Please describe your experience with Arthur D. Little, '
9 A. I have been employed by Arthur J. Little, Inc. since 1922. My current 10 position is Vice President responsible for the overall coordination 11 of the company's international energy consulting work. Prior to this, 12 I was manager of Arthur D. Little's Energy Economics Section in 13 Cambridge. Throughout my career at Arthur D. Little I have specialized 14 in oil and gas consulting on behalf of such diverse clients as large 15 energy users (utilities and chemical companies), oil companies (major 16 and independent), governments of producing a,d consuming countries, 17 the U.S. Environmental Protection Agency, etc. This work has included 18 strategic planning, crude oil and product marketing, refinery feasibility 19 studies, energy forecasting, design of taxation terms for oil and gas 20 exploration, and the development of a linear programming refinery 21 model to test the impact of change on the cost of producing individual 22 crudes.
23 Q. Mr. Godley, will you please state your name and place of residence?
24 A. My name is Nigel Godley and I reside in Acton, Massachusetts.
25 Q. By whom are you employed?
26 A. I am employed by Arthur D. Little, Inc., Cambridge, Massachusetts.
27 Q. What is your educational background?
2281 321
1 A. I hold a diploma in business Administration from the Portsmouth 2 College of Technology and I attended a special course dealing with 3 decision-making in the marine industries at the Massachusetts 4 Institute of Technology.
5 Q. Please describe your experience with Arthur D. Little, Inc.
6 A. I have been employed by Arthur D. Little, Inc. since 1969. I 7 am currently manager of the Company's Energy Economics Section.
8 My areas of specialization include crude oil and petroleum product 9 pricing, oil taxation, concession analysis, petroleum transportation, 10 energy forecasting and the financial analysis o( the hydrocarbon 11 industry including exploration production, refining, and marketing 12 ac tiv ities.
13 Q. Mr. Hanna, will you please state your name and place of residence?
14 A. My name is David Hanna, and I reside in Arlington, Massachusetts.
15 Q. By whom are you employed?
16 A. I am employed by Arthur D. Little, Inc., Cambridge, Massachusetts.
17 Q. Wha t is your educational background?
18 A. I received an undergraduate degree in physical sciences from 19 0xford University and a graduate degree in business management from 20 the London Business School.
21 Q. Please describe your experience with Arthur D. Little, Inc.
22 A. I have been employed by Arthur D. Little, Inc., since 1972. I 23 am a member of the Energy Economics Section in Cambridge and specialize 24 in oil and gas consulting for U.S. and international clients. My 25 work has included strategic planning, oil supply / demand forecasting 26 and crude oil and petroleum products pricing.
27 Q. What work has Arthur D. Little, Inc., recently performed for 28 Boston Edison related to fuel oil price forecasts?
~
2281 327
1 A. Arthur D. Little, Inc. (ADL) ms comnissioned by Boston Edison in 2 July,1977 to prepare a report on the outlook for coal and residual fuel 3 oil prices for Boston Edison. Our final report on this assigment ws 4 subnitted in July,1978. In August, 1978 we prepared written testimony 5 for the hearings in Massachusetts DPU 19494 which ms presented by us 6 in April, 1979. A copy of this written testimony is attached as 7 Exhibit NP-44 (except for the resunes which were part of that testimony) .
8 Since that time Arthur D. Little, Inc. has been cmmiss'.oned by Boston 9 Edison to update our oil price forecasts. This work is in progress 10 at the time of writing but results are not yet available.
11 Q. Have any significant events affecting international oil supply occurred 12 since the preparation of your testinony in DPU 19494, which is incor-13 porated herein, which would influence your views?
