ML19225B228
| ML19225B228 | |
| Person / Time | |
|---|---|
| Site: | 05000471 |
| Issue date: | 06/29/1979 |
| From: | Weiner B BOSTON EDISON CO. |
| To: | |
| Shared Package | |
| ML19225B229 | List: |
| References | |
| NUDOCS 7907240317 | |
| Download: ML19225B228 (322) | |
Text
s .
UNITED STATES OF AMERICA 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 )
)
)
- APPLICANTS' REVISED SUPPLEEITAL TESTIMONY s
ON NEED FOR PILGRIM 2 w
"* +
s .
E 408 291 7 9 0724 0 'W /
t t
C
. , ~
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, Generation Planning Engineer, Bos'on Edison Company Donald V. Bourcier, Chief of Load Forecasting, New England Power Planning Arthur W. Barstow, Manager of Generation Planning, New England Power Planning PANEL 2 PANELISTS: F. Cort Turner, Vice President , a chur D. Little, 1,c.
Nigel Godley, Manager-Energy Economics Section, Arthur D. Little, Inc.
DavLd Hanna, Energy Economics Section, Arthur D.
Lit:le, Inc.
- Intervenors Comraonwealth of Massachusetts Contentien 6, Cleeton Contention H, Ford Contention M 408 292
e e
e PANEL 1
.0u c/-
1 Q. Mr. Weiner, please state your name and business address.
2 A. Benjamin H. Weiner, Boston Edison Company, 800 Boylston 3 Street, Boston, Nbssachusetts.
4 Q. What is your present position?
5 A. I am Vice President - 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 Prerident's staff 9 and, in 1969, I was promoted to the position of Assistant 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 included 15 the negotiation and preparation of bulk power purchase and 16 sale agreements, including s, s tem and unit sale contracts 17 and icint ownership arrangements covering various types of 18 generation - hydroelectric, fossi". 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 responsib ility for all of Ediscn's 22 bulk power supply purchases and sales and rates for 23 wholesale and resale sales. Additionally, I a= Edison's 408 294
1 representative on the New England Power T ool (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 NEPOOL
- 5 including the operation of the New England Ecuer Exchange 6 (NEPEXS and the New England Planning Staff (NEPLAN), as 7 well as new generation scheduled by other New England 8 companies and other ma:ters relating to bulk power supply 9 in New England.
10 I am a member of the Ccmpany'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 programs, except for 15 nuclear, report te 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 frem the University of Massachusetts in 1953.
20 : have completed the Harvard Business School Program for 21 Management Development. I am a Registered Professional 22 Engineer in the Cecmonuealth of Massachusetts.
23 Q. Mr. Weiner, what is the purpose of your testimony?
k00 2
1 A. My testimony is to demonstrate that 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 oroj ected by NEP00L, there 6 are beaefits to installing Pilgrim 2 in 12/85 as scheduled.
7 These benefits include cost savings to New England electricity 8 consumers, reduction in dependency on an expensive and 9 potentially unreliable supply of oil, and the further-10 ance of national and regional energy policies and goals.
11 Q. Mr. Legrow, please s tate 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. What is your present position and responsibilities with 16 Boston Edison Company?
17 A. I am a Generation Planning Engineer in Boston Edison's
~
18 Engineering, Planning and Research Department. M" res-19 pousibilities include the analysis of any of tba Company's 20 genera tion costs , both short and long term, aad the 21 conduct of long range generation planning studies.
22 Q. Please describe your educational background and experience.
403 206
t 1 A. I received a Bachelor of Science degree in Electrical 2 Engineering from Northeastern 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 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 Springfield, Massachusetts.
18 Q. What 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?
408 297
1 A. From 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, 4 Connecticut, with a Bachelor of Science degree in 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 Nbrketing Research 14 Analyst. At Remington, I developed sales forecasting models 15 and conducted consumer market research studies. Since 16 October 1972, I have worked for New England Power Planning 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 Statistical Association. I am the current chairman 21 of the Load Forecasting Task Force of the NEP00L Planning 22 Cc=mittee.
23 Q. Have you written any articles or books in the field of 24 economic analysis?
408 298
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 NEPOOL load forecast. The forecast is 10 presented and explained in three documents:
11 1) NEPOOL Forecast for New England, 1979-1989, 12 NEPLAN, March 1, 1979.
13 2) Report of the NEPOOL Load Forecasting Task Force 14 on the NEPOOL M'o del-Based Forecast of New England 15 Electric Energy and Peak Load, 1979-1989, NEPLAN, 16 March 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'.
$ 9 ()
1 Q. What is your educational background?
2 A. I received a Bachelor of Science degree in Electrical 3 Engineering from the University of Massachusetts in 1951 4 and a Nbsters degree in Business Administration from 5 American International College in 1964. I have also taken 6 several courses including Pawer System cugineering from 7 the General Electric Company while an employee there. I 8 am a Registered Professional Engineer in the State of Ne i 9 York and a member of the Pouer System Engineering Committae, lo System Planning Subcommittee and several watking groups and 11 task forces of the Power Engineering rociety 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 en 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 Lars a 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 electricci planning department 23 of Western Massachusetts Electric Company in Springfield, 24 Massachusetts. I wo rked in distribution and transmission 408 300
1 planning until 1960. In 1960, the Connecticut utilities 2 and Western Mass. 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 Mass Electric Company 7 (WNECO) representative in that endeavor. In 1961, while 8 serving 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 WNECO with Westinghouse, 14 I was transferred back. to Western Mass . Electric Company 15 aad 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. At the same time, I was made Interconnection 19 Planning Engineer for Western Mass . Electric Con oany.
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 408 301
_9_
1 level. I have co-authored IEEE papers and a number of 2 New England Generation planning reports on the subj ect of 3 generation 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 (althe capacity 6 aspects of the most recent NEPOOL Load and Capacity Report, 7 (b)NEP00L's generation reliability criterion as it is 8 reflected in the determination of NEP00L's reauired 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 proj ections?
