September 2016, Vol. 243, No. 9
Features
Energy Forecasts Show Urgent Need for Canadian Oil Pipelines
Forecasted growth in Canadian oil production shows new major oil pipelines are urgently needed to deliver energy to domestic and world markets, the Canadian Association of Petroleum Producers (CAPP) announced in its 2016 Crude Oil Forecast, Markets and Transportation report.
CAPP’s report offered a 15-year outlook for total Canadian crude oil production and Western Canadian crude oil supply. Canadian and regional U.S. refining market demand for this supply is examined along with an update on the transportation projects that could deliver this supply to both new and traditional markets.
The report also examines the impact of oil prices and production, and reports the latest regulatory delays in the pipeline approval process, as well as other pertinent developments.
On prices, the report shows average spot prices for WTI crude oil was US$91 per barrel in 2014, and since September 2014, the price has declined by 50%. While acknowledging this period of low oil prices is extending longer than many expected, CAPP still forecasts additional Canadian crude oil production growth of 1.1 MMbpd by 2030. This translates into over 1.5 MMbpd of additional crude oil supplies to be transported to markets. Though a number of pipeline projects are proposed that could serve new and traditional markets, all face challenges and regulatory delays.
“Canada’s energy future relies on our ability to get Canadian oil and gas to the people who need it,” said Tim McMillan, CAPP president and CEO. “Connecting Canadian supply to new and growing markets abroad, safely and competitively, is a top priority.”
McMillan noted Canada’s pipeline network has the capacity to move about 4 MMbpd, which closely matched the 2015 average supply of 3.981 MMbpd. This comes at a time when over 850,000 additional bpd of oil sands supply will be available by 2021.
The 2021-2030 supply from Canada’s oil sands is forecast to grow further, over 700,000 bpd, requiring more transportation infrastructure. This means Canada’s oil supply will soon greatly exceed its current pipeline capacity.
CAPP estimates production of Canadian oil, the total volume of oil before imported diluent is added, will increase 28% over the next 15 years, growing to 4.9 MMbpd by 2030, up from 3.8 MMbpd in 2015. This is 400,000 bpd lower in 2030 compared to the 2015 forecast.
Supply, the total volume after imported diluent is added to production, is expected to rise 37% over the next 15 years, growing to 5.5 MMbpd by 2030. Due to the increase in total volume, all forms of transportation in all directions are needed to get Canadian oil to new and existing markets.
Oil Sands
Canada’s oil sands remain the primary driver for growth in Canadian crude oil production. By 2030, the oil sands are expected to produce 3.7 MMbpd, down from last year’s forecast of 4 MMbpd by 2030. This 3.7 MMbpd by 2030 translates into supply growth from the oil sands of over 1.5 MMbpd.
Western Canada Production
In 2015, Western Canadian conventional production declined slightly to 1.3 MMbpd. This production was comprised of 29% heavy crude oil, 54% light and medium crude oil, and 17% pentanes and condensate. Notably, while both conventional and heavy components reported declines from 2014, pentanes and condensate production rose 20%, or 37,000 bpd, thereby offsetting some of the decline from other conventional sources.
The report noted Canada’s western crude oil supply base is landlocked and separated from the majority of its refining markets by large distances. Most of these supplies are moved by pipelines to marketplaces throughout North America. Rail, trucks and marine tankers have also emerged to play a role in moving discrete shipments when pipelines are at capacity or unavailable. (The accompanying map shows the existing pipeline projects and the proposals for projects that could provide part of the needed additional capacity out of Western Canada as crude supplies grow.)
The Gulf Coast is seen as the most significant opportunity for market growth for heavy Canadian crude oil supplies to markets in North America. Refineries in the region rely on imports primarily from Mexico, Saudi Arabia and Venezuela for heavy crude. Most supplies of Western Canadian crude traditionally moved to the U.S. Midwest but with the recent startup of Seaway Twin and the TransCanada Gulf Coast Extension of the Keystone pipeline, over 1.2 MMbpd of transport capacity was opened up from the U.S. Midwest to the U.S. Gulf Coast.
In 2015, refineries in Eastern Canada processed almost 1.1 MMbpd of crude oil, of which 567,000 bpd originated from foreign sources. This is a potential market for Western Canadian producers. A proposed pipeline that could provide a conduit to this market is TransCanada’s Energy East project that has a start date of 2021.
As to transporting crude from Alberta to the West Coast, the Kinder Morgan Trans Mountain pipeline is the only system serving this market. There is significant interest in building new pipeline capacity to the West Coast where it can be offloaded onto crude carriers to reach California, Washington, the U.S. Gulf Coast and Asia. These include the proposed Kinder Morgan Trans Mountain Expansion with a proposed start date in late 2019 and the Enbridge Northern Gateway with an unspecified start date.
As part of the Northern Gateway project, Enbridge proposes a diluent pipeline that would run from Kitimat, BC to Bruderheim, AB. The proposed capacity of the pipeline is 193,000 bpd, and the last reported in-service date is 2019.
