We are used to reading news of the Organization of the Petroleum Exporting Countries (OPEC) curtailing production to address low oil prices and, more recently, it acting in concert with Russia to do so. However, when Alberta announced that it would be curtailing production in 2019 by up to 325,000 barrels a day (more than 8 percent of Alberta's total oil production), to be borne by producers with production greater than 10,000 barrels a day, it came as somewhat of a surprise. The cuts are not small on either a relative or an absolute basis, keeping in mind that global oil production is roughly 100 million barrels a day, with Alberta producing approximately four million barrels of that, while OPEC and Russia combined produce approximately 40 million barrels a day.

Alberta has a long history of considering and, in some instances, implementing oil production cuts, although the motivations have been different in each case. In the 1930s, on at least two occasions, the Alberta Government sought to restrain production. In 1950, faced with oil production that exceeded available pipeline space and refining capacity, Alberta's regulator stepped in and mandated maximum allowable production from oil wells. More recently, and most famously, Alberta resorted to legislative authority to curtail production in response to the National Energy Program (1980) (NEP), to address a federal government program that imposed a national oil price for oil consumed in Canada, which was lower than the world price by approximately CA$20 per barrel. One intent of the NEP was to redistribute the economic benefits of Alberta's oil and gas production outside of the province. The threat of curtailing production was sufficient to facilitate executive agreements between Alberta and the federal government on pricing. Alberta cut production by 120,000 barrels per day between March 1 and September 1, 1981, and withheld approval of new oilsands projects. Now, almost 40 years later, we find ourselves in a similar position, with Alberta having announced a proration scheme to address price differentials, this time caused by government intervention in oil pipeline markets. This government intervention resulted from years of persistent intervention by environmental groups trying to stop pipeline development in order to affect government policy changes on climate change. To address the challenges presented to pipeline development, oil and gas producers, acting with the pipeline industry, invested billions of dollars pursuing multiple pipeline options. The first was Keystone XL, followed shortly by Northern Gateway and then Energy East.

Keystone XL was the first pipeline to be delayed and later stopped by a decision of the President of the United States, largely, if not exclusively, as a result of environmental groups successfully employing their climate change strategies. The next pipeline proposal stopped was Northern Gateway, again for political reasons, but this time with the apparent intent on the part of Canadian governments to acquire social licence for the third pipeline proposal, TMX. This strategy of acquiring social licence was fraught with risk, which has now manifested itself. When the Joint Review Panel hearing of the Northern Gateway Pipeline Application recommended its approval, the in-service date for the 580,000-barrel-a-day pipeline was late 2018. TMX was the next pipeline application in the regulatory process and was almost two years behind Northern Gateway. Denying Northern Gateway did not provide the social licence sought. Social licence is an elusive concept, which, in addition to being undefined and not understood, would have never been granted by the parties insisting it was needed in the first place. The opponents of Northern Gateway insisting social licence was needed, continued their fight against TMX and were successful, first, in getting the private proponent of the project to stop construction, and second, after the federal government acquired the pipeline to deal with the first problem, the courts ordered a delay of construction to remedy flaws that were found in the regulatory and consultation process for TMX. Finally, the regulatory uncertainty prevailing at the time, and which continues to prevail, caused the proponent of the Energy East Pipeline to give up on that project after spending CA$1 billion developing it, rather than facing evolving regulatory expectations that would only result in a regulatory approval, which was still considered to be subject to obtaining a social licence.

The measurable financial impact of the NEP would be relatively insignificant when compared to the most recent example of government intervention in the pipeline market. In the case of the NEP, oil prices collapsed shortly after its implementation, making it difficult to ascertain, with any degree of certainty, which of Alberta's economic challenges faced throughout the 1980s were attributable to the NEP. This quantification issue does not, however, exist in the context of pipeline capacity constraints caused by government policy. Both the Alberta and federal governments appear to agree that pipeline capacity constraints are currently costing the Canadian economy (oil producers, the Province of Alberta and the federal government) between CA$80 and CA$100 million dollars a day, which amounts to CA$3 billion a month or CA$36 billion a year.

Stopping pipeline development has proven to be far more costly to the Oil and Gas industry than carbon tax. The lack of pipeline capacity comes out to CA$500 a tonne, when equated to dollars per tonne of GHG emissions associated with Alberta's oil production. For comparison, the federal government's proposal for a carbon tax currently reaches a maximum of CA$50 a tonne.

In the face of these costs, the desire on the part of Alberta to do something is understandable. However, the solution of production cuts to be borne by the Oil and Gas industry does not come without costs of its own, especially where they are not evenly distributed. Beyond the issue of creating a corporate exemption for the first 10,000 barrels a day of production, Alberta's integrated producers, who have invested heavily in building or acquiring, upgrading and refining assets, both in Alberta and throughout the United States, to facilitate development of Alberta's resource, will incur these costs without any associated benefits of curtailment. An approach that socialized the cost of curtailment would have been fairer and could have avoided placing future investments in the development of Alberta's resources at greater risk. In a worst case scenario, mitigating the political risk that created the pipeline capacity problem, and the political risk that manifested itself in the production curtailment solution, could include conditions on future capital investments, such as having governments agreeing not to legislate creative solutions to problems they cause. 

These types of conditions include production and royalty agreements governed by foreign (rather than Alberta) law, with disputes being arbitrated by international bodies rather than Alberta courts. This is common in the case of states that do not have a strong history with the rule of law and the protection of individual rights. It would, however, be new to Alberta. We do not expect it to get to this. Canada has long been viewed as a good place to invest, by virtue of political and fiscal stability, the rule of law and relatively transparent regulatory processes. We do not want to get to the place where the existence of this is called into question to the point where industry players ask, "Can we do projects in Canada any more?"

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