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September 17, 1982

Mr. Richard Emerman Alaska Office of the Governor DivisiGn of Policy Development and Planning Pouch AD Juneau, Alaska 99811

Dear Dick:

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.1 Pantie 0iorriw.e')t Laboratories P.O. Bo\ 9-19 Richland. \\.>:.hm~ten L.S.A. 99352

Telephone !509J 376-4852 Telex 15-2o7·fTS 444-4852

RECEIVED

SEP 2 4Jf3B2 ALASKA POWE.q Au-r-u

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You1~ letter of August 24, 1982 to Wayne Slater has been referred to me for ~eply. I read the August 17, 1982 draft of Alaska Enerqy Planninq Studies: Substantive Issues and the Effects of Recent Events by Arlon Tussing ari·d Gr-eg Erickson and do have some corrnnents to make on their report -..~...:i they a.dd1~ess the Railbelt Electric Power Alternatives Study~ I have keyed my discussion to the main technical issues raised~ ·

FUTURE OIL PRICES

The authors' strongest point is that there is now no consensus on the long-term oil-price outlook. We agree that there is r0 consensus. While there is a strong herd instinct among analysts to over--emphasize the most recent experience in the market in projecting the longer tr.end. the outlook for the short term is undoubtedly a·flat nominal price. The cutlook for the long run is far less certain. For example, in contrast to the authors' view that future oil prices are likely to be considerably lower than today, Data Resources, Inc.'s sui11Tler 1982 long term trend forecast is for negative nominal grmvth in prices through 1983, but with long term growth to 1995 averaging about 8.6 to 8.7 percent per annum. At their forecast of 6.7 percent average inflation, this yields about 2 percent average real price increase. At the seven percent assumed for the Railbelt Alternatives Study, the average total price increase for oil would be 1.6 percent. Alaska Department of Revenue's June, 1982 forecast has also rebounded somewhat from the pessimism expressed in March, forecasting weighted average price for Prudhoe Bay-type crudes rising from $31.11 in FY 1982 to $98.46 in FY 1998, or about 7.5 percent per year average. At their assumed 7.7 percent average inflation this indeed works out to -0.2 percent. At the seven percent inflation rate assumed in the Railbelt Alternatives Study, however, it works out to plus 0.5 percent. In any case, Department of Revenue now estimates that Alaska North Slope oil at the wellhead would increase at 9.6 percent in nominal terms: 1.9 percent real at their rate of inflation, 2.4 percent real at a seven percent rate of inflation assumed in the Railbelt Study. Still, a balanced reading of the literature might indeed

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shm'l that there is no current consensus concerning long term "future enErgy prices. We can certainly find such evidence. Standard Oil Company of California's economics department June 1982 forecast year 2000 real oil prices from near $30 per barrel to $55 per barrel, a range of about 0 percent to 2.7 percent per year.

There can be no doubt that state revenue forecasts are now dramatically lower than in June 1981 or even December 1981 (although higher than in March 1982). This in turn should lower the expected rate of growth of the Alaska economy. As a matter of fact, the best current evidence now sug9ests a 11most likely 11

case near or slightly below the pr~vious low case. However, since Battelle­Northwest anticipated that the best ~narket evidence is subject to change with very little notice, Battelle-Northwest arranged to transfer the models used in the study to the State of Alaska as insurance aga1nst the forecasts themselves becoming outmoded. Some 80 percent of the budget in the project was devoted to building the models and the information base; about 20 percent to scenario­building and analysis.

. Contents of the Moderate Growth Case

The authors have made several minor errors of fact in this section. For example, our appendix Table A.3 shows population in the Railbelt growing at a compound rate of 2.15 percent, not 4.2 percent. The state spending assumption was that real state spending would grow in proportion to real income (not remain constant in per capita terms).

