TABLE 3.-SUMMARY COMPARISON OF TRANS-ALASKA PIPELINES TO LOS ANGELES AND MACKENZIE VALLEY PIPELINE TO CHICAGO USING A 10-PERCENT DISCOUNT RATE

1 Present value of taxes are calculated by multiplying the wellhead price by 20 percent and the resultant per barrel tax by the appropriate present value of throughput.

a Present value of profits are determined by subtracting royalty severance taxes, and production costs from the wellhead price and then multiplying by the appropriate present value of throughput.

historical price and then permit foreign oil to be imported to meet the difference between the quantity of domestic plus Canadian oil supplied and domestic quantity demanded at this price.

On the other hand imports in Districts I to IV are based upon a percentage of domestic production. Accordingly, if present import quota regulations are maintained, the probability of cheaper foreign oil increasing in the west as a percentage of domestic supply is far greater than in the east, if North Slope oil is not produced. That is, present institutional rigidities will create a greater incentive for domestic producers east of the Rockies to produce any shortage in supply than their West Coast counterparts. The relative quantities produced in each section of the country are particularly important, since production east of the Rockies is more than six times greater than West Coast production. Therefore, small percentage increases in supply from various incentives such as increasing prices, new technology, more favorable tax treatment will have a far greater absolute increase in oil supplied for markets east of the Rockies.

Two conclusions should be drawn from the above discussion. First, foreign oil tends to be far less costly in both real and monetary terms than the marginal barrel of oil produced in the eastern part of the United States. Therefore, if the alternative to North Slope oil is more likely (Pa) to be a domestic source than a foreign source (PF) then the average cost of the alternative to North Slope will be greater in both monetary and real terms in the Midwest and East Coast when compared to the West Coast. Second, the market is far greater in terms of its actual size and its growth in demand; therefore, both markets will probably find their dependence on foreign oil increasing over time. Therefore, from a national security standpoint, the full throughput of either crude oil pipeline will displace foreign crude. The difference between alternatives is that in the eastern part of the United States, due to different institutional rigidities, North Slope crude is more likely to back out higher cost domestic crude as well. Therefore, the assumption of relatively low cost foreign sources of supply being used as a substitute for North Slope crude oil in Chicago may not be as appropriate as making that same assumption in the case of Los Angeles. One way to account for this distinction is to estimate the probability of using domestic or foreign sources of supply in each market. The Footnotes at end of article.

average costs of domestic and foreign sources of supply can then be combined to form a weighted average alternative cost, as follows:

(5) where:

CDripdiCD+PjCpi

Cor Weighted average cost of alternative source of supply in market j from domestic (D) and foreign (F) sources of supply.

PD=1-P=The probability of domestic sources being used as a substitute

in market j.

Pi=The probability of foreign sources being used as a substitute in market j.

CpAverage cost of domestic crude in market j.

Cpi Average cost of foreign crude in market j.

Pri

2 billion barrels per day

(10 billion barrels per day + 2 billion barrels per day Pa=1-P=5

6

An additional adjustment that might be made is to relax the assumption of equal benefits to consumers of crude oil from different sources of supply. The viability of domestic and foreign production restrictions east of the Rockies will certainly be affected differently if North Slope crude rather than foreign crude is used as a source of supplying Midwest demand in the future. An additional measure of benefits is the fact that oil consumers in different markets value products made from crude oil differnetly. For example, gasoline is a major product of refineries on the West Coast. Gasoline is light and the lighter the crudes the easier (that is, least costly) it is to derive gasoline from crude oil. In the Midwest a greater mix of products is demanded by consumers. One of the main reasons for this is that home heating fuels (which are relatively heavy products) are highly valued in the Midwest, but not on the West Coast. Since North Slope crude is a relatively heavy crude, its value to refiners and consumers is greater in the Midwest due to greater product mix than on the West Coast. Since lighter crudes can be substituted more readily on the West Coast and since the entire world market is potentially available for import, this relative advantage of a Midwest final market for crude is important. One method of measuring this relative importance is to note that most crudes east of the Rockies are adjusted $.02 per degree of API specific gravity difference, while on the West Coast the penalty for heavy crudes is about $.06 or $.07, or about three times greater. In this section the importance of these exceptions will be analyzed to determine their effect on the benefitcost ratios, state taxes and the profitability of each Arctic transportation system.