13 A. The results of the most recent NEPOOL ioad forecast 14 are presented in Exhibit NP-33. The NEPOOL foracast 15 projects a 3.8% compound annual growth rate in peak load 16 from 1979/80-1989/90. Exhibit NP-34 presents the April 1979 17 schedule for major generating capacity additions planned 18 for the next decade. Exhibit NP-35 presents the total 19 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, NP-35 shows that by 1984/85 the New 24 England reserve margin will be at or below the minM 302 25 desired level. If Pilgrim 2 is delayed to 12/88, reserve
1 margins will be inade cate and reliability impaired through 1987, 2 Exhibit NP-36 grneni: ally 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 caracity 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 sud environmental considerations. The 9 NEPCO units have been postponed and will not be built on 10 the schedule indicated in Exhibits NP 36. 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 NEPOOL Management Committee establishes a generation 17 reliability criterion. Given this criterion, as well as 18 a knculedge 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?
408 303
1 A. NEP00L 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 di: connecting 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 accually 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. Similarly, 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 cf 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-li 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 NEPCOL Executive Committee decided that this was 17 the reliability criterion to whic the system should be 18 designed.
19 Q. Having established the reliability criterion, would you 20 please describe the procedure used to determine the NEF00L 21 capacity requirements?
22 A. Required reserve margins are based on calculations of the 23 probability of occurrence of insufficient generating 408 ::n c sva
1 capacity to meet the anticipated loads. These calculations 2 are performed by NEPLAN for the pool. Once the reliability 3 calculations have been completed and the results reviewed 4 by the NEPOOL Planning and Ixecutive Committecs, the 5 NEP00L Objsetive Capability ia established. The Objective 6 Capability ir the amount of capacity (loco plus required 7 reserves) deemed necessary by the Execu fe Committee to 8 meet the Pool's reliability criterion.
9 Q. Has the Executive Cour .t*.ee 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 preliminary 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 pericd 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 frca 408 306
1 year to year depending on unit cammitment 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 economie generation mix, such ..s is the present 11 case for New England, capacity installed to improve the 12 mix which results in more than the minimum required to 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 amouets 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 13.57. of the 22 oil used in the 1.0 year / day LOLP case.
23 In addition, the February 1978 NEPOOL Generation Task Force 24 and t ta NEFLAN Staff report " Planning for Load Growth 408 507
1 Uncertainty (Recognizing Unit Lead Times)" demov 'trated 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 rate than that on which the expansion 6 was based. In addition, there is an econ >mic benefit 7 associated with planning to a high load growth rate and 8 actually experiencing a lower growth rate. Those savings 9 are attriLutable to the early installation of nuclear 10 capacity which ena'a les 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 12 considerable oil savings when compared to the generation 14 expansion pattern designed just to meet the actual load 15 growth rate.
16 Q. Mr. Weiner, what are the econcmies 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 darc ror Pilgrim 2 favor installation at the 20 earliest possible time independent of reliability require-21 men ts . For example, for a 3 year delay, assuming that all 22 other planned units are brought in on schedule, 12/85 23 installation results in net present worth savings of 24 S1387 million (in 1986 dollars) to New England consumers 25 over the life of the project. In spite of higher costs 408 308
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 1987, only 4 one year after installation.
5 In addition to .the loss of savings, the delay of Pilgrbn 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 contradic.cs actional energy policy 11 and the regional interest.
12 Q. Rave you evaluated the setsitivity of this econcmic analysis 13 to different peak-load greath rates?
14 A. At the request of the NRC Staff we analyzed the impact of 15 a 12/85 installation da te versus 12/88 assuming a 3.4%
16 peak load growth. The 3.4% growth case yielded present 17 worth savings of S1087 million (in 1986 dollars) over the life 18 of the proj ect. The breakeven year was 1989 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 3.0% growth case 21 yielded present worth savings of $1051 million fin 1986 22 dollars) over the life of t he project. The breakeven year 23 was also 1989. We have no t explicitly analyzed the impac t 24 of a 12/85 installation date versus a 12/88 installation 25 date assuming a peak load growth rate higher than 3.8%.
408 309
1 It is not unreasonable to expect that a strong economic 2 recotery in New England might lead to load growth that 3 would exceed our current projections. At a higher load 4 growth rate the present worth savings accruing to the 5 ' arlier 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 fram 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 su=med, 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 408 310
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 NF-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" most 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 13 projections of property taxes and nuclear fuel carrying 14 charges for the 28-yest book life of the unit for each 15 in-service date, and t1 e 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 1986-199;.
4DS 5\\
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-ser. ice dates of all 4 other NEP00L 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; from 1989 9 co 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 1.7 point?
18 A. Recent international events have had dramatic repercussions 19 on the world oil markets. Consequently supplies of imported 20 oil, upon wh. New England must depend, cannot be 21 regarded as secure. The lesson of the 1973-74 arab oil 22 embargo was ceinforced dramatical"..y this winter by the 408 3 '. 2
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 o rer 40%, and 4 the source of 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 approximately $1 per barrel to about $15 currently, 10 and the continuing ability of OPEC to Lapore 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. Oil 5_rned in May by Boston Edison 22 had an average price of $17.56/ barrel, S5/ barrel or 40%
23 higher than the 1978 average cost of $12.60/ barrel. In ,
408 313
1 addition, our principal suppliers, Asiatic Petroleum Ccapany
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2 and Texaco have formally put us on notice that fuel 3 shortages are possible 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 our oil dependency 11 over the longer term. Bringing Pilgrim 2 in service on 12 the earliest possible schedule will make a significant 13 centribution to that goal.
14 Q. You also mentioned consistency with N'a tional energy policy.
15 What specific polici2s were you referring to?
16 A. When President Carter announced the first ccmprehensive 17 National Energy Plan in 1977, he articulated Administration 18 policy that dependence on fossil fuel imports be reduced 19 through a large-scale conservation effort that 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.
