Trans Mountain pipeline—B.C.’s NDP government should put safety first

Pipelines are 2.5 times safer than rail for oil transportation.

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Safety First: Intermodal Safety for Oil and Gas Transportation

A contentious road lies ahead for the construction of three recently approved oil pipelines (Trans Mountain, Line 3, and Keystone XL). Given continued opposition to oil and gas infrastructure, we have examined the latest data on the safety of oil and gas transport. In general, the transport of oil and gas is quite safe by all modes we examine: pipeline, rail, and tanker, though there are differences between the modes that should be considered when developing infrastructure.

Pipelines suffer few occurrences (accidents and incidents) given the amount of oil and gas that is shipped through them. Overall, between 2004 and 2015, pipelines experienced approximately 0.05 occurrences per million barrels of oil equivalent (Mboe) transported.

When petroleum and natural gas goods are evaluated separately, we find that the transportation of oil results in fewer occurrences than the transport of natural gas. Indeed, transporting petroleum products by pipelines resulted in approximately 0.04 occurrences per Mboe compared to 0.07 for natural gas products. This means that the rate of occurrences for transporting natural gas products was 1.67 times greater than the rate of occurrences for petroleum products.

The focus on the occurrence rate only tells part of the story for pipeline safety. In addition to having low occurrence rates, almost 70 percent of pipeline occurrences result in spills of less than 1 cubic metre (17 percent result in no spill). Only 17 percent of pipeline occurrences take place in the actual line pipe, meaning that the vast majority of spills occur in facilities that often have secondary containment mechanisms and procedures. The results were similar for rail, where the transportation of oil was found to result in fewer accidents per Mboe transported than natural gas. Also similar to the data on pipelines, most rail accidents occurred in facilities rather than in transit.

While both pipeline and rail transportation of oil and gas are quite safe, when comparing the two modes of transportation, pipelines continue to result in fewer accidents and fewer releases of product, when taking into consideration the amount of product moved.

Specifically, based on petroleum product transport data from 2004 to 2015, pipelines were 2.5 times less likely than rail to result in a release of product when transporting a million barrels of oil. This study also evaluated marine tanker safety in light of the additional oil tankers that will result from the expansion of the Trans Mountain pipeline.

Since the mid-1990s there has not been a single major spill from oil tankers or other vessels in Canadian waters. One recent study conducted by the federal government on marine oil spill preparedness estimated that a major spill of over 10,000 tonnes was exceedingly rare and likely to only occur once every 242 years. Likewise, a spill of 100 to 1,000 tonnes is expected to occur once every 69.2 years.

Marine safety has also improved dramatically since the 1970s. For example, when comparing the number of spills in the 1970s to the 2010s (up to 2016) using international data, the number of spills between 7 and 700 tonnes has decreased from 543 to 35 and in this same period the number of large spills (>700 tonnes) has declined from 245 to 12. The amount of oil spilled has also dropped dramatically, falling from three million tonnes in the 1970s to only 39,000 tonnes in the 2010s.

In addition, compared to pipelines and rail, marine tanker transport is found to result in the fewest number of accidents per million barrels of oil transported.

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Global Petroleum Survey 2016

This report presents the results of the Fraser Institute’s 10th annual survey of petroleum industry executives and managers regarding barriers to investment in oil and gas exploration and production facilities in various jurisdictions around the globe. The survey responses have been tallied to rank provinces, states, other geographical regions (e.g. offshore areas), and countries according to the extent of such barriers. Those barriers, as assessed by the survey respondents, include high tax rates, costly regulatory obligations, uncertainty over environmental regulations and the interpretation and administration of regulations governing the “upstream” petroleum industry, and concerns with regard to the political stability and security of personnel and equipment.

A total of 381 respondents participated in the survey this year, providing sufficient data to evaluate 96 jurisdictions, which hold 66 percent of proved global oil and gas reserves and account for 75 percent of global oil and gas production.

The evaluated jurisdictions are assigned scores on each of 16 questions pertaining to factors known to affect investment decisions. These scores are then used to generate a “Policy Perception Index” for each jurisdiction that reflects the perceived extent of the barriers to investment. The jurisdictions are then sorted into clusters based on the size of their proved reserves, allowing for an apples-to-apples policy perception comparison of the resources that are available for commercialization.

Of the 12 jurisdictions with the largest petroleum reserves, Texas, United Arab Emirates, Qatar, Alberta, and China are the five most likely to attract, or least likely to deter, investment. The five large-reserve jurisdictions least likely to attract investment on the basis of their Policy Perception Index scores (Venezuela, Libya, Russia, Indonesia, and Nigeria) account for 45 percent of the proved oil and gas reserves of all the jurisdictions included in the survey. Alberta is the only Canadian jurisdiction in the group of jurisdictions with large reserve holdings.

In the group of 36 jurisdictions with medium-sized reserves, the 10 that are the most attractive for investment are: Oklahoma, Wyoming, North Dakota, Norway—North Sea, the Netherlands, Arkansas, Norway—Other, Louisiana, United Kingdom—North Sea, and West Virginia. The only Canadian jurisdictions in this group are Newfoundland & Labrador (12th of 36) and British Columbia (18th of 36).

Of the 45 jurisdictions with relatively small proved oil and gas reserves, the top 10 performers are Kansas, Saskatchewan, Mississippi, Utah, Montana, Alabama, United Kingdom—Other, Manitoba, New Zealand, and Morocco. Nova Scotia, Yukon, and the Northwest Territories rank near the middle to the bottom of the small-reserve-holder group. New Brunswick was the least attractive jurisdiction in this group due to its poor Policy Perception Index scores on a number of survey questions.