~
14 A. In the late fall of 1978 a revolution took place in Iran, one of the 15 major Middle East oil producing countries. Consequent to the revolu-16 tion, the Shah departed from Iran and the Bakhtiar Goverment, appointed 17 by him prior to his departure, fell. A new Islamic regime was established 18 by the Ayatollah Khaneini. The revolution in Iran caused a cessation 19 of oil exports between late Decenber 1978 and early March 1979. Exports 20 are currently reported to be limited by the Government to about 3 million 21 barrels per day, compared to an average export level of the order of 22 5 million barrels per day prior to the revolution. In response to the 23 Iranian crisis, Saudia Arabia at first allowed production to increase 24 in later 1978 to 10.4 million B/d. Subsequently, Saudi production was 25 reduced such that it averaged 9.5 MMB/d in the first quarter of 1979 26 and is currently at a level of 8.5 MMB/d. Thus, it is clear that 27 there have been significant crude oil supply difficulties and rearrange-ments in recent months 28 gj 3
1 Q. How have oil prices evolved since you prepared your earlier 2 testimony? 3 A. OPEC menber states met in Abu Dhabi in Decenber 1978 and decided on 4 a schedule of quarterly price increases for 1979. Under this 5 schedule, the contract price for the Saudi marker crude was to have 6 increased in steps during each quarter reachirg 14.57 for the 4th 7 quarter (an average of 107. over the year assuming level production) . 8 The original schedule was: 9 .Decenber 1978 $12.70/ Bbl 10 1st quarter 1979 13.34 11 2nd quarter 1979 13.84 12 3rd quarter 1979 14.16 13 4th quarter 1979 14.55 14 However, in early February 1979, Saudi Arabia announced a retro-15 active (to January 1,1979) price increase for all barrels sold 16 in excess of the official allowable production of 8.5 million barrels 17 per day. These excess barrels were to be sold at the scheduled 4th 18 quarter price. In mid-Febru_try, certain countries (Libya, Abu Dhabi, 19 Qatar, Iraq, and Kuwait) added surcharges to all volumes which in 20 effect inmediately implenented the prices scheduled for the 4th quarter.
'l At the end of March 1979 OPEC :nonbers met again for a " consultative" 22 meeting in Geneva, at which it ms decided to increase the official 23 marker price of Saudi Arabian Light crude oil such that the scheduled 24 4th quarter price of $14.55/ Bbl would be effective from April 1,1979.
25 It was also decided that menber countries should be free to add those 26 market prenia which they deened justifiable in the light of circumstances. 27 As a result, menber countries have introduced prenia which currently 2281 324
1 range up to $2.50/Bb1 over the previou '.y scheduled 4th quarter 2 Prices. It is noted that all OPEC med r countries have added these 3 price praaia except Saudia Arabia and that We highest prenia have 4 been added by Iran and the African light crude ' oil producers such 5 as Algeria, Nigeria, and Libya. Prania se far added for the other 6 OPEC manbers for their credes have been at lower levls, nestly 7 in the range of $1 to $2/ Bbl. 8 Spot market crude oil prices have risen much nure rapidly and have 9 now reached unprecedented levels. Spot prenia over official prices 10 (already including the " official" prenia mentioned above) are being 11 quoted at $8 to $10/ Bbl and although the volume of real transactions 12 is small, prices were recently reported to be in the range of $24 13 to $28/ Bbl for various crudes. 14 Q. How have the recent develognents you have just described influenced 15 your views on future crude oil prices? 16 A. The events in Iran, the consequent disruptions to wrld oil supplies 17 and the impact of those disruptions on crude oil prices have 18 re-inforced our view that supply /danand imbalances will trigger-off 19 substantial upward revisions in crude oil prices as portrayed in the 20 Delphi forecast referred to in the testimony diich follows. Some 21 crude oil prices have already risen to higher levels in advance of 22 the trend forecast resulting from the Delphi survey; spot crude oil 23 Prices are already at or above the cost of alternative fuels. The 24 events in Iran and the supply constraints introduced by Saudia Arabia 25 have brought into sharp focus the underlying tightness of world crude 26 oil supply and danand and the inherent instability of the supply 27 situation. The inpact of the supply situation on price has again 2281 325
1 been duronstrated. We expect that the price increase, which in 1978 2 we forecast for the mid-1980's, is likely to take place earlier. 3 In fact, this increase may already be, at least partially, underway. 4 Q. What would be the impact on fuel oil prices of the trend changes in 5 the crude oil price forecast you have just described? 6 A. We would expect that crude oil price increases will in general terms 7 flow through to petroleum product prices. Thus, Caribbean fuel oils 8 delivered to southern New England, will reflect the changing crude oil 9 prices. Fuel oil prices actually paid by U.S. consumers will also 10 reflect any price controls or price subsidy measures in force or 11 adopted in the future by the Federal Government. In addition, higher 12 crude oil prices will act to marginally increase both refimng and 13 tanker transportation costs which will therefore also be somewhat 14 higher than those included in the earlier testimony. 2281 '26 O