408 3l4
1 In response, Congress passed a series of Acts [ referred 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 (FUA).
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 interstate commerce require the establishment of a program for the expanded use, 8 censistent with applicable environmental require-ments, of coal and other alternate fuels as primary 9 energy sources for existing and new electric powar-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 maj or fuel-burning ins talla-tions, consistent with applicable environmental require-12 ments, as primary energy sources in lieu of natural gas or petroleum.
13 In the definitione, 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 rescurcea of the United States to the extent such reduction 17 and use further the goal of national energy self-suffiency and otherwise are in the besc 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, for 20 which there are no feasible alternative fuels or raw material substitutes ;
403 315
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 primary 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 fature generations; (7) to encourage the modernization or replacement 5 of existing and new electric powerplante 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 Pilgrim 2 on-line at the earliest possible date 10 (i.e., December, 1985) would be consistent with the intent 11 and purposes of EUA, 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) districts , the 16 most vulnerable to interruption of imported oil supply is 17 District I, which is comprised of all of New Englanu, 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 408 316
1 15 times the total amount of Laported petroleum products 2 of the next largest Laporting PAD district. When 3 considering only residual oil, PAD District I imports 4 were almost thirty times the amount Laported by the next 5 highest district.(1) Because District I receives over 6 79% of its rasidual oil from foreign sources, it is 7 critical that this region's dependency on residual fuel 8 imports be reduced, if the goals of FUA/NEA are to be 9 met.
10 As discussed, these goals are to reduce our nation's 11 dependency on foreign petroleum imports for non-essertia'l 12 uses, while continuing to ensure an adequate reliability 13 of service for electric generation. If Pilgrim 2 is 14 delayed, not only are we needlessly consuming millions 15 of additions 1 barrels of oil, at higher and higher prices, 16 but we are also exposing ourselves to extreme political, 17 econcmic and social risks. Bringing PilgrLa 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.
ado 317
tam HCIno ImfrAST SIMwrt 1979-1989 1979-89 Q vg o ssi hwunal Actual Forecast Grcuth Rate 1977 1976 19~79 1M0 1981 1%2- TM) 19BFIM5 1M6 1987 1988 1%f li)
Wiracident l\iak las! (m)
Ibxxuth! . Winter (Ibc./Jan.) 14846 15100P
, Stamer 14234 14458 Heather (a)
Cor rectal . Winter (tbc./Jan.) 15363 15500P 16595 17266 18036 18822 19755 20668 21502 22267 22989 235 % 24120 3.81
.. faamer 13712 14954 15569 16108 16714 17409 18113 18958 19784 20552 212/5 21933 22495 3.75 Dwsrgy Sales to Ultimate matomra (G41)
. 'Ibtal 72751 n/a C4276 87590 91249 35241 99318 104148 108843 113217 117285 120980 124144 3.95
. Ibsitkntial 28222 n/a 31631 32248 33260 34543 35721 37113 36150 39577 40572 41371 42007 2.88
. Irmlustrial Wa Wa 22786 24143 25446 26397 27433 28670 29341 31035 32120 33220 34123 4.12
. Gamezclal n/a Wa 20655 30006 31341 33072 34904 37066 39217 41234 43191 44062 46569 4.98
. Hism ilarwxus n/a n/a 1205 1194 1203 1228 1259 1299 1336 1371 1403 1427 1445 1.84 thst tresTJy for las! (Gei) (b) 79781 82800P 91861 95473 99462 103812 103256 113521 118639 123407 127840 131860 135317 3.95 hunul Ins! Factor (t) 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 Dxmunitic/Dtmojragide
. I'tpalaticsi (000'u) 12238 12256P 12337 12404 12491 12569 12654 12745 12819 12937 13029 13117 13206 0.68
. Ibisedmaids (000's) 4141 Wa 4301 4379 4467 4552 4637 4723 4t,10 4892 4972 5050 5129 1.78
. thployuent (000's) (c) -
5377 n/a 5692 5844 5923 5988 6066 6150 6L9 6300 6361 6423 G475 1.30
. Huntacturir.j (000's) n/a n/a 1469 1499 1513 1514 1525 1539 1543 1559 1563 1569 1565 0.64
. tannarvif acturisuj (000's) n/a n/a 4202 4323 4389 4453 4520 4595 466 L 4720 4777 4333 4889 1.53
. Instsiploymtsit Rate (t) 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 -
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. tet Higration (000's) n/a n/a 27 41 31 35 36 37 38 32 29 30 30 -