A larger error in perception concerns how the scenarios used in the studv were developed. ISER's 1980 scenarios were not used "as is"; they were modified, subjected to further review, and "fr·ozen 11 in August 1981. The load growth scenarios were sumnarized in the Evaluation of Railbelt Electric Enerqv Plans, but descr·ibed in far greater detail in ISER's final report to Battelle­Northwes-t:, Alaska Economic Pro.iections for Estimatino Electricity Reouiremr:onts for the Rai1belt. They \~Jere also described in the fvlarch 1981 Alaska ··­Economic ·scenarios Review Document, Corrment Draft \·Jork ing Paper No. 2.1, which was widely circulated in Alaska for review to obtain Alaskans! opinions (and especially exoert opinion) of what economic activity was likely to occur in Alaska. Int~restingly, both authors of the current critique were sent the latter document and offered the chance at that time ~o criticize the assumptions anf contribute to a better study. They chose not to avail themselves of the opportunity. Had they chosen to review the scenarios at that time, they v.;ould have noticed detailed instructions on crit·icizing the scenarios used. The scenarios review document soecifically asked the following questions (page 7.):

Critiques of ISER economic model forecasts for the Alaska Power Authority's Susitna Hydroelectric Project power studies have focused on the following issues in scenario development. You may wish to corrnnent on these:

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o Upper Bound (High Economic Growth plus High State Spending) and Lower Bound (Low Economic GrowtL and Low Government Expenditure) scenarios were not run. (The alternatives study will do this.)

o The set of scenarios run did not include futures cont~ining either stable industrial growth or economic stagnation.. (Do the industrialization and fiscal crisis scenarios take care of this problem?)

o Future State Government expenditures in the highest spending case still resulted in a large fiscal surplus at the end of the century; therefore, they were not high enough. (Is this a serious issue? If so, how should it. be handled?)

o The scenario approach puts its emphasis on currently identifiable projects and options for industrial growth. Thus, it tends to understate developments whose start dates are beyond the current long range planning horizon of the private sector. For example, industrial development based on lease sales and changes in minerals, fisheries, agricultural, and timber markets after 1985 could affect the post-1990 forecasts. (How should this be incorporated in the forecasts, if at all?)

In retrospect, we might have been wise to leave out some projects from some cases. In prospect, this was not as obvious. Further, no state expert saw fit to challenge our assumptions. The fact is that Battelle-Northwest researchers were aware of the potential for a problem with the range represented by their forecasts and did include an Unsustainable Spending Scenario. ISER had great difficulty making this operational because of the buoyant energy price forecasts then current; however, an attempt was made and is included in the study.

Dr. Tussing has had many words to say on the subject of the proper selection of scenarios for evaluation in power studies. In contrast to the May 9, 1980 report on page 24, citing the importance of examinina a boom-bust scenario (which we did: see section 8.3.3, p. 8.12 of the Evaluation of Electric Enerqy Plans), Tussing also gave the following advice to the Policy Review Committee in his later examination of Battelle-Northwest 1 s proposal (emphasis in the original):

11 The procedure and method we are suggesting centers on ranking and simulating the attributes and side effects of a relatively small number of expansion strategies, first under a set of standard or base-case assumptions, and then assuming specific departures from the base-case assumptions (for example, higher or lower than expected load growth; higher or lower than expected natural gas prices; a specjfied cost overrun or de1ay in completing a selected project, etc.). This approach can deal

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Mr'i. R'ichard Emerman seiptemb~~r 17~ 1982 Pa:ge 4

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both with uncettai ntv and vtith di saareement over the input ___...._ assumptions, and makes the effect of changing any assumption explicit~ What follows is a general outline of the approach.

1. ESTABLISH BASE CASE-ASSUMPTIONS. Select plausible, conventional, consensus or. majority assumptions about A 1 ask a economic deve 1 opment, 1 oad growth and 1 oad characteristics, inflation, fuel prices, interest rates, etc. Also, select base-case attributes describing financing strategy, reliability standards, other policy and institutional variables. It is not crucial for the base-case assumptions to be 'correctJ (an impossible goal in any case), but that they be assumptions which would be acceptable to the decision­makers. They should be tne assumptions public officials and utility planners are likely to use regardless of what 'our' experts believe would be the 'best' assumptions. The assumption should be carefully and unambiguously stated, and consistent both internally and with one another, but they should not be particularly sophisticated or innovative. -

For example, the boom-and-bust scenario suggested by Tussing may well be the most likely future for Alaska. But even if there were a consensus among professional economists that it was the most likely future, it is. almost unthinkable that the Alaska Power Authority, the Governor, or the Legislature would use that scenario as a basic assumption for planning electric generating facility. Like.wise, it may be true that the fir$t large­scale coal-fired generating plant in Alaska, or a specific large hydropower project, is likely to come on line five years or more later than planned, and at three times its budget. Yet planners and officials are unlikely to base their decisions on assumptions like these. Any analysis that rested on an assumption that Alaska•s economy will crash in the 1990's and that Susitna project will be subject to large overruns and compl(~tion delays would be r·ejected by the decision­maker!: and the public, and would thus be worthless as a plann:ng toJl. In our approach, any departures from base-case assumptions, whether seen as risks or as issues of controversv, would be examined by means of sensitivity analvsis.