The first step is to estimate the probabilities of using foreign or domestic sources of supply in each market. The greater the domestic production in a region of the United States, the probability of foreign oil as an alternative source of supply is less likely. Therefore, I will assume for simplicity that weights (Pa and Pr) may be assigned on the percent that the full North Slope throughput would be to the approximate present domestic production plus that full throughput level of production. Therefore, in Districts I to IV, I will use the following weights: 18

Since such an adjustment for any possible savings over possible domestic alternatives was not made on the calculations performed above for the West Coast, if a Trans Alaskan pipeline is selected a similar set of weights

(Pa and Ppi)

can be determined. Using the same formula as the east of the Rockies, these probabilities will be approximately equal, since the expected TAP throughput approximately equals present "domestic" production in District V, threefore: 2 billion barrels per day

Pri

(2 billion barrels per day + 2 billion barrels per day) Pa=1=P=1

2

Footnotes at end of article.

1

=

2

To calculate relative domestic costs there is insufficient information available. One simple method to approximate relative cost differences is to use relative price difference as a proxy. Prices of domestic crude oil are available at the producing source. Specific adjustments to account for qualitiative differences in domestic crudes such as specific gravity and sulfur content are also available. The prices at the wellhead of these domestic crudes are net of transportation costs to specific markets. Since such transportation costs are real economic costs, it is appropriate to calculate the cost of these reference crudes in specific consuming markets, such as Los Angeles, Chicago and New York. Prices in the latter two markets are determined by adding the transportation costs of crude oil from the East Texas-Southern Louisiana Gulf region to the price of crude oil in this Gulf region. Producing areas which sell crude on the Gulf Coast are priced at a lower amount of their wellhead to reflect the cost of transporting this crude to the Gulf.10 Relative price differences between the west coast and east of the Rockies market will also reflect the relative cost of refining crudes for different product mixes. Since these differences are also important to consider in assessing real economic benefits, this is an additional reason to use relative price difference. Finally, domestic market restrictions for crude oil make it likely that domestic producers will, in the absence of a large low-cost domestic source of supply, produce crude oil at a high marginal cost. If prices are expected to increase if North Slope oil is not supplied to a particular U.S. market, then higher marginal cost oil will be produced than is presently the case. Therefore, it is appropriate to use the present price as a measure of the average cost of additional domestic sources of supply (and also assume in this range that the average domestic cost equals the present marginal cost).

Using the above weights and present prices and assuming a system of "swaps" is developed so that effectively half the crude from the North Slope displaces higher cost domestic and foreign crudes in Chicago and New York, a weighted average cost of alternative similar to that shown in equation (5) above can be determined as follows:

A similar adjustment for the Los Angeles market using a mixed domestic and foreign alternative source of supply can be calculated as follows:

1⁄2 ($3.17) + 1⁄2 ($2.50) = $2.835

These estimates of $3.715 and $2.835 per barrel can be compared with the per barrel benefit estimates of $2.74 and $2.49 for the east of the Rockies and West Coast markets respectively. These later values were used in Table 3 above and are based upon a long-run view that foreign crude was the only alternative source of supply.

21

In the computations presented below, several additional parameters are reviewd. First, it has been pointed out the North Slope oil is medium in sulfur content. However, the domestic crudes that supply the Midwest market are generally lower in sulfur content than domestic crudes on the West Coast.20 To adjust for this difference, crude prices might be reduced east of the Rockies. An $.11 per barrel difference exists between the posted wellhead of West Texas sour and West Texas Intermediate Sweet. This difference is used below to account for sulfur content differences. A second possible adjustment is that North Slope oil may be lighter than 26.9° API, in which case the penalty charged against it may be too severe for the West Coast relative to the Midwest. This adjustment may reduce relative prices by an additional $.05 to $.10 per barrel. To account for both factors, the various benefit estimates will be reduced by $.18 per barrel. This combined adjustment is identified below as the "Alyeska Price Adjustment Factor."

Footnotes at end of article.

It should be noted that the adjustment for sulfur content and specific gravity penalties reduces the reference price in the Midwest to $3.63 per barrel. However, it is important to note that this adjustment may be in the wrong direction, since early analysis of North Slope crude indicated it scored particularly high using a Hydrocraking refining technique, which is now being installed in the Midwest.22 Usuing that finding, a reference price of $3.93 per barrel would be in order. As a final point on prices (in the opposite direction) the Department of Interior used a maximum price of $3.50 per barrel for reference purposes in the Midwest.23 However, this has recently been increased to $3.60 per barrel 24 and the East Coast price has always been consistent with those higher prices used in the analysis above. Therefore, the case labeled "Alyeska Adjustment" can also be interpreted as the new Department of Interior maximum Midwest price case,25 and the Midwest price without adjustment is high or low depending upon future conditions but it certainly falls in the most likely range of $3.63 to $3.93 per barrel for the Chicago market.