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. Eurs(sul 1:wxsie (mil 569) 53195 n/a 56514 58947 61058 63010 65109 67299 69497 71754 73961 76196 78364 3.32 y H
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EXHIBIT NP-35 flew ENGLUD SYSTEM CAPABILITIES AND ESTIMATED PEAK LOADS 1979-1909
% RESERVE AritR MAINTENANCE WITH
% RESERVE PILGRIM 2 POWER TOTAL PEAK AFTER INSTALIrn YEAR CAPABILITY LOAD MAINTENAilCE IN 12/88 9
1979/80 21,980 16,595 30.0 -
1980/81 21,982 17,266 26.8 -
1981/82 22,301 18,036 20.0 -
1982/83 22,626 18,822 19.5 -
1983/84 23,773 19,755 20.3 -
1984/85 23,768 20,668 15.0 -
1985/86 25,869 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 22.5 -
408 320
NEW FNGl.AflD LOADS AND CAPACITIES AS OF APRIL 1979 HEFCo 2 3ti _
! O S HILLS 10flE 3 SFTIH00K 2 Y 30 - Pi l (IN 2 y p SEABROOK 1 /
,- e STONYDR00K CT V / LOAD PLtlS 23" 26 -
y . STONYBROOK CC 3,
RESERVE I y -
CAPACITY -
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e -
- W ITER PEAK LOAD a '
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Exhibit NP-37 Revised 6/29/79 3.8% GROWTH CASE SAVINGS ASSOCIATED WITH INSTALLING PILCRIM 2 IN 1985 VS. 1988
($000)
Acc. P.W. Savings Year Capital Savings Fuel Savings Total Savings At 10.83%
1986 (408,754) 403,363 (5,391) (5,391 1987 (397,061) 492,479 95,418 80,702 1988 (381,362) 501,45d 120,096 178,474 1989 176,428 81,297 257,725 367,789 1990 179,332 48,342 227,674 518,686 1991 172,870 60,419 233,289 '658,198 1992 168,609 11,354 179,963 755,302 1993 161,256 43,742 204,998 855,106 1990 154,631 -
154,631 923,032 1995 149,317 -
149,117 982,214 1996 145,196 -
145,19o 1,034,139 1997 143,046 -
143,046 1,080,797 1998 140,720 -
140,720 1,121,267 1999 138,002 -
138,002 1,157,520 2000 135,192 -
125,192 1,189,575 2001 133,399 -
133,399 1,218,09) 2002 130,678 -
130,678 1,243,312 2003 123,591 -
123,591 1,264,830 2004 116,972 -
116,972 1,283,207 2005 108,938 -
108,938 1,298,649 2006 107,159 -
107,159 1,312,353 2007 103,829 -
103,829 1,324,335 2008 100,826 -
100,826 1,334,833 2009 97,163 -
97,163 1,343,962 2010 93,733 -
93,733 1,351,907 2011 90,500 -
90,5CO 1,358,829 2012 86,505 - 86,505 1,364,799 2013 82,638 -
82,638 1,369,944 2014 126,981 -
126,981 1,377,073 2015 109,209 -
109,203 1,382,614 2016 92,377 -
92,377 1,386,839 0
Exhibit NP- 38 Revised 6/21/79 3.8% GROWTH CASE FUEL SAVINGS ASSOCIATED WITH INSTALLING PILGRIM 2 IN 1985 VS. 1988 Year 12/85 Pilg. 2 MWHR 12/88 Pilg. 2 MWER MWHR Bbl. Oil Equiv.*
1986 5,943,521 -
5,943,521 9,905,868 1987 5,940,818 -
5,940,818 9,901,363 1988 6,263,348 -
6,263,348 10,438,913 1989 6,749,019 5,942,067 806,952 1,3'.4,920 1990 f,738,399 5,935,820 802,579 1,337,632 1991 7,047,508 6,2',0,489 807,019 1,345,032 1992 7,068,628 6,771,058 297,570 495,950 1993 7,047,412 6,748,850 298,562 497,603 Total Oil Savings 35,267,281
- Assumes 10,000 Btu /kWh, 6 MM3tu/ bbl.
?
e 403 323
Exhibit NP-39 Revised 6/29/79 3.42 GROWTH CASE SAVINGS ASSOCIATED WITH INSTALLING PILCRIM 2 IN 1985 VS. '988 (S000)
Acc. P.W. Savings Year Capital Savings Fuel Savings Totcl Savings At 10.832 1986 (408,754) 328,891 (79,863) (79,863) 1987 (397,061) 363,171 (33,890) (110,441) 1988 (381,362) 390,758 9,396 (102,792) 1989 176,428 65,029 241,457 74,573 1990 179,332 51,597 230,929 227,628 1991 172,870 55,881 228,751 364,426 1992 168,609 13,755 182,364 462,826 1993 161,256 28,616 189,872 555,265 1994 154,631 - 154,631 623,191 1995 149,317 - 149,317 682,373 1996 145,196 -
145,196 734,298 1997 143,046 -
143,046 780,456 1998 140,720 - 140,720 821,427 1999 138,002 -
138,002 857,680 2000 135,192 -
135,192 889,724 2001 133,399 - 133,399 918,254 2002 130,678 -
130,678 943,471 2003 123,591 -
123,591 964,990 2004 116,972 -
116,972 983,366 2005 108,938 -
108,938 998,808 2006 107,159 -
107,159 1,012,512 2007 l'1,829 - 103,829 1,024,494 2008 100,826 - 100,826 1,034,992 2009 97,163 -
97,163 1,044,121 2010 93,733 -
93,733 1.052,067 2011 90,J00 - 90,500 1,058,988 2012 86,505 -
86,505 1,064,958 2013 82,638 - 82,638 1,070,104 2014 126,981 - 126,981 1,077,237 2015 109,209 -
109,209 1,082,773 2016 92,377 -
92,377 1,086,998 403 32li
Exhibit NP-40 Revised 6/29/79 3.4% GROWTH CASE FUEL SAVINGS ASSOCTATED WITH INSTALLING PILGRIM 2 IN 1985 VS. 1988 Year 12/85 Pilg. 2 MWHR 12/88 Pilg, 2 MWHR MWER _ Bbl. Oil Eauiv.*
1986 5,941,742 -
5,941,742 9,902,903 1987 5,941,815 - 5,941,815 9,903,025 1988 6,258,429 - 6,258,429 10,430,715 1989 6,747,160 5,941,510 805,650 1,342,750 1990 6,743,522 5,935,851 807,671 1,346,118 1991 7,043,027 6,236,696 806,331 1,343,885 1992 7,067,911 6,768,166 299,745 499,575 1993 7,047,027 6,746,673 300,354 500,590 Total 011 Savings 35,269,561
- Assumes 10,000 Beu/kWh, 6 MMBtu/ bbl.