This approach does not require that much additional effort be devoted to further refinement of load-growth forecasts. The uncertainty that proceeds from the clouded outlook regarding Alaska economic growth in general could swamp, by an order of magnitude or more,

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any improvement in load forecasts that would result from better methodology or data. This study is not the place to fight out the issue of Alaska•s future economic outlook, but it is imperative to show what the implications would be if these standard assumotions were \'Jrono."

In fact, this was precisely the approach taken in the Railbelt Alternatives Study. Most of the analysis did center around what was believed at the time to be the most plausible or believable case with several sensitivity tests. It did not become clear until after all the final computer runs were done that world oil market conditions had changed enough to warrant a ne1t1 11 most likely .. case. Although one can reasonable argue that the sensitivity tests that we ran may not have taken into account the full range of sensitivities, we did consider the problem involved. For example, we spent some time considering how large a range of cases to consider for Susitna cost overruns and for downturns in demand. We settled for 20 percent cost overruns on Susitna because those overruns were in the readily believable range and did make the point that the plans containing Susitna were sensitive to capital cost escalation. We did not think that 200 percent cost overruns, for exampl~, would have been a believable sensitivity case, especially since ACRES/APA claimed 70 percent confidence for the costs they reported. We considered a fairly sharp decline in demand (-37% over 15 years) just at the point that Wa+1na is completed. As expected, power costs went up and Devil Canyon had to be deferred. By dwelling on the main scenario, Tussing and Erickson miss a lot of the study.

Lono Term Enerav Plan

Footnote 37 appears to be in error. Battelle's "low case" population compound growth rate for the Railbelt to the year 2000 is about 1.8 percent,.as can be derived from Table A.4 in the Evaluation o~· Railbelf Electric Enerav nlans report, not 3.4 percent as stated. Like ~Iussing and Erickson, I am also unable to account for Booze-Allen and Hamilton's population and employment growth rates, though Tussing and Erickson seem to correctly report what Booze-Allen and Hamilton assumed. I had several discussions with Booze-Allen and Hamilton about our forecasts of population, employment, energy, and electricity, but 1.1 percent population growth is not consistent with either our preliminary set of forecasts used in the study for the Division of Minerals and Energy Management or the final set of forecasts produced in January.

ALASKA FOSSIL FUEL AVAILABILITY AND COSTS

The authors may have read more into Battelle-Northwest's "position" on gas and coal-fired power plants than we intended or think we said. We certainly do not take the position (as Acres apparently does, if quoted correctly) that future thermal generation must be coal. As a matter of fact, because of our uncertainty over the prospects for gas in Cook Inlet, we went on to examine a future with gas available at both Anchorage and Fairbanks. We indicated,

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however, that the~e are great uncertainties surrounding the extent of this supply. For example, the Battelle-Nor~hwest study for the Department of Natural Resources does not necessarily conflict wi~h the assumptions used in the Railbelt Study. The DNR, although it assumes lower demand by Pacific LNG, still study shows that if Pacific Alaska LNG or any other plant of its size delivering to an export market were to go forward as assumed in all but the Railbelt low case, the Cook Inlet region wou 1 d, in fact, show a deficit against existing reserves before the year 2000. (An error was made in the original printing of the DNR study which underestimated cumulative Cook Inlet gas consumption by 135 Bcf. Corrected for that, uses, excluding oil and gas pr~oduction, consume the estimated reserves before the year 2000 in the Railbelt medium and high scenarios.) i-la.lf the question on gas availability thus is really whether Pacific LNG or other industrial customers would tie up the existing gas, reducing its availablity for local utilities. The other half of the question is whether additional gas resources exi~t in Cook Inlet and, if so~ the extent of these resources.