Global Energy Demand
The International Energy Agency (IEA) forecasts global demand for energy, including oil, will grow by 32% by 2040 with over 25% of total demand coming from oil. Demand will primarily be driven by emerging economies in Asia. Canada is sitting on 171 Bbbls of oil reserves, third-largest in the world, and was the sixth-largest producer as of 2015. Yet the National Energy Board reports that less than 1% of Canadian oil is shipped overseas.
“Canada has an important role to play as a global supplier of oil, and we can do it at a standard that far exceeds other producing nations,” said McMillan. “Through technological innovation, world-class regulatory systems and environmental standards that meet or exceed our closest competitors, Canadian oil can be the world’s fuel of the future. But we need the infrastructure to connect Canadian energy to the global economy.”
Demand for oil is forecast to increase significantly in China and India, with combined demand expected to grow by over 10.8 MMbpd by 2040, according to the IEA. These two markets represent almost 84% of the total world oil demand increase for 2014-2040.
Canada alone spent $17 billion in 2015 importing oil from the U.S., Saudi Arabia, Algeria, Angola and Nigeria. For Quebec and Atlantic Canada, this amounts to about 600,000 bpd imported to meet refinery needs.
Canadian Oil Sand Expenditures
A related study by United Kingdom consulting firm GlobalData suggested Canadian oil sands projects will see capital expenditures for 2016-2025 will reach US$40.6 billion.
As with other oil and gas projects that require a high crude price to break even, several oil sands projects have been delayed or canceled over the past 12 months. However, the production of oil sands in Canada is set to continue its path of growth, with plans for six new projects and the expansion of 11, according to GlobalData.
GlobalData suggested this growth will be supported by the size of the resource, the well-established and developed industry in Alberta, and the relatively secure demand for heavy crude oil in the U.S. refining markets
Adrian Lara, GlobalData’s senior upstream analyst, explained, “There is a real opportunity for increasing oil sands refining market share in the U.S. and Gulf of Mexico, as the decline in the production of traditional suppliers of heavy crude such as Mexico and Venezuela leaves complex refineries needing to draw the supply from other reliable sources such as Alberta.”
GlobalData estimated capital expenditure for key planned oil sands projects will total US$82.8 billion, of which US$40.6 billion is expected to be spent during 2016-2025. Key oil sands planned projects are forecast to contribute 715,000 bpd of incremental supply by 2023. Among the major operators, Canadian Natural Resources Limited is expected to lead in liquids production mainly due to its Horizon mining project.
“Producers continue to divest and cut costs preparing for what could be the new normal for crude prices,” said Alexandra Pais, GlobalData upstream analyst. “In this context, the most viable projects are the ones that are already producing and for which a planned phase was already sanctioned or in construction before the oil price fell steeply.”
Cenovus Energy Inc. will lead the way in planned Canadian oil sands projects, expected to operate five – Narrows Lake, Foster Creek Phase G, Foster Creek Phase H, Christina Lake Phase F and Christina Lake Phase G. In addition, Canadian Natural Resources Limited, Husky Energy Inc., Pengrowth Energy Corp. and Suncor Energy Inc., are likely to operate two projects each. GlobalData estimated an average internal rate of return for these expansion projects of 7%.
Of the oil sands projects on hold, Kearl Phase 3 with a capacity of 80,000 bpd and Kearl Phase 4 Debottleneck with a capacity of 45,000 bpd are expected to start operation in 2016 and 2017, respectively.
“Considering a large portion of the initial capital investment has been made, the ongoing profitability of upcoming oil sands projects depends upon operators’ abilities to reduce and contain operating costs,” Lara said. “For new projects, if targeted operating costs between $20-25 per barrel can be achieved, the internal rate of return can improve to anywhere from 10-15% under the current oil price.”
Pais added, “In mid-2016, the West Canadian Select crude price remains below US$35 per barrel. While the breakeven of a new oil sands project without prior investment varies between US$40-60, the breakeven of an expansion phase already in construction such as Foster Creek phase G is around US$25 per barrel. Even with current prices still facing downward pressure, this is a relatively low breakeven that gives expansions an advantage over new projects.”
Cost of Pipeline Constraints
The Costs of Pipeline Obstructionism, written by Gerry Angevine, senior fellow, Fraser Institute and Kenneth P. Green, senior director of Natural Resource Studies, Fraser Institute, explained how Western Canadian oil producers are being constrained by the inability to access new markets through 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.
The report said Western Canadian conventional and non-conventional (such as 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 U.S. oil production. Access to port facilities on both coast would allow Canadian producers to access world crude oil prices.
Moreover, if Canada were able to export 1 MMbopd to markets accessible from ocean ports – with the lion’s share of heavy oil and bitumen exports continuing to flow to U.S. oil markets – substantial incremental revenues could result. At a US$40/bbl price this is projected to be as high as $2 billion per year (in Canadian dollars), compared with selling into the flooded U.S. market.
The report urged every effort 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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