Much discussion in this controversy has dealt with the environmental advantages of the Alaskan Highway Route (AHP). Thus far we have not considered its economic benefits and costs. This route is longer than the Mackenzie Valley route (MVP). Walter Parker 26 therefore estimated it would cost about $400 million more in 1971 $. This difference needs to be taken into account. In doing so below, the operating costs of this longer route have also been increased proportionately.

The last factor, which will be considered in the analysis below, tests the sensitivity of the results of an assumption that the real costs of the Canadian alternatives have been underestimated. This could be due to uncertain and inaccurate cost data or to possible new taxes or other real costs imposed by Canada. Guaranteed capacity for Canadian oil is sometimes mentioned as a possibility. Such decisions might result in U.S. consumers of oil paying higher costs or taxes to the Canadian government and thus represent a real cost. All such adjustments would be in the same direction, that is, cost would increase; therefore, the sensitivity of the results to an appreciation in all costs of 10 percent and 20 percent will be examined below.27

In Table 4 the benefit-cost ratios are shown adjusted for the above factors. Only at the highest capital cost per barrel, as are found in the ANP case (Alaska Highway with capital costs of about $4 billion), with a two-year delay and 20% cost appreciation (making capital cost equal to about $5 billion) do the benefit-cost ratios that are calculated using a mixed domestic and foreign alternative fall to levels as low as the results for TAP at the lower end of the spectrum of capital cost and the Alyeska production schedule. If costs have not been understated, the Trans Canadian pipeline alternatives always have greater or equal benefit-cost ratios than the Trans Alaska pipeline alternative in all but one case.

Footnotes at end of article.

TABLE 4.-BENEFIT-COST RATIOS (CONSERVATIVE PRICES) FOR TRANS CANADIAN ALTERNATIVES TO CHICAGO AND TRANS ALASKA PIPELINE TO LOS ANGELES AT A 10 PERCENT DISCOUNT RATE

1 Similar benefit-cost ratios for New York can also be calculated. For without the cost appreciation case, the following ratios would result: 3.55, 3.02, 3.11, 2.62, 3.18, 2.74, 2.78, and 2.38. Note that the 3.55 for New York is based upon the same assumptions as the 4.18 for Chicago. If the benefit-cost ratios for an Alyeska schedule are important, they are approximately equal to the accelerated after a 2-year delay ratios shown in this table.

That one exception occurs when the lowest of TAP's capital cost estimates is compared with the highest capital cost estimate for AHP.

In Table 5 an index is presented which is easier to use for comparison purposes. It is the net benefit estimate based on average capital cost for the three main routes: the Mackenzie Valley (MVP), Alaska Highway (AHP), and Trans Alaska (TAP). The first conclusion that one must draw from this comparison is that in all cases, including AHP, with a two-year delay and 20% increase in costs, the net benefits exceed, and in some cases by a factor of about two-thirds, similar estimates for the average TAP computations which are presented. A second significant difference revealed by this table is the greater net benefits of about one-half a billion dollars in present value in 1971 of a Mackenzie Valley Route (MVP) compared to the more southerly Alaska Highway route (AHP). The difference is the amount that any environmental advantages attributed to AHP would have to equal or exceed (in the sense of a discounted time stream of environmental cost differences), in order for AHP to be preferred over MVP.

While the previous two tables show that the social value or net benefits of each Canadian alternative exced comparable TAP estimates, it is important to note the fact that the state's revenue and oil company profits will generally not be affected by the adjustments to real costs and benefits which were made when domestic alternative sources of supply were included in the analysis. Therefore, whether or not "real" benefits are adjusted to reflect these differences will not affect the "financial" desirability of each alternative.28

The conclusions to be drawn are quite clearcut. First, the present value of benefits to the nation if TAP is buil are considerable. They equal about $3 to $6 billion. Accordingly, foregoing production due to environmental damage must equal or exceed this amount. However, since an environmental comparison led us to conclude that two all-land routes through Canada were superior Footnotes at end of article.