4.2.5.1 Pre-nGPa US Gas Pricing
Until the 1954 Supreme Court decision, US gas prices were unregulated. And until 1954, prices were very low by comparison with competitive fuels. In the early days of US oil exploration, producers had discovered large reserves of natural gas that, in the absence of a national transmission system, lacked market outlet. Prices reflected producer competition for very limited local markets.
The national pipeline system began to take shape in the period immediately preceding World War II. In fact the Natural Gas Policy Act of 1938 was deliberately designed to give pipelines the right of
‘eminent domain’ at the Federal level to enable them to acquire right-of-way without the often cumbersome and contested eminent domain process at the state level.
While pipeline construction was stalled during the war, it resumed in earnest at the end of the war.
The rapid expansion of pipelines began to absorb some of the surplus reserves that had depressed prices. By the time the State of Wisconsin challenged wellhead price regulation in the Phillips case, earlier prices had begun to strengthen (they reached $0.10/MMBtu in 1954 after never having been higher than $0.07/MMBtu before 1952).
The Supreme Court decision, placing wellhead pricing under FPC rate jurisdiction, put that organisation in a very difficult position. Rate regulation of pipelines was based on historic costs associated with investment in individual facilities. But in the oil and gas exploration process, the value of individual investments often bears little relationship to the money invested. A successful discovery may have very low unit costs, but a dry hole has infinite unit costs. In addition, problems of joint costing between unregulated oil and regulated gas posed additional problems.
The FPC took several years to come up with its solution, which it called ‘area pricing’. The price limits were set by the average costs experienced over major areas (South Louisiana, the Permian Basin). The flaw in the system was that it violated fundamental laws of economics. For a fungible commodity, prices are expected to clear when the marginal cost of new supply is equal to the marginal price that the buyer is just willing to pay. The effect of the FPC system was to give both sellers and buyers the same price signal based on historic costs. But in a rising cost environment, the marginal cost required to bring forth new supply should be higher than the embedded cost of the historic supply on which buyers are making their purchase decisions. The net result was a system designed to create shortages – which it did.
4.2.5.2 the nGPa and Partial De-regulation of Gas Prices
When Congress finally addressed the failed experiment in controlled wellhead prices, the prices of alternate fuels had risen substantially as a result of the oil shock. Thus, while Congress accepted in principle the concept of ultimate de-regulation of wellhead prices, it found the transition to full de-regulation to be too disruptive to the consumer. It thus adopted an
33. The right of ‘eminent domain’ refers to the right to take private property (with equitable compensation) for the public good.
117 approach – ‘partial de-regulation’ – that created a series of categories, each with its own price
ceiling. It also extended price controls to the intrastate market.
The composite of the prices of the various categories was designed to cushion the rise increase to customers, but the NGPA addressed the problem of higher marginal prices required for new supply by offering incentive pricing for various categories. While old flowing gas remained ‘forever price controlled’, ‘new’ discoveries were to be price-controlled by their discovery vintage. They were to be completely de-regulated in 1985. One category – ‘high-cost’ gas (such as from very deep wells) was de-regulated immediately. Imported gas was not subject to price controls either.
An unintended consequence of this complex pricing system was to create cross-subsidies between gas that was price-controlled below market clearing levels and de-regulated gas – both high-cost and imported gas. Pipelines that faced shortages showed no price discipline in competing for these de-regulated supplies. During the period, the extent of a pipeline’s ability to cross-subsidise de-regulated gas was given the name ‘roll-in capacity’, denoting how much above market a given pipeline could afford to pay. Figure 26 illustrates the pricing situation during this period (using prices as of August 1982). At that time both imported gas and high-cost gas were selling above residual fuel oil price parity and high-cost gas was actually priced above distillate fuel oil.
Figure 26: Vintage Gas Pricing under NGPA Partial De-regulation Showing the Effect of Cross-subsidising De-regulated Gas (Prices as of August 1982)
Imported Gas Old ‘Flowing’ Gas ‘New’ Gas High Cost Gas
Average wellhead price
Price-controlled Deregulated
categories 8.00
7.00 6.00
5.00 4.00
3.00 2.00 1.00 0.00
$/MMBtu
Distillate fuel oil parity
Low sulphur residual fuel oil parity
Source: Jim Jensen
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4.2.5.3 the Effect of US regulatory Policies on Canadian Prices
One of the major beneficiaries of the cross-subsidy phenomenon was the Canadian gas producer.
Pipelines with shortages had been bidding up the price of Canadian imports – which were not price-controlled – even before the passage of the NGPA. But the NGPA simply locked in the process.
In 1974, the Canadian government, alarmed over the US bidding up of prices for Canadian consumers, established export price controls through a single border price for all exports. Then in 1975, it established price controls for its own domestic oil and gas supplies through the Petroleum Administration Act. Gas prices for Canadian supplies were tied to a netback from price-controlled crude oil in Toronto. But the export price was much higher. Between 1975 and 1980, Canada set the export border price unilaterally.
In 1977, when the Canadian border price was $2.16/MMBtu, Pemex in Mexico negotiated a contract with several US pipelines for Mexican imports at a price of $2.60/MMBtu. The US Administration, alarmed that this contract would set a precedent for a Canadian price increase, disallowed the import contract. Nevertheless, prices continued to strengthen so that by late 1980, when the Canadian domestic price formula provided a wellhead price of $2.60/MMBtu, the single border price for exports to the US had increased to $4.47/MMBtu. In 1980, the US and Canada negotiated the
‘Duncan-Lalonde Agreement’ that provided a mutually-acceptable set of pricing rules.
To administer this system the Canadian government became the sole purchaser of Canadian gas for export at the prevailing domestic price. It then took the economic rent on export sales and re-distributed it through a system called ‘flowback’ that was provided pro-rata to each seller according to his production. This system caused distortions of its own as producers in Alberta competed with one another to create new sales that would increase their shares of flowback.
The system of government-dictated export prices began to run into difficulties in the early 1980s as the US gas bubble surplus began to emerge. With less pressure to acquire new supply, US pipelines stopped bidding for new Canadian purchases. From a peak import level of 28.4 Bcm/year in 1979, US imports from Canada had fallen 25% by 1984.
The final blow to the Canadian wellhead pricing system occurred in 1984 when the FERC issued its Order 380. Its provision that utility buyers no longer had to honour their minimum bill provisions applied to US pipelines purchasing Canadian gas, as well as applying to US LDCs buying US supplies.
In the face of the bubble surplus and the abolition of the minimum bill provision, the Canadian export pricing system was no longer sustainable.
Negotiations between the Canadian Federal Government and the producing provinces of Alberta, B.C. and Saskatchewan led to the Agreement on Natural Gas Markets and Prices on 31 October 1985 – the so-called ‘Halloween Agreement’. This effectively dismantled the earlier price control system, thereby restructuring the Canadian gas industry and providing for competitive market pricing and third-party pipeline access.
As had been the case in the US, the new regulations provided serious take-or-pay problems for the Canadian pipelines. Unlike the US, however, where Congress let producers and pipelines negotiate their way out of the problem, in Canada the NEB stepped in. It made it possible for TransCanada – the biggest victim of the market and policy changes – to finance its take-or-pay
119 obligations and work them off through an allowable pipeline surcharge. The problem was, therefore, nowhere near as disruptive in Canada as it was in the US or in the UK.