nn -r
~J
Exhibit NP-41 Revised 6/29/79 3.02 GROWTH CASE SAVINGS ASSOCIATED WITH INSTALLING, PILGRIM 2 IN 1935 VS. 198E
($000)
Acc. P.W. Savings Year Capital Savings Fuel Savings Total Savings At 10.83%
1986 (408,754) 317,323 (91,431) (91,431) 1987 (397,061) 345,210 (51,851) (138,215) 1988 (381,362) 380,114 (1,248) (139,231) 1989 176,428 59,224 235,652 33,869 1990 179,332 58,974 238,306 191,814 1.31 172,870 47,749 220,619 323,748 1992 168,609 21,494 190,103 426,324 1993 161,256 30,116 191,372 519,494 199'+ 154,631 -
154,631 587,420 1995 149,317 - 149,317 646,602 1996 145,196 - 145,196 698,527 1997 143,046 - 143,046 744,685 1998 140,720 - 140,720 785,655 1999 138,002 -
_38,002 821,909 2000 135,192 - 135,192 853,953 2001 133,399 -
133,399 882,483 2002 130,678 -
130,678 907,700 2003 123,591 - 123,591 929,219 2004 116,972 - 116,972 947,595 2005 108,933 - 108,938 963,037 2006 107,159 -
107.159 976,741 2007 103,829 - 103,d29 988,723 2008 100,826 - 100,826 999,221 2009 97,163 - 97,163 1,008,330 2010 93,733 - 93,733 1,016,295 2011 90,500 -
90,500 1,023,217 2012 86,505 - 86,505 1,023,187 2013 82,638 -
82,638 1,034,332 2014 126,981 - 126,981 1,041,466 2015 109,209 - 109,209 1,047,002 2016 92,377 - 92,377 1,051,227 408 326
Exhibit NP-42 Revised 6/29/ /9 3.0% GRCWTH CASE FUEL SAVINGS ASSOCIATED WITH INSTALLIhG PILGRIM 2 IN 1985 VS.1988 Year 12/85 Pilg. 2 MWHR 12/88 Pilg. 2 MWHR MWHR Bbl. Oil Equiv.*
1986 5,941,743 - 5,941,743 9,902,905 1987 5,939,321 - 5,939,321 9,898,868 1988 6,257,807 -
6,257,807 10,429,678 1989 6,745,243 5,938,763 806,480 1,344,133 1990 6,743,888 5,935,851 808,037 1,346,728 1991 7,041,351 6,235,473 805,878 1,347,130 1992 7,065,725 6,765,560 300,165 500,275 1993 7,042,522 6,743,376 2co . l .6 498,577 Total Oil Savings 35,264,294
- Assumes 10,000 Btu /kWh, 6 MMBtu/ bbl.
408 327
Exhibit NP-43 Revised 6/29/79 MAJOR ASSUMPTIONS EMPLOYED IN ECONOMIC ANALYSIS OF DELAYED INSTALLATION General rate of inflation: 6%/ year Bosten Edison cost of mor.ey: 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 assu=ptions with the July 1978 A.D. Little report.
Sample current dollar fuel prices: (S/MMBtu) 1986 1988 1990 1992 1994 No. 6 oil, 1 S 6.659 7.974 9.548 11.169 13.064 No. 6 oil, 2.2% 6.126 7.322 8.751 10.234 11.968 No. 2 oil 7.597 9.074 10.839 12.649 14.761 Coal - - - - -
Pilgrim 2, 12/85 C.O. .779 .962 1.152 1.374 1.615 Pilgrim 2, 12/88 C.O. - -
1.057 1.291 1,606 Load Model: 59% Icad 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 Oa!c Ridge Model;
- 3. 1978/79 weather-adjusted winter peak, extrapolated at 3.0%/ year.
Pilgrim 2 capital coscs: S1,895 million in 1985, S2.550 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 Ef fective income eux rate: 49.517.
Pilgrim 2 property tax assu=ptions: Plymouth annual budget growth: 10%
Income tax credit: 10% for all years 408 328
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%
Sch year: 67%
6th and following years: 70%
Future capacity additions to meet load plus 23% required reserves through 1993:
nuclear, similar to Filgrim 2. All planned units listed in the April 1, 1979 New England Load and Capacity Report installed on the schedules indicated therein.
408 329
pA8EL 400 33rj
1 Q. Mr. Turner, will you please state your na=e 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 your educational background?
6 A. 1 received undergraduate 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, Inc.
9 A. I have been employed by Arthur D. Little, Inc. since 1952. My current 10 position is 71ce 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 chemica' companies), oil co=panies (major 16 and independent), governments of producing and consuming countries, 17 the U.S. Environmental Protection Agency, etc. Thia 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 progra= ming refinery 21 model to test the i= pact of change on the cost of producing individual 22 erudes.
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?
/ O 771 4 U sJl
1 A. I hold a dipicma in Business Administration from the Portsmouth 2 College of Technology and I attended a special course dealing with 3 decicion-making in the =arine industries at the Massachusetts 4 Institute of Technology.
5 Q. Please describe your experience with Arthur D. Little, Irc.
6 A. I have been e= ployed by Arthur D. Little, Inc. since 1969. I 7 am currently manager of the Company's Energy Econcmics 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 of the hydrocarbon 11 industry including exploration production, refining, and marketing 12 activities.
13 Q. Mr. Hanna, will you please state your nane and place of residence?
14 A. My _ame is David Hanna, and I reside in Arlingt-n, Massachusetts.
15 Q. By whom are you employed?
16 A. I am employed by Arthur E. Little, Inc., Cambridge, Massachusetts.
17 Q. What is your educational background?
13 A. I received an undergraduate degree in physical sciences from 19 0xford University and a graduate degree in business management frca 20 the London Business School.
21 Q. Plaase describe your experience with Arthur D. Little, Inc.
22 A. I have been employed by Arthur D. Little, Inc., etnce 1972. I 23 am a member of the Energy Econcaics Section in Cumbric ge and specialize 24 in oil and gas consulting for U.S. and international c 'ients.
. My 25 work has included strategic planning, oil supply / demand forecastieg 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?
d}
. 1 Q. What work has Arthur D. Little, Inc. recently perfonned for Boston 2 Edison related to fuel oil price forecasts?