EXHIBIT NP-44 From: DPU 19494 Exhibit No. BE-II-400 5 Q. What cost elements enter into the price of petroleun 6 products? , 7 A. The chain of costs starts with the acquisition of 8 crude oil and includes the transportation of crude oil 9 to refineries by pipelines and tankers,' the refining 10 of crude oil into the different petroleum products, 11 and the delivery and distribution of these products 12 to the ulti= ate consumer. In addition, governnents 13 (including state and local) may impose taxes and/or The weighting of 14 fees / duties on individual products. 15 these different elements (crude oil, transportation. 16 refining) varies with the source and type of crude 17 processed, the ce=plexity of refinery operations, 18 and the refinery location, Very approximately, when 19 processing a Middle East crude oil, the crude oil 20 itself now accounts for 80%, ocean transportation 87,, 21 and refining 127. of the cost of all the products at the 22 wholesale level (before distribution costs , taxes, or 23 entitlenents benefits), 24 Internationally, crude oil prices are set by the 25 principal producers belonging to the Organizapion of
'. 2281 327
1 Petroleu= Exporting Countries (OPEC). These oroducers 2 set the price of the Ar~abian Light " marker crude oil" 3 with all other crudes being related to the marker crude 4 oil through differentials reflecting quality (sulfur 5 content, specific gravity, etc.) and locat, ion (distance 6 from markets). The actual production cost of the marker 7 crude is a small fraction (less than 5%) of the selling S price and the same is true of most other OPEC crudes 9 as well. Historic production costs are thus irrele-10 vant as a factor in determining international crude 11 oil prices. 12 U.S. crude oil prices are fixed by the U.S. Government 13 under a complex set of regulations designed to stimulate 14 the search for oil by allowing a higher price for "new 15 oil" while preventing excess profits by holding down 16 the price of "old oil". The average refiner acquisi-17 tion cost of domestic crude oil is about $10.50 per 15 barrel or about $4.00 less than the average acquisition 19 cost of foreign crude oil. The composite refiner 20 acquisition cost of all crude oil (domestic and 21 foreign) is about $12.25 per barrel or about $2.25 22 less than foreign oil. The Government has proposed 23 a crude oil equalization tax (COET) designed to 23 equalize the cost of domestic and foreign oil through v 25 a new tax on the price controlled categories of _6_ 2281 328 e
1 domestic oil, to be applied in stages, If enacted, 2 COET would bring average U.S. crude oil prices up to 3 current international levels. In addition, the Govern-4 ment has proposed selective user taxes and restrictions 5 on the use of oil. . 6 The other key elements in the cost build-up -- transpor-7 tation and refining -- to a large extent reflect market g conditions. Currently there is a large surplus of 9 forei 6 n flag. tankers and freight rates,particularly 10 for "very large crude carriers" (VLCC's). of over 150,000 11 tons deadweight,have been driven down to variable costs 12 (i.e., rates which cover bunker fuel and port charges 13 nly). In the Caribbean, the source of cost of New 1; England's fuel oil, there is a large surplus of 15 refining capacity. Refiners in this area recover little 16 more than variable costs (i. e, , refinery fuel and 17 Power, adcitives, etc , , which vary directly with output) . 18 Distribution costs which are important for retail sales yg of gasoline or home heating oil can be ignored for 20 utilities which purchase fuel in cargo cuantities, 0 How did you forecast the price of utility fuels? 21 A. Mu h of the fuel oil used in New England comes from 22 Caribbean refineries which process crude oil imported 23 from the major OPEC countries in the Middle East, Africa, and South America. The Caribbean will continue 2281
- _ 329
1 to be a major source of products for the U.S. East 2 Coast and so we chose this area as the basing point 3 for our economic calculations. Arabian Light was selected 4 as the crude type on the presu=ption (which, in fact, 5 is OPEC policy) that other crudes will be priced in 6 equilibrium with this marker crude oil. Thus, the 7 results would have been the same had we chosen'a e different crude. Further= ore, the results would not 9 differ significantly had we chosen a different 10 refining location (say, an East Coast refinery). 11 Next, wr. forecast the future price evolution of the 12 Arabian Light marker crude and added the proj ected 13 refining and transportation cost elements to arrive 14 at the landed price of products in New England. 15 These prices were then adjusted to reflect the impact s 16 of U.S. regulations (fees, duties, entitlements, COET, 17 etc.). la Q. Please tell in some detail how you forecast the future 19 price of crude oil since it accounts for such a high 20 proportion of the cost of oil products. 21 A. The price of crude oil is to a large extent politically 22 determined: by OPEC deliberations in the case of 23 foreign oil and by Presidential / Congressional action 2; in the case of domestic oil. Thus, there is a high 25 degree of uncertainty in any crude oil price projection. r 2281 330
1 In this context, it is worth noting that the OPEC 1973 2 price hikes were largely unpredicted. Following the 1973 3 price hike, it was widely believed that the cartel would 4 collapse as all previous cartels had. It is now more 5 generally believed that the OPEC cartel will survive 6 but with various schools of thought on how the cartel will 7 behave. An optimistic view of the future has the cartel 8 acting in a responsible manner while a more pessimistic 9 view holds that the cartel will act in an opportunistic 10 manner, taking advantage of current economic circumstances 11 much as it did in the 1973 crisis. 12 To better structure our views on these issues Arthur D. 13 Little made use of Delphi techniques. Basically,a panel 14 of experts, in this case Arthur D. Little staff members
' 15 located throughout the world, were asked to record their 16 views en the future oil price levels and the paths by 17 which these price levels would be reached. In addition, 18 a series of consistency questions related to supply / demand 19 conditions, resource availability, economic growth, cost 20 of oil substitutes, etc. were asked. The oil price 21 projection in constant 1977 dollars emerging from this 22 process is shown in Exhibit No. BE-II-401.