The Tussing/Ericksen position on the first question is that there is substan­tial doubt that the Pacific Alaska LNG plant will ever go forward, both because of problems regarding the specific project (which we agree are there) and because of new doubts about all supplemental gas. Nonetheless, the Pacific LNG project has been able to makesubstantial progress toward si~ning up additional reserves in the last year--up from 829 to 980 Bcf firm commitments, options on 75 Bcf more, and new reserves of 435 Bcf--and the sponsors continue to believe the aas will be wanted in California in the late 1980's. Even if the Pacific­Alaska LNG project should fail on environmental grounds (which is not certain), the Pacific Rim as a whole may be a potential market for the gas. Standard Oil of California, for example, s~ys in their June 1982 forecast that Japan's market for LNG is expected to increase at 6.5 percent per year to the end of the century. (Gas is priced based on the delivered cost of oil in Japan because over 65 percent of gas delivered to Japan goes into electrical energy production where its principal value is as Btu's.) Also~ contrary to what the authors app2ar to believe, other industrial users are making low-profile attempts to line up additional reserves, probably for export. How serious or extensive these attempts are, we don't know. However, in any case we do not believe a buyers market in 1990 in Cook Inlet would resemble the "buyers market" of the early 1960's. Even if the Cook Inlet Market should experience a surplus situation due to the collapse of Pacific-Alaska LNG concept on environmental grounds, it is highly unlikely that producers would sign new contracts for gas deliveries containing the unrealistic escalation clauses of the past or which have initial prices markedly below the producers' opportunity cost of delivery to the existing (or expanded) LNG and ammonia-urea plants on the Kenai Peninsula. We continue to believe that while there is some chance for lower prices in Cook Inlet, the most prudent course for analysis is to assume the gas price would be dictated by opportunity costs represented by LNG. However, for those persons who believe the price might be lower than we forecasted, we did examine a sensitivity case in which oil prices escalated at one percent instead of 2 percent in real terms. Retail natural gas prices in Cook Inlet in this case reach $2.32 by 1990 and $4.56 by the end of the century, as opposed to $2.47 and $5.91 in the base case. This sensitivity case

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is shown in section 8.2.1 of the draft final report, and demonstrates that the relative position of the gas alternative (Plan 4) is much improved compared to Susitna (Plan 18) when lower gas prices are assumed.

NORTH SLOPE G.l\S AVAILABILITY AND PRICE

Because of the fundamental differences in institutions and markets for North Slope natural gas~ a completely different appproach was taken. Our discussions with the Federal Energy Regulatory Commissior. indicated the manner in which gas transportation would be priced, given that the pipeline were built. If no pipeline (ANGTS is not the only proposal) is built, there is little likelihood of gas being available at Fairbanks~ The details of our discussion are contained in Section 6.2 of the Fossil Fuel Availability and Price Forecasts document. Some details have been changed to account for non­escalation of the pipeline tariff in nominal terms, although it has minimal impact on the use of gas in Fairbanks. If the pipeline is built, the netting back of transportation from the lower 48 must give a minimum well head price that covers North Slope marginal cost of producing the gas at the well head. Based on estimates of the Department of Interior from the middle-to-late 1970's, escalated to 1982 dollars, that price might be as low as $1.00-$1.50. This would reduce the Fairbanks price below its base case value to between $4.79 and $5.29, not dramatically different than the base case value of $5.92. Even at the maximum gas price, our forecasts indicated that the price of oil and electricity would be high enough that most Fairbanks space heating (and other uses where gas, oil, and electricity substitute for each other) would be done with.gas if the pipeline were built. Price considerations thus would not dramatically reduce electric demand in Fairbanks through fuel substitution. Lower prices for gas would likely increase demand for electricity (on balance) by lowering the overall cost of energy and the relative price of electricity. This should also substantially increase the attractiveness of Plan 4 (Increased Use of Gas).

Since we were aware of Tussing's position that the ANGTS pipeline plan had problems .. it might have been prudent to exclude the ANGTS pipeline in at least one case. However, the only comments we had on this issue from any reviewer were not that the pipeline would not be'built; rather, that it would be delayed a year compared with the then-announced schedule. We put that delay in a1l cases in order to be as conservative as we then dared.

