Case Study - Interlocking Regulatory Authorities
In 1978 Congress passed the Natural Gas Policy Act. This act called for rolling deregulation of most U.S. gas by 1/1/85. During this interim period U.S. gas was (1) allowed to escalate at inflation plus an incremental factor; (2) certain gases, e.g., deep "incentive" 107 gas, were deregulated immediately; and (3) all gas was allowed to increase by at least the general rate of inflation (CPI).
With most U.S. gas prices fixed below the market-clearing price, domestic shortfalls developed. Foreign gas supplies were not subject to the NGPA. The PG&E service area was linked to Alberta producers by the Pacific Gas Transmission (PGT) Company's pipeline. Gas was gathered in Canada for PGT by Alberta and Southern Co.
A complex international regulatory overlay governed the sale of gas from the wellhead (domestic or foreign) to the burner tip. At the apex of this structure was the Canadian National Energy Board (NEB). This entity set the Canadian border price. The U.S. Economic Regulatory Administration (ERA) approved import prices. The concept of oil price equivalency was established by the Duncan-Lalond Agreement. The Federal Energy Regulatory Commission controlled U.S. regulated wellhead prices and interstate pipeline rates. The California Public Utilities Commission (CPUC) set burner tip rates by customer class for various California service areas.
The Canadians were clearly price seekers, analogous to the pre-
oil embargo OPEC countries. The very threat of an oil embargo
provided OPEC with sufficient information to raise prices and
attempt to set output quotas. The NEB spoke for all Canadian
producers and thus acted as a stabilizing force on the Canadian gas
cartel.
.
How to negotiate? This was the question being asked on both sides of the border. The basic game rules were set early on by the two governments, under the Duncan-Lalond Agreement; namely
A convergence process was taking place. Canadian prices were
falling and would continue to fall, while U.S. prices would
increase. The exact end point in this game was not clear. It
depended on many factors such as
The upper boundary for one (marginal) Thousand Cubic Feet (MCF approximately equals MMBTU) of Canadian gas to sell into a deregulated U.S. market was the deregulated (1/1/85) domestic U.S. market clearing price. The U.S. domestic natural gas supply curve was positively sloped. With imports, and a fixed border price, the aggregate U.S. supply curve (foreign and domestic) was positively shaped up to the fixed (regulated ) price and thereafter it was vertical and then horizontal at the established border price set by the NEB with ERA concurrence. However, if the fixed price rose above the wealth maximizing constraint (export revenues = price x quantity of natural gas exported) established by the NEB, it was theoretically possible that the Canadians could price below the U.S. regulated rate. Under this scenario, the aggregate U.S. supply curve would be positive up to the border price and thereafter horizontal over the range of Canadian exports. After that, the aggregate U.S. supply curve would then be positively sloped.
Tables 1 and 2 show acquisition costs and volumes by PG&E from their various supply sources during this period. The present worth, using a 6 percent discount (capitalization) factor in 1995 dollars for the difference between Canadian natural gas and U.S. gas acquisitions amounts to approximately $US6 billion. This calculation is demonstrated in Table 3. That is not the total export value, but the difference between importing Canadian gas at Canadian prices as compared to importing the same gas at U.S. prices. Gas is fungible. The approximate $6 billion represents the primary (negative) impact. Applying foreign trade multipliers on service area dollar ($US) outflows would increase the overall negative impact on the service area economy. Exports normally stimulate jobs and local economic growth, while imports have the opposite effect.
TABLE 1
PG&E PAYMENTS ON A $ PER MCF BASIS TO SUPPLIERS
(1978-1984)
1 2 3 4 5 6
YEAR $MCF $MCF $MCF $MCF $MCF $MCF
CALIF. EPNG CANADA AVE. PG&E CAN-EPNG MAX-SAVINGS
1978 1.59 1.35 2.40 1.89 1.05 1.05
1979 1.73 1.79 2.79 2.23 1.00 1.06
1980 2.16 2.30 4.34 3.10 2.18 2.18
1981 2.60 2.57 4.86 3.29 2.26 2.29
1982 3.09 3.54 5.14 4.04 2.05 2.05
1983 3.40 4.02 4.49 4.07 1.09 1.05
1984 3.60 3.98 4.21 3.96 0.61 0.61
TABLE 2
PG&E PURCHASES OF NATURAL GAS BY SUPPLY SOURCE & TOTAL VOLUME
(1978-1984)
TOT VOLS
YEAR % CALIF % EPNG % CANADA TOT % MMCFT
1978 16.70 35.40 47.90 100 699594
1979 17.10 37.40 45.50 100 829361
1980 16.00 43.70 40.30 100 781643
1981 19.50 49.20 31.30 100 835684
1982 18.20 45.40 36.40 100 698166
1983 23.10 36.90 40.00 100 621539
1984 24.00 42.40 33.60 100 690455
YEAR.................... $US1995
1978.........................947,481,193 1979.........................958,625,219 1980......................1,540,038,704 1981......................1,354,266,142 1982.........................867,273,966 1983.........................235,123,814 1984.........................101,290,814 TOTAL...............$6,004,099,140
This phenomenon of pricing disparity for the same product developed somewhat as a result of a complex interlocking of agreements, laws, and regulations. The compromise of the NGPA, in protecting northeastern consumers while allowing southwest producers to more quickly approach market price, was the underpinning of the entire system. Scrapping all U.S. wellhead controls in 1978 would have eliminated the mechanism for institutionalizing Canadian-U.S. gas price differentials and made moot any need for special contractual arrangements to ensure longevity of natural gas supplies.
The Canadians, in the late 1970s, claimed that their natural gas was a national heritage. Capital value theory would suggest that they acted prudently (excluding entering into the uniform price agreement) in their pricing strategy. Their pricing policies were augmented on the U.S. side by some who believed that Canadian producers should be encouraged to sustain long-term natural gas exports to the U.S., with the inducement of premium- priced, long-term contracts. A number of U.S. analysts have argued that such contracts were never called for and that Canadian gas could have been marketed-out (down) from the onset by stronger negotiations on behalf of U.S. consumers. Using a "rolled in" average acquisition cost for the purposes of regulatory rate making may have masked the problem.
Prices are signals, relaying present and future valuations. Consumer-oriented contracts should have reflected future as well as present prices. The Canadians would not have sacrificed their national wealth and economic growth by leaving gas in the ground, especially when the export price was on the threshold of falling. Present income has a higher present worth than future income (near versus far dollars -- especially when a market solution is at hand). Premium-priced contracts with the Canadians were probably as relevant as entering into premium-priced contracts with one food chain to provide an ongoing supply of Twinkies.
YEAR TOT VOLS PCT VOLS Current Dollar Present $95
NGPA $MCF PG&E CANADA Savings Savings-6%
CAN - EPNG MMCFT (%) ($Mil)) ($1995MIL)
1978 $1.05 699594 47.90 352 947
1979 $1.00 829361 45.50 377 959
1980 $2.04 781643 40.30 643 1540
1981 $2.29 835684 31.30 599 1354
1982 $1.60 698166 36.40 407 867
1983 $0.47 621539 40.00 117 235
1984 $0.23 690455 33.60 53 101
TOTAL $6,004
(6.004 Billion $1995)
Students, please research this situation and let's discuss. Check these figure against annual reports. Do you agree with method? Could the Canadians have been marketed out ? Was the NGPA good for the U.S.? For Northern California? Why should capital theory be used in formulating contracts?
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