23 Q. What was the consensus view, or reference case, arrived 24 at through this process? 25 A. During the next several years, worldwide oil proddction
. _9_ .
2281 331
1 capacity will substantially exceed demand as a result of 2 the addition of major new supplies (Alaska, North. sea, 3 Mexico, and certain OPEC countries) coupled with a slowdown 4 in demand growth rates due to the gombined effects of 5 conservation, energy substitutes, and economic growth 6 rates lower than historical levels. The surplus producing 7 capacity will be largely concentrated in Middle Eastern 8 OPEC countries and OPEC itself will be under considerable 9 internal strain as revenues of individual member countries 10 are threatened. Under these circumstances, price rises 11 will be modest and linited to inflation plus currency 12 type adjustments. Moving into the mid-1980's, the situation
. 13 begins to change. New non-OPEC supplies will have largely 14 been absorbed and increases in OPEC production will be 15 needed to meet demand, easing the internal pressures within 16 OPEC. During the mid-1980 's there will be a strong like-17 lihood of another significant upward revision of crude 18 price to levels which would be targeted to make high cost 19 hydrocarbon resources such as shale oil, tar sands, or 20 remote natural gas (Arctic and Middle East) cost competitive.
21 The timing of such an increase would depend on economic 22 conditions but would most likely occur when a bottleneck 23 (in production, refining, and/or transportation) develops 24 within the oil supply system. The quantum increase would 25 be followed by a period of consolidation and dige5 tion,
-lo-2281 332
. 1 during which the crude oil prices would not increase in 2 real terms. Later, in the mid-1990's, some respondents 3 felt that another duantum jump would take place as physical 4 oil resource constraints were stropgly perceived. Other 5 respondents felt that by the mid-1990's international
~
6 agreements would have been reached to relate oil prices 7 to the cost of alternatives and that strides would have 8 been made to develop viable oil substitutes. 9 There was, however, considerable uncertainty as evidenced 10 by the confidence limits shown in Exhibit No. SE-II-401. 11 Q. How were the other elements of cost projected? 12 A. The projection of refining cost poses particular problems 13 since the cost must be allocated to individual products. 14 In the simplest type of refinery, crude oil is separated
' 15 into individual fractions by boiling off the lighter fractions 16 in a process called distillation. A portion of the crude 17 oil does not boil off and is called residual fuel oil.
18 This is the product typically used by utilities in steam 19 electric plants. The raw fractions obtained by this primary 20 distillation, however, may not satisfy the product demand 21 patterns or the product quality charactcristics required. 22 For example, the residual fuel oil may have to be treated 23 to remove sulfur and this desulfurization cost causes a 24 price difference between high sulfur and low sulfur fuel 25 oils. In some markets, the yield of residual fuef oil is ( v 2281 333
1 larger than can be absorbed at economic fuel oil prices.