Coal Prices

We are quite puzzled at Tussing/Ericksen's explanation of the way in which they apparently believe Battelle-Northwest derived coal prices for the Cook Inlet and Fairbanks areas. Even though our forecast was fairly close to the central tendency of Acres forecasts, in no way \'/as this price computed from the pri c.e of oil in Japan. Rather, initial price \A/as based on Chuitna field cost estimates by Bass-Hunt-Wilson, as well as two separate netback calculations~ one using the actual price of coal CIF Japan and Taiwan (considerably below the price of crude oil) and one using weighted average landed cost to Japan of

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steal.: co a 1 produced in Australia, Canada, and South Africa. The three prices were in close agreement. The escalation rate for Beluga coal was based on both the obse~ved price history for steam coal during the 1970 1 s and a number of industry forecasts. (These are not unanimous. Standard 0 i 1 now be 1 i eves the Pacific Rim price for steam coal will remain flat to the end of the century.) Nenana coal current price was based on the current base price at Usibelli, plus transportation. The real rate of increase in price was then based on historic experience with the production cost of Healy coal, plus our knowledge of,export alternatives. Existing contracts for Healy coal expire in 1986 and 1987, when price adjustments could take place. Thus while the Tussing/Ericksen argument is interesting, it is beside the point as far as Battelle-Northwest's coal price computations are concerned.

Tussing and Erickson also make an assertion (it is no more than that) concerning coal producers' likely react~on to a local utility's offering a 20 year take-or-pay contract. While we cannot predict whether such an offer would be forthcoming or acc~pted, our best information is that a bigger contract would be needed to open the Beluga field: on the order of 400 MW to 600 MW, rather than 200 MWn We do agree that an export.mine would make the local­dedicated reserves more attractive to develop. ·we believe that under some circumstances it may be essential to opening the field at all.

Additional information has been gathered concerning the attractiveness of various-sized coal mines in the Beluga area. While the current effort to develop the Beluga-Chuitna fields is oriented toward large scale mining (beginning at 5 to 6 million tons per year) for export, Battelle-Northwest further explored the possibility of smaller mines with some of the producers in the Beluga area. One group stated that previous analysis done by themselves and others indicates that mines serving mine mouth power plants might be opened for as _little as 0.5 million tons per year. Furthermore, at 400 MW {about 1.4 million tons per year) a mine-mouth plant would probably be competitive with other sources of power, and a 2 million ton per year contract (600 MW) would be very attractive. These studies have not been re-evaluated in light of more recent knowledge or for generating plants of smaller than 400 MW. Another producer group states the situation a bit differently. They agree with the first group that a coal mine with contracts for take-or-pay at 2 million tons per year to a mine-mouth plant would be attractive, as would a 2 to 3 million ton per year export mine with 2 to 3 million tons mine-mouth sales. There are circumstances where three quarter of a million tons per year (enough to fire a single 200 MW plant) might be attractive enough to open the mine. It would depend on what additional demand (export and mine-mouth) might be forthcoming, with what guarantees, and with what timing. A 200 MW plant by itself might or might not be enough to open the mine. The producers appear divided on thispointe

If sales equivalent to 400 to 600 MW could somehow b~ guaranteed ~ithin about 3 years, however, a mine-mouth plant becomes much more likely. This might require the state to give the producers a take-or-pay contract for up to 2 million tons per year of coal; or, alternatively, that there be a large enough export market (less than the 5 to 6 million tons required for export only, but

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large enough to pay for export facilities) to give the producers rate of return large enough to amortize the capital investment necessary to open the mine at efficient scale.

In the Railbelt Alternatives Study base case, 200 MW of coal-fired generation is planned for 1992 in Anchorage-Cook Inlet and 200 MW in 1997 in Fairbanks­Tanana Valley. Withc~t an export market, even 400 MW consolidated at Beluga opening over that period of time might not be enough timely demand to guarantee a mine opening at Beluga at 200 MW, so coal would have to come from Healy at higher cost. In the increased coal use plan, the outlook is much better for Beluga: 600 MW over the 5 years beginning 1997, plus 200 MW at Nenana that could be moved to Beluga if necessary. Even so, without exports the state might have to guarantee markets for somewhere between 400 to 600 MW within a short period of time to open a mine at Beluga on the first 200 MW. Guaranteed exports at a scale large enough to pay for shipping facilities would in either case make a mine opening much more attractive to the producers. To pay for such facilities (given the mine mouth demand) these exports might be on the order of 2 to 4 million tons per year.

I hope this helps in your evaluation of Tussing and Erickson's report.

Yours truly, •

~ Michael J. Scott Senior Research Economist

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cc DE Deonigi CP Sitkin AR Tussing PRC

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