EnergyBC

Resource Value

SFU (2004) noted that several reports have attempted to estimate the economic value of the Queen Charlotte Basin reserves by multiplying median reserve estimates by the market value of oil and gas. They advised that such efforts must be interpreted with caution for three reasons: First, reserve estimates are highly speculative due to a lack of geological data about the structure of the Queen Charlotte Basin and the potential reserves therein. Second, there is no guarantee that it is economically viable to recover the reserves even if do they exist. Third, if the reserves are economically viable, the value of the resource is based on the net value after deducting production costs, not the gross value as estimated.

That said, in 2000 the Maritime Awards Society of Canada produced a report stating that using the GSC's (Geological Survey of Canada) median resource estimates multiplied by October 2000 market prices, economists estimated that the value of the BC offshore oil could be as high as $55 billion (US) and that of the gas at $40 billion (US). The total “downstream” value of the resource, including additional wealth generated in, or attracted to, the province by the presence of the offshore industry could conceivably be close to $500 billion (US). Spread over a 30-year production period or longer, the annual revenues to BC might therefore be as high as $3 billion (US) directly from production and $15 billion (US) in total “downstream” benefits (MASC, 2000).

These projections (Year 2000), though speculative, would make offshore oil and gas production the second largest industry in the Province behind tourism at $8.3 billion (US) annually but ahead of logging and forest products ($2.2 billion US), mining ($1.8 billion US), agriculture ($0.8 billion US), and fishing ($0.2 billion US). Offshore hydrocarbon development in BC could contribute up to 14% of the provincial gross domestic product (GDP). These figures assume that offshore resources would be used as a fuel in the conventional manner. Some argue that these resources should be applied to non-fuel purposes such as plastics and other sectors of the chemicals industry, or in the case of natural gas, serve as the basis for fuel cell technology.

Revenue Streams

One of the major sources of revenue derived from offshore oil and gas production comes from royalties. Marshall (2001) describes how in Newfoundland, royalties paid to the provincial government are divided into a statutory royalty and a contractual royalty. The statutory royalty equals one cent per barrel of oil produced, which would yield $7.7 million over the duration of the Hibernia project. Contractual royalties entail a basic royalty and a net royalty. The basic royalty is paid on the sales revenues minus the transportation costs, with the percentage paid increasing from 1% on the first portion of oil to 7.5% on the last portion. Royalty percentages are indexed to the price of oil. Even when ignoring transportation costs and discounts for oil prices below US$30/barrel, the basic royalty will total CAN$1.5 billion over the life of Hibernia. Net royalties will only be paid if the project’s revenue exceeds its eligible costs.

It is unlikely that BC would agree to a royalty structure similar to that in Eastern Canada. Former Fisheries Minister and Newfoundland MP John Crosbie recently published a review of the Atlantic Accord that was negotiated between the federal government and Newfoundland almost 20 years ago. In it he is quite critical of the revenue sharing agreement that was negotiated, as much of the royalty revenue (up to 80%) accrued by province is negated by the reduction in equalization payments from the federal government.

Another source of revenue for the federal and provincial governments are in the form of taxes. Both the provincial and federal governments collect personal income taxes from Canadians and some Non-Canadians who work on the various projects in Eastern Canada. In the case of property taxes, in 1999 the Alaskan government received $350 million in taxes from offshore companies (Alaska Oil and Gas Association, 2001). There is also the matter of corporate taxes levied on offshore operators and associated industry contractors. However, taxes are sometimes exempted for some companies in an effort to encourage investment and development, as was done in the case of Hibernia.

Investment

The potential revenue from a BC offshore development must be weighed against the amount of investment required by private and especially public sector sources. As estimates for quantities of oil and gas are still speculative, any investment scenarios must also be. A study by Royal Roads University (2004) of a BC offshore scenario assumed a limited production volume with operations similar to Cook Inlet in Alaska due to the physical similarities of the basins. Investment required was estimated at $1.3 Billion for the exploration and development (construction) phases. Annual operating cost estimates were $42 million/year. The study did not postulate on what level of investment would be required from the federal and provincial governments. This is important given the previous experience with the Hibernia development in Newfoundland.

The Hibernia development was intended to be constructed and operated without government money (Marshall 2001). In the end, the project relied heavily on government grants, loan guarantees and tax exemptions. Most of the subsidies from the Newfoundland government came in the form of tax exemptions. The provincial government first waived the 12% sales tax on start-up capital costs and as the project neared completion, the provincial sales tax on the operating expenses was waived as well. Hibernia Management Development Corporation (HMDC) received a tax credit on corporate income tax payable to the province. No retail sales tax was paid on a transshipment terminal constructed in Placentia Bay. Finally, a fuel tax exemption was granted to both the Hibernia project and the Terra Nova project.

Marshall (2001) continues, explaining that Newfoundland also collaborated with the federal government to offer grants and subsidies to the project. Under the Offshore Technology Transfer Fund, the Newfoundland government provided the project with $11 million to ensure that Newfoundland engineers were hired to design the offshore structure. Through the Canada-Newfoundland Offshore Development Fund, the two levels of government subsidized the Bull Arm facility where the offshore drilling structure for Hibernia was built by up to $95 million. In 1988, when the low price of oil put the entire Hibernia project at risk, Mobil Oil obtained a $1.04 billion grant from the federal government along with a $1.66 billion loan guarantee.

In 1992 another investor was required in Hibernia when Gulf Canada Resources Ltd. pulled its 25% share out of the project. The federal government purchased an 8.5% share for nearly a billion dollars and guaranteed over $700 million in loans to Murphy Oil Corp. from Arkansas so that it could pick up a 6.5% interest. Shrimpton (2004) critiques Marshall's (2001) assessment, pointing out that while these loan guarantees were made to protect the companies from the financial risks associated with development, no disasters or major financial losses have fallen upon the project. In fact, in the long term, the federal government's equity ownership in Hibernia has yielded it substantial financial gains, and will continue to do so for many years. Marshall (2001) concluded that all the subsidies highlighted the vulnerability of a project dependent on global commodity prices. This dependence was later demonstrated once again by an interest-free loan extended by the federal government for as much as $300 million to help oil companies make interest payments whenever the price of oil drops below US$25/barrel (in 1987 dollars).

Some credit from above text to Review of Offshore Oil and Gas Development by Simon Fraser University, 2004 and Royal Roads University: BC Offshore Oil and Gas Socio-Economic Papers, 2004