~
2 Refining processes are available (catalytic cracking, 3 hydrocracking, etc.) to convert fuel oil into gasoline 4 and No. 2 fuel oil. The cost of these conversion processes 5 is reflected in the price differential between fuel oil 6 and these lighter products. To further ccmplicate matters, 7 individual crude oils vary widely in their properties 8 ranging from crude oils with a very high natural proportion 9 of residual fuel oil (heavy crudes) to those with a low 10 proportion (light crudes) and ranging from crude oils with 11 a high sulfur content to crudes with very little sulfur. 12 Refiners continually balance crude oils, processing, and markets to achieve optimal results and.this complex
].3 14 interaction is reflected in individual product prices. ' 15 At the present time in the Caribbean there is both a 16 surplus of distillation capacity and a surplus of fuel 17 oil desulfurization capacity. This situation causes a 18 low allocation of refining cost to residual fuel oil on 19 the one hand and price differentials between high sulfur 20 and low sulfur fuel oils below the full cost of desulfuriza-21 tion on the other hand. At the same time, there is a 22 shortage of processing capacity to convert fuel oil to 23 light products (gasoline and No. 2 fuel oil) and prices 24 for these products are higher than the full cost of 25 conversion processing. Our forecast of the refinfng element
( ~_ 2281 334
1 in product prices reflects a gradual trend to full cost 2 recovery, including a return on investment, by the mid-1980's. 3 Given that caribbean refiners currently are not even recovering 4 fixed cash costs (such as labor, 1,ocal taxes, etc.), the 5 shift to recovering full costs accounts for a relatively 6 high rate of increase in the refining element in product 7 prices. 8 Foreign flag tankers are in much the same position as 9 offshore refineries. The surplus tanker capacity has 10 driven freight rates below cash costs for large tankers 11 and down to about cash costs (bunker fuel, port charges, 12 maintenance, insurance, and labor) for smaller product 13 tankers. As in the case of refineries we expect this 14 to change gradually as tanker supply and demand come
~
15 into balance such that freight rates will reflect full 16 costs including a return on investment by the late 17 1980's. Both the tanker cost forecast and the refinery 18 cost forecast reflect projected crude price increases 19 which influence bunker costs in the case of tankers 20 and refinery fuel in the case of refining. 21 current U. S. regulations reduce the cost of fuel oil 22 below import parity by granting importers an " entitlement 23 credit" of about G0c per barrel (30% of the entitlement 24 credit for imported crude oil). In addition, an import 25 fee of up to 630 per barrel is payable on certain# import w 2281 335
. 1 volumes. This whole system is under review. In preparing 2 the price projections, it has been assumed that the present 3 system will be phased out along the lines of the Carter 4 Administration's proposal such that only a fee of 420 per 5 barrel will apply to imported product as a protection 6 for U. S. refiners. It has been further assumed thht the 7 proposed user tax will not apply to Boston Edison consumption.
8 Q. What are the results of your analysis? 9 A. Applying the procedures just outlined, we have obtained 10 the following results, expressed in 1977 dollars per 11 million stu. 12 TABLE 1
~
l3 DELIVERED FUEL OIL PRICE FORECAST
- 14 Reference Case ~
15 (1977 5 per Million Btu) 16 1978 1980 1985 1990 1995 2000 17 No. 2 Fuel Oil 2.69 2.66 3.43 4.49 5.02 5.42 18 0.5% Sulfur Resid 2.14 2.04 3.01 4.04 4.56 4.95 19 1.0% Sulfur Resid 2.06 1.96 2.'89 3.88 4.37 4.75 20 2.2% Sulfur Resid 1.89 1.80 2.65 3.53 3.97 4.33 21 2.7% Sulfur Resid 1.83 1. 7.3 2.55 3.41 3.83 4.18 22 Tables 2 and 3 show the +70% and -70% confidence limit cases 23 for the same forecast. 24 25 2281 336
1 TABLE 2 2 DELIVERED FUEL OIL PRICE FORECAST . 3 PLUS 70% CASE 4 (1977 S per Million Btu) 5 1978 198e 1990 2000 6 No. 2 Fuel Oil 2.69 2.99 5.52 6.78 7 0.5% sulfur Resid 2.14 2.28 5.04 6.26 8 1.0% sulfur Resid 2.06 2.20 4.85 6.01 9 2.2% sulfur Resid 1.89 2.01 4.44 5.52 10 2.7% sulfur Resid 1.83 1.95 4.29 5.33 11 12 13 TABLE 3 - 14 DELIVERID FUEL OIL PRICE FORECAST 15 MINUS 70% CASE 16 (1977 5 per Million Btu) 17 1978 1980 1990 2000 18 No. 2 Fuel Oil 2.69 2.39 3.59 4.26 19 0.5% sulfur Resid 2.14 1.80 3.17 3.81 20 1.0% Sulfur Resid 2.06 1.73 3.02 3.64 21 2.2% sulfur Resid 1.89 1.59 2.74 3.29 22 2.7% sulfur Resid 1.83 1.52 2.63 3.16 23 - 24 25 2281 337 0
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