3 A. Arthur D. Little, Inc. ( AD.) was commissioned by Boston Edison in July, 4 1977 to prepare a report on the outlook for coal and residual fuel 5 oil prices for Boston Edison. Our final report on this assignment 6 was submitted in July,1978. In August,1978 we prepared written 7 testimony for the hearings in Massachusetts DPU 19494 which was pre-8 sented by us in April,1979. In May,1979 Boston Edison comissioned 9 Arthur D. Little, Inc., to update our oil price forecasts, the results of which 10 are incorporated in this testimony. 11 Q. What cost elements enter into the price of petroleum products? 12 A. The chain of costs starts wita the acquisition of crude oil and includes 13 the transportation of crude oil to refineries by pipelines and tankers, 14 the refining of crude oil into the different petroleum products, and 15 the delivery and distribution of these products to the ultimate consumer. 16 In addition, governments (including state and local) may impose taxes 17 and/or fees / duties 'on individual products. The weighting of these .,, 18 different elements (crude oil, transportation, refining) varies with the 19 source and type of crude processed, the complexity of refining operations, 20 and the refinery location. Very approximately, when processing a 21 Middle East crude oil, the crude oil itself now accounts for abcut 85%, ocean 22 transportation for 5%, and refining for 10% of the cost of all the products at 23 the wholesale level (before distribution costs, taxes, or entitlements 24 benefi ts ) . 2 c. Internationally, crude oil prices are set by the principal producers 26 belonging to the Organization of Petroleu'a Exporting Countries (OPEC). 27 Generally, in the past, these producers set the price of the Arabian 28 Light " marker crude oil" with all other crudes being related to the 29 marker crude oil through differentials reflecting quality (sulfur content, 7-
1 specific gravity, etc.) and location (distance from markets). More 2 recently, since the Iranian crisis, many producers have added surcharges 3 related to market conditions, over and above their parity price with 4 Arabian L~ it. The actual production cost of the marker crude is a 5 small fraction (less than 5%) of the selling price and the same is true 6 of most other OPEC crudes as well. Historic production costs are thus 7 irrelevant as a factor in determining international crude oil prices. 8 U.S. crude oil prices are fixed by the U.S. Government under a complex 9 set of regulations designed to stimulate the search for oil by allowing 10 a higher price for "new oil" while preventing excess profits by holding 11 down the price of "old oil". The average refiner acquisition cost of 12 domestic crude oil was $12.06 per barrel in March,1979 or about 13 55.50 per barrel less than the average acquisition cost of foreign 14 crude oil The composite refiner acquisition cost of all crude oil 15 (domestic and foreign) was $14.52 per barrel or about $3.00 less than 16 foreign oil. The Carter Administration has now implemented a phased 17 program of ciade oil price deregulation and has proposed a windfill profits 18 tax which has yet to be approved by Conpress. Under the Carter progivm 19 U.S. domestic crude oil prices will reach international parity le als 20 in fall 1981. 21 The other key elements in the cost build-up-transportation and refining-22 to a large extern. reflect market conditions. Currently there is a large 23 sarplus of foreign flag tankers and freight rates, (particularly for 24 "very large crude carriers" (VLCC's) of over 150,000 tons deadweight) 25 have been driven down towards variable costs (i .e. , rates whid cover 26 bunker fuel and part charges only). In the Caribbean, the source of 27 most of New England's fuel oil, there is a large surplus of refining 28 capacity. In recent years, refiners in is area have generally recovered 408 334
1 little more than variable costs (i.e., refinery fuel and power, 2 additives, etc. , which vary directly with output). Distribution 3 costs which are important for retail sales of gasoline or home 4 heating oil can be ignored for utilities which r.urchase fuel oil 5 in cargo quantities. 6 Q. How did you forecast the price of utility fuels? 7 A. Much of the fuel oil used in New England comes from Caribbean g .efineries which process crude oil imported from the major OPEC 9 countries in the Middle East, Africa, and South America. The Caribbean 10 will continue to be a major source of products for the U.S. East Coast 11 and so we chose this area as the basing point for our economic cal-12 culations. Arabian Light was selected as the crude type on the pre-13 sumption (which in fact, is OPEC policy) that in normal times other 14 crudes will be priced in equilibrium with this marker crude oil. Thus , the 15 results would have been comparable had we chosen a different crude. Furthermore , 16 the results would not differ signi'icantly had ve chosen a ditterent 17 refining location (say, an East Coast refinery). Next, we forecast 18 the future price evolution of the Arabian Light marker crude and added 19 the projected refining and transportation cost elements to arrive at the 20 landed price of products in New England. These prices were then adjusted 21 to reflect the impact of U.S. regulations (fees, duties, and entitlements). 22 Q. Since the price of crude oil accounts for such a major pr~mion of 23 the cost of fuel, please describe what significant events have recer.tly 24 affected international oil supply and how oil prices have evolved in 25 recsnt months. A. In the late fall of 1978 a revolution took place in Iran, one of the 26 27 major Middle East oil producing countries. Consequent to the revolution, 28 the Shah departed frcm Iran and the Bakhtiar Government, appointed 29 by him prior to his departure, fell. A new Islamic regime was established 30 by .the Ayatollah Khomeini . The revolution in Iran caused a cessation 408 335
1 of oil exports between late December 1978 and early March 1979. 2 Exports are reported to be limited by the Government to about 3 million 3 barrels per day, compared to an average export level of the craer of 4 5 million barrels per day prior to the revolution. In response to th? 5 Iranian crisis, Saudi Arabia at first allowed production to inceaase 6 in late 1978 to 10.4 million B/d. Subsequently, Saudi production was 7 reduced such that it averaged 9.5 MP8/d in the first qaarter of 1979 8 and is currently at a level of 8.5 MMB/d. Thus, it is clear that 9 there have been significant crude oil supply cifficulties and rearrange-10 ments in recent months. 11 Conserning prices, OPEC member states met in Abu Dhabi in December,1978 12 and decided on a schedule of quarterly price increases for 1979. Under 13 this schedule, the contract price for the Saudi marker crude was to have la increased in steps during each qudri.er reaching $14.55/ Bbl for the 4th quarter 15 (an average of 10% over the year assuming level production). The original 16 schedule was: 17 December 1978 $12.70/ Bbl 18 lst quarter 1979 13.34 19 2nd quarter 1979 13.84 20 3rd quarter 1979 i4.16 21 4th quarter 1979 14.55 22 Hca 3ver, in early February 1979, Saudi Arabia announced a retroactive 23 (to Jar.uary 1,1979) price increase for all barrels sold in excess 24 of the official allowable production of 8.5 millian barrels per day. p; These excess barrels were to be sold at the scheduled 4th quarter price. 26 In mid-February, certain countries (Libya, Abu Dhabi, Qatar, Iraq, and 27 Kuwait) added surcharges to all volumes wnicn in effect imediately 23 frrplementad the prices scheduled for the 4th quarter. At the end of 29 March,1979 OPEC members met again for a " consultative" meeting in Geneva, 30 at wnich it was decided to increase the official marker price of Saudi 408 n J .)
