Month: May 2015

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Introduction

Long a continental supplier to the world’s erstwhile largest energy consumer (China passed the US in 2012), the Canadian oil and gas sector has been secured by the principle of “Alberta makes and the US takes.” However, this energy future has all been called into question by the plunge in global oil prices and the resulting “new normal” operating environment. Can it remain that by the end of this decade, Canadian oil and liquefied natural gas (LNG) will begin to flow away from the increasingly saturated US market to offshore markets, primarily in the high growth Asia-Pacific region?
The how and where of this assertion remain the most important questions. Options for export exist on all four coasts- Pacific (BC, Oregon), Atlantic (Quebec City and St John’s), US Gulf Coast (re-exports of Canadian imports), or even to the north via Alaska or Churchill/Hudson’s Bay. Each option has cost and risk and has been, and will continue to be, debated and evaluated.
When Canada will begin to shift oil and gas exports away from the US and towards growing emerging markets remains to be seen, especially in today’s new operating environment. In November 2014 at OPEC’s ministerial meeting, the oil cartel under Saudi Arabia’s leadership signaled a dramatic shift from its traditional role as global oil swing producer and instead decided to focus on retaining market share. The move sent prices plummeting by over 50%, from a 2014 peak of $115 per barrel for Brent in June to a low of nearly $50 in January 2015. Currently, prices remain depressed, ranging in the mid to upper $60’s, yet there is downside near-term risk for oil markets from significant factors such as continuing oversupply from producers other than the US and major geopolitical supply-shock events such as the Iran nuclear deal. As such, prices are likely to remain very volatile for the next couple of years.
Regardless, and especially in the longer-term, Canada’s oil sands reserves are too valuable to leave in the ground and failure to find some route to market would be a failure of both public policy imagination and market forces of epic proportion. What underpins this view is a world in which strategic, world scale oil development opportunities are in short supply, regardless of prices, while petroleum demand continues to grow, albeit not at the torrid rates of 2002-2008.
Natural gas/LNG exports remain a more tenuous scenario, but more in terms of timing. Even if the world energy industry determines BC’s LNG plays to be marginal at the present time, the double-digit pace of annual demand growth for natural gas in Asia means LNG in BC will move forward eventually. However, due to mounting commercial constraints, intense environmental opposition, increased global competition and weakened market conditions, significant export volumes from Canada’s west coast projects are now most likely aiming for a post-2020 timeframe.
Of course, for these scenarios to emerge, industry and government cannot just stand still and wait for things to happen. The familiar but intractable – so far- challenges of infrastructure/market access and social license to operate on First Nations and GHG emissions will need to be overcome. Canadian voters will have a chance to judge the effectiveness of the current government’s efforts on these fronts come October 2015, while the opposition parties must demonstrate to a skeptical electorate and industry that they have better ideas and solutions.
As a non-partisan institute, Canada 2020 and the author offer these ideas to all interested parties with the express hope that we can play some small role in helping Canada realize its global potential as a competitive and responsible energy power, with all the benefits that would entail not just for Western Canada but for the country as a whole.
Meanwhile, capital markets and international oil companies around the world will be watching too. There is no where they would rather do business than in Canada- including many of their home countries- if we can finally overcome the obstacles of the last decade. However, in a lower oil price environment, industry will be even more sensitive to cost and risk-averse in terms of policy uncertainty around market access and public acceptance.
We also challenge government and industry to think ahead to the risks and opportunities that await once our hydrocarbons exports reach global markets. Will there be the expected windfall that appears to be there today- or will global markets evolve with new suppliers emerging and changing demand patterns that will diminish the prize? The world is not standing still while we figure out our own internal challenges. The export markets we covet are also being targeted by a wide array of competitors, many with geological and geopolitical advantages that we lack. While we bring many assets to the table as well, we must seek to understand and plan for the global energy landscape that is emerging. Part of this understanding must account for growing concern about climate change not just among environment activists, but among governments, corporate executives, and institutional investors.