When the attractiveness for investment is considered independently from the reserve size of jurisdictions (historically the primary focus of this survey), we find that jurisdictions with first quintile Policy Perception Index scores, suggesting that obstacles to investment are lower than in all other jurisdictions assessed by the survey, are almost all located in Canada, the United States, and Europe. According to this year’s survey, the 10 most attractive jurisdictions for investment worldwide are Oklahoma, Texas, Kansas, Saskatchewan, Wyoming, North Dakota, Norway—North Sea, Mississippi, Utah, and Montana. All but three of these jurisdictions—Wyoming, Utah, and Montana—ranked in the worldwide top 10 in the 2015 survey.

The 10 jurisdictions that are least attractive for investment are (starting with the worst): Venezuela, Quebec, Libya, Bolivia, New Brunswick, California, New South Wales, Ecuador, Ukraine, and Russia.

Our analysis of the 2016 petroleum survey results indicates that the extent of negative sentiment regarding key factors driving petroleum investment decisions has increased somewhat in many of the world’s regions. The United States continues to remain as the most attractive region for investment, followed by Australia, which moved ahead of Canada this year. Canada’s fall to the third most attractive region in the world for investment is reflective of Alberta’s continued deterioration, as investors continue to view the province as less attractive for investment.

Delaying pipeline projects leads to economic loss for Canadians

With pipeline access to ports, Canadian-based companies could sell crude oil at higher prices in overseas markets than in the U.S.
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The Costs of Pipeline Obstructionism

This paper reviews how Western Canadian oil producers are being con­strained by the inability to access new markets via ocean ports and how this constraint, along with the drop in oil prices, the Alberta ceiling on greenhouse gas (GHG) emissions in oil sands operations, and regulatory obstacles are affecting pipeline infrastructure requirements and decisions.

Western Canadian conventional and non-conventional (i.e., oil sands) heavy crude oils continue to suffer from price discounts relative to world region crude oil prices such as North Sea Brent (adjusted for quality differentials and transportation cost), and are at risk of being displaced by increasing US oil production. Access to port facilities on the west and/or east coast would allow Canadian producers to access world crude oil prices.

If Canada were able to export 1 million barrels of oil per day to markets accessible from ocean ports—with the lion’s share of heavy oil and bitumen exports continuing to flow to US oil markets—substantial incremental rev­enues could result. At a US$40/bbl price this could be as high as $2 billion per year (in Canadian dollars) compared with selling into the flooded US market. At an average price of US$60/bbl, it could reach CA$4.2 billion; and at US $80/bbl, CA$6.4 billion. If higher netbacks from markets accessed from tidewater connections were realized by all Western Canada heavy oil production, at the US$40, US$60, and US$80/bbl price levels the annual benefits could reach CA$8.9 billion, CA$18.5 billion, and $CA28.2 billion, respectively.

Both the oil price and the volume of production drive the Alberta and Saskatchewan crude oil royalty formulas. The importance of the price factor is underscored by the impacts of much lower prices on royalty revenues. In the Alberta October 2015 budget, royalty revenues were projected to plunge to $1.5 billion in 2015–16 from $5.0 billion. Royalties from conventional oil production were estimated at $0.5 billion compared with $2.2 billion in 2014–15 (Alberta, 2015a). Saskatchewan’s February 2016 Budget Update projected oil royalty revenue of $347.9 million in fiscal 2015–16—38.5 per­cent less than previously (Saskatchewan Ministry of Finance, 2016a).

Understanding the sensitivity of royalty revenues to price changes allows governments to predict how revenues will be affected by improved prices as, for example, access to new markets is achieved. Oil royalty revenues in Alberta and Saskatchewan would increase by about CA$1.2 billion a year if the WTI oil price were to increase by US$7/bbl. A US$5/bbl increase in the price of WTI crude oil would increase Saskatchewan’s annual royalty revenue on heavy oil production by approximately $29.5 million, and total oil production royalties by about $94.5 million (assuming an exchange rate of 71.5 cents per Canadian dollar).

The capacity to transport crude oil to coastal refineries is insufficient to solve the pricing dilemma that western Canadian oil producers face due to heavy dependence on the US mid-continent region. Oil pipeline projects with a combined capacity of about 4 MMbpd (million barrels per day) have been proposed or conditionally approved. But investors may be less inclined to move ahead with oil sands and related infrastructure projects than before the downturn in prices.

With no reduction in GHG emission rates, the 100 Mt limit on GHG emis­sions from oil sands operations will be reached in 2025, at which point total oil sands production is projected to increase by 1.5 MMbpd. If, as the NEB has suggested, Western Canadian conventional oil production will then have peaked, the required increase in pipeline takeaway capacity will be about 1.9 MMbpd (assuming a system capacity utilization rate of 80 percent). Clearly, without significant reductions in oil sands GHG emissions rates, much of the proposed increase in pipeline capacity from Western Canada will not be needed.

The Energy East Pipeline, the Trans Mountain Pipeline Expansion, and the Northern Gateway Pipeline project would enable about 2MMbpd of Western Canadian crude to access coastal US and overseas markets. But all three proj­ects face serious challenges, mostly environmental, from First Nations, and from various communities. Further, the federal government has imposed new consultation obligations and upstream GHG emission assessment requirements on the Energy East and Trans Mountain projects that will prolong the review process.

Every effort should be made to expedite pipeline project review and assess­ment processes before windows of opportunity for access to new markets are largely pre-empted by competitors. If the legislated regulatory review process with regard to a particular project is unduly delayed, the federal government may need to help resolve impasses or, in the case of projects that are truly in the national interest, introduce special legislation to allow a project to proceed.

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