1 Arabian Light crude oil such that the scheduled 4th quarter price of 2 $14.55/ Bbl would be effective from April 1,1679. It was also decided 3 that member countries should be free to add those market premia which 4 they deemed justifiable in the light of circumstances. As a result, 5 member countries have introductJ premia which are currently 6 in the range of $2.50 to $5.50 per barrel over the .previously 7 scheduled 4th quarter prices. It is noted that all OPEC 8 member countries have added these price premia except Saudi Arabia. 9 At the time of writing, OPEC members are meeting in Geneva to discuss 10 official prices for the third quarter 1979. II Spot market crude oil prices have risen much more rapidly and have I2 now reached unprecedented levels. Spot premia over official prices 13 (already including the " official" premia mentioned above) were being I4 quoted at $15 to $20/ Bbl and although the volume of real transactions is 15 small, some prices were recently reported to be in the range of $35 to 16
$40/ Bbl for various crudes in early June 1979.
17 Q. Please explain how.you forecast the future price of crude I3 oil given the many factors involved and the highly uncertain environment. 19 A. The price of crude oil is to a large extent politically determined: 20 by OPEC deliberations and by individual producing governments in tne 2I case of foreign oil and by Presidential / Congressional action in the 22 case of domestic oil. Thus, there is a high degree of uncertainty in 23 any crude oil price projection. In this context, it is worth noting 24 that the timing and magnitude of the OPEC 1973/4 and 1979 price hikes 25 were largely unpredictable. Following the 1973 price hike, it was widely 26 believed that the cartel would collaase as all arevious cartels had. 27 It ts now ser.erally believed that CPEC will continue to be able 408 n, al
1 to set prices. An optimistic view of the future has the 2 cartel acting in a responsible manner wh'le a more 3 pessimistic view hol.fs that the cartel will act in an opportunistic 4 manner, taking advantage of current economic 'rcumstances much as it 5 did in the 1973 crisis and as it is curr 'ntly doing. 6 To better structure our views on these issues Arthur D. Little has 7 made use of aiDelphi technique. Basically, a panel of experts, in 8 this case Arthur D. Little staff members located throughout the world, 9 were asked to record their views on the future oil price levels and the 10 paths by which these price levels would be reached. In addition, a 11 series of consistency questions related to supply / demand onditions, 12 resource availability, economic growth, cost of oil substitutes, etc. 13 were asked. The oil price projection in constant 1979 dollars resulting 14 from the most recent Delphi survay conducted in June 1979 is shown in 15 Figu.' . 16 Q. What was t5e concensus view, or reference case, arrived at through 17 this proces;. - 18 A. The events in Iran, the consequent disruptions to world oil supplies 19 and the impact of those disruptions on crude oil prices have re-inforced 20 our view that supply / demand pressures will trigger-off substantial up-21 ward revisions in crude oil prices as shown in Figure I. These recent 22 events and the supply constraints introduced by Saudi Arabia have brought 23 into sharp focus the underlying tightness of world crude oil supply and 24 demand and the inherent instability of the supply situation. The impact 25 of supply tightness on price has again been demonstrated. There was 26 a general belief among the respondents that CPEC will continue to maintain 27 it.; price setting capability in the absence of unexp- ted events such as 28 military intervention or the discovery of significant new reserves of oil 29 in non-CPEC :ountries. //{/g ., h 6'
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1 We anticipate that the surcharges levied by most OPEC producers will be 2 consolidated into the official price f r Saudi Arabian Light (currently 3 $14.55 per barrel) such that the media.i price in 1980 is expected to 4 be $17.8/ Bbl in 1979 $. A slowdown in demand growth rates due to the 5 combined effects of conservation, oil substitutes, and depressed economic 6 growth rates, coupled with the addition of new supplies from Alaska, the 7 North Sea and Mexico, will lead to a potential easing of the tignt supply 8 position during the early 1980's. Price increases in this period are there-9 fore likely to be modest and limited to inflation type adjustments. 10 Moving into the mid-1980's, the situation begins to change. New non-OPEC 11 supplies will have largely been absorbed and increases in OPEC production 12 will be needed to meet demand. During the mid-1980's there will be a 13 strong likelihoac of another significant upward revision of cude price 14 to levels which would be targeted to make high cost hydrocarbon resources 15 sch as shale oil, tar sands, or remote natural gas cost 16 competitive. 17 The timing of sucn an increase would depend on economic conditions but 18 would most likely occur when a bottleneck (in production, refining, . 19 and/or transportation) develops within the oil supply system. This 20 increase would be followed by a further pericd lidation and 21 digestion, during which the crude oil prices would stabilize in real 22 terms. Later, in 1. .e mid-1990's, it was fel t that further price increases 23 would take place as physical oil resource constraints were strongly 24 perceived. There was a general perception among respondents that the major 25 instabilities occuring during the 1980's as tne crude oil prica is 26 ratcheted upwards will give way during the 1990's to a period of 27 greater stability once the transition to greater use of alternative 28 energy forms is wall under way, a higher degree of conservation has taken 29 effect and oil prices are more in line with the cost of the alternates. 408 340