1. The Oil Sands

They are big. They are costly. They are unpopular (most places outside of Alberta, Bay Street, and Houston). But unless and until there is a massive transformation in oil-dependent global transportation systems, they are irreplaceable. The world needs about 92 million barrels a day of oil to match demand. Even the most bearish forecasts predict 1% annual demand growth, or roughly just over another million barrels a day, per year, for the foreseeable future. If (and a big “if” because demand could just as easily exceed, rather than miss, these forecasts) demand slows, we still likely need about 110mmbpd of global liquids (oil, biofuels, etc.) by 2035. Moreover, the world’s existing oil fields have a natural production rate decline between 3 and 10% a year, depending on whose numbers you use, the countries included and the type of production you are talking about. So the replacement rate to add the incremental 18mmbpd is likely double that, once declines are accounted for.
This is generally understood but the implications perhaps are not fully appreciated. If these numbers- which again are considered conservative by many of the world’s leading government and private sector forecasters- are right, then the denial of Keystone XL or Northern Gateway, the introduction of a $30/ton carbon tax, cost challenges in labor and materials markets, and hesitation about allowing open access to investment by state-owned enterprises won’t matter. The oil sands will be developed.
There are not enough other sources of accessible oil- low cost, medium cost, or high cost- to keep up with growth.]. High cost oil from Alberta (and a number of other places) will effectively set a price floor once again as demand and decline rates eventually overcome the current market imbalances. Even if our efforts to build coastal pipelines fail, the resulting discount in the Alberta heavy oil price would likely be steep enough to incent US and Canadian refiners to build new refineries that are equipped to process our output. A new market would be created and barrels from Mexico and OPEC countries would go elsewhere.
The main underlying argument against Keystone XL from leading environmental groups acknowledges much of this but states that the denial of the project would represent both a stop to “unbridled” development of oil and gas resources without concern for future climate change impact, and a start to a new era where public policy prioritizes the development of non-hydrocarbon resources. So far no government has accepted either proposition without at least massive hedges, caveats, and conditions. There is too much risk politically in switching from the fossil fuel world of the near term to the post-hydrocarbon world of well, sometime, but the sometime always seems beyond the next election.
The most likely event to “kill” the oil sands and trigger a new era of non-hydrocarbon development would be peace breaking out in the Middle East- a losing bet since 1967. In the short-term, a lifting of Iranian sanctions in the aftermath of a deal between Teheran and Washington could worsen the current surplus in markets and lower prices this year. But the upside in new Iranian production would be limited and take a long time to materialize. Conversely, a catastrophic geopolitical event in the Persian Gulf, regardless of the likelihood of a nuclear deal with Iran, could have the same effect, in that it would spike prices in the short term but force major Western and Asian consumers to take action to begin to shift the transport sector from petroleum to other fuels, through onerous taxation and massive subsidy of alternative transport. A disruptive technology to displace the internal combustion engine could do the same and do to the auto/oil complex what the internet has done to Canada Post, record companies, and the print media.
Finally, despite the upset victory by the New Democratic Party (NDP) in Alberta elections in May and raised industry concerns about the prospects of a negative policy environment for the oil sands, weak market conditions and heavy economic dependence on the energy sector will limit both the risk of a royalty hike as well as the size of a potential increase.
The biggest risk for industry in Alberta from the NDP government will probably be a new carbon policy, where the government will likely pursue a more aggressive pricing mechanism while aligning provincial carbon policy with other Canadian provinces. BC already has a carbon tax, Quebec has a cap-and-trade system, and now Ottawa has announced a federal pledge (to the United Nations as part of the Paris climate change talks in December) to cut Canada’s greenhouse gas (GHG) emissions by 30% by 2030. The new NDP government in Alberta will likely argue that a more proactive and aggressive approach on carbon will bolster public and international acceptance of the oil sands, facilitate pipeline projects like Keystone XL, and finally help avoid contentious fights over issues like the European Fuel Quality Directive and California Low Carbon Fuel Standard. This strategy is also being advocated in a similar form by national Liberal Party leader Justin Trudeau and will play out in October’s federal election.
In conclusion, all of the above scenarios and risks to continued oil sands development are significant and bear monitoring closely. Industry’s ability to adapt to a lower price environment and effectively manage stakeholder relations has never been more critical. A complete shutdown of longer-term oil sands development fits into the category of “possible” but not “probable.” Public policy and corporate strategy should emphasize the probable while not losing sight of the possible, from the perspective of risk management.

2. LNG

On the LNG side, Western Canada is watching its “baseload” export market disappear as the US capitalizes on its booming natural gas domestic production. US projects are also taking the lead in the export race due to low costs and a streamlined regulatory approval process, which will likely yield its first LNG exports towards the end of this year from Cheniere’s Sabine Pass project. Nonetheless, Canadian industry optimism remains tethered to the spate of LNG projects along the BC coast, none of which is actually under construction or have received final approval from their developers. Asia’s robust gas demand growth (much more material than comparable numbers for oil) is a magnet for “stranded” gas resources in northeastern BC that are no longer needed in the US or Eastern Canadian markets. Yet that same “magnet” is a powerful signal to every other potential gas play in the world- all roads in the global gas market lead to Asia. BC is competing with the US, Russia, East Africa, Central Asia, and Australia to supply Asia with gas. Giant Persian Gulf producers like Qatar may opt to increase supply in response to demand, while dormant mega-reserve holders like Iran and Iraq also loom as medium to long term alternatives.
Canada can compete in global LNG markets but we are unlikely to be the supplier of choice due to high costs from commercial challenges and labor shortages. Of the 19 currently proposed LNG export projects in BC, a front-runner has been Petronas’ Pacific Northwest (PNW) LNG project, especially in light of the recent offer of over C$1 billion in incentives to a First Nations group for its consent. Despite the high level of commitment signaled by the offer, the First Nations group has rejected the agreement which will likely delay the project’s progress as well as set back an FID decision. While the setback will deal a broader blow to BC’s LNG ambitions, other projects are unlikely to face the same intense degree of environmental opposition. In fact, the BC government has made notable progress in striking revenue-sharing agreements with 28 First Nations groups (out of 35 with which the government is negotiating) over LNG projects, including bands around upstream operations in northern BC and along pipeline routes to planned liquefaction terminals. Overall, the setback for PNW LNG adds another layer of risk for Canadian projects, especially those that are already struggling to get off the ground amid increasing costs and weakening market conditions.
Despite this, two or more BC LNG projects will likely be built-eventually.. In the near-term, a silver lining for the province’s LNG industry could be the more promising outlook for smaller-scale, floating projects which will likely drive