1 There was, however, considerable uncertainty ia future oil prices as 2 evidenced by the confidence limits shown in Figure I and Tables 1 to 5. 3 There is also considerable uncertairty surrounding the timing of price 4 increases since shortages in supply could develop at any time as a 5 consequence of accidental or deliberate cutbacks by individual OPEC 6 countries. 7 Q. How were the other elements of cost projected? 8 A. The projection of refining cost poses particular problems since joint g costs must be allocated to individual products. In the simplest type 10 of refinery, crude oil is separated into individual fractions by 11 boiling off the lighter fractions in a process called distillation. 12 A portion of the crude oil does not boil off and is call:d ;esidual 13 fuel oil. This is the product typically used by utilities in oil fired 14 electric plants. The raw fractions obtained by this primary distillation, 15 however, may not satisfy the product demand patterns or the product 16 quality characteristics required. For example, the residual fuel oil 17 may have to be treated to remove sulfur and this desulfurization cost 18 causes a price difference between high sulfur and low sulfur fuel oils. 19 In some markets, the yield of residual fuel oil is larger than can be 20 absorbed at economic fuel oil prices. Refining processes are available 21 (catalytic cracking, hydrocracking, etc.) to convert fuel oil into gasoline 22 and No. 2 fuel oil. The cost of these conversion processes is reflected 23 in the price differential between fuel oil and these lighter products. 24 To further complicate matters, individual crude oils vary widely in thit-25 orope r,nging from crude oils with a very high natural proportion 26 of re . fuel oil (heavy crudes) to those with a low proportion 27 (lig'et crudes) and ranging from crude oils with a high sulfur content 28 tr. crudes wi th very li ttle sul fur. Refiners continually balance crude fGf b0
1 oils, processing, and markets to achieve optimal results and this complex 2 interaction is reflected in individual product prices. At the present 3 time in the Caribbean there is both a surplus of distillation capacity 4 ano a surplus of fuel oil desulfurization capacity. This situation 5 causes a low allocation of iafining cost to residual fuel oil on the 6 one hand and price differentials between high sulfur and low sulfur i fuel oils below the full cost of desulfurization on the other hand. 8 At the same time, there is a shortage of processing capacity to convert 9 fuel oil to light products (gasoline and No. 2 fuel oil) and prices for 10 these products reflect margins higher than the full cost of conversion 11 processing. Our forecast of the refining element in the fuel prices 12 projected in this study reflects a gradually increasing trend to full 13 cost recovery during the period to the year 2000. 14 Foreign flag tankers are in much the same position as offshore refineries. 1: The surplus tanker capacity has driven freight rates below carh costs 16 f ar large tankers. For smaller product tankers, freight rates are currently 17 higher than fully allocated costs. As in the case of refineries we expect 18 rates. for larger tankers to change gradually as tanker supply and demand lg come into balance such that freight rates will reflect fuil costs including 20 a return on investment by the early 1990's. Both the tan %er cost forecast 21 and the refinery cast forecast reflect projected crude price increases 22 which influence bunker costs in the case of tankers and refinery fuel in 23 the case of refining. 24 Current U.S. regulations reduce the cost of fuel oil below import pari y 25 by granting importers an " entitlement credit" of about $1.00 per barrei 26 (50% of the entitlement credit for imported crude oil). In addition, 27 import fees are theoretically payable on certain import volumes, but have 28 currently been suspended. The administration has recently im;lemented 29 a special $5,00/ Bbl entitlement credit for distillate imports. In o - f'
- 13..
1 preparing the price projections, it has been assumed that only a fee 2 of 42c per barrel will apply to imported products as protection for 3 U.S. refiners. 4 Q. What are the results of your analysis? 5 A. Applying the procedures just outlined, we have obtained the results 6 shown below in Table I which are expressed in 1979 dollars per 7 million Btu, for the reference case: TABLE 1 DELIVERED FUEL OIL PRICE FORECAST Reference Case _ (1975 $ per Million Btu) 1980 1985 1990 2000 No. 2 Fuel Oil 3.75 4.90 5.71 6.90 0.5% Sulfur Resid . 3.17 4.45 5.24 6.40 1.0% Sulfur Resid 3.06 4.29 5.03 6.15 2.2% Sulfur Resid 2.83 3.95 4.61 5.63 2.7% Sulfur Resid 2.74 3.83 4.46 5.44 408 34;
Tables 2 and 3 show the +70% and /0% confidence limit cases and Tables 4 and 5 the +95% and -95% confidence limit cases. TABLE 2 DELIVERED FUEL OIL PRICE FORECAST Plus 70% Case (1979 $ per Million Stu) 19ED 1985 1990 2000 No. 2 Fuel Oil 4.18 6.01 7.16 8.85 0.5% Sulfur Resid 3.53 5.53 6.65 19 1.0% Sulfur Resid 3.41 5.33 6.40 7.98 2.2% Sulfur Resid 3.15 4.93 5.90 7.35 2.7% Sulfur Resid 3.06 4.79 5.71 7.12 TABLE 3 DELIVERED FUEL OIL PRICE FORECAST Minus 70% Case (1979 $ per Milifon Stu) 1980 1985 1990 2000 No. 2 Fuel Oil 3.21 3.67 4.41 5.12 0.5% Sulfur Resid 2.72 3.26 3.98 4.66 1.0% Sulfur Resid 2.61 3.13 3.81 4.46 2.2% Sulfur Resid 2.42 2.87 3.47 4.06 2.7"< Sul fur Resid 2.34 2.77 3.35 3.91 408 344
TABLE 4 DELIVERED FUEL OIL PRICE FORECAST
+95% Case (1979 $ per Million Btu) 1980 1985 1990 2000 No. 2 Fuel Oil 4.77 6.99 9.11 10.61 0.5% Sulfur Resid 4.02 6.48 8.55 10.01 1.0% Sulfur Pesid 3.38 6.25 8.24 9.65 2.2% Sulfur Resid 3.59 5.79 7.62 8.91 2.7% Sulfur Resid 3.49 5.63 7.40 8.64 TABLE 5 DELIVERED FUEL OIL PRICE FORECAST
-95% Case (1979 $ per Million Stu) 1980 1985 1990 2000 No. 2 Fuel Oil 3.02 3.28 3.63 3.94 0.5% Sulfur Resid 2.55 2.88 3.21 3.52 1.0% Sulfur Resid 2.45 2.76 3.07 3.35 2.2% Sulfur Resid 2.27 2.52 2.78 3.02 2.7% Sulfur Resid 2.20 2.44 2.67 2.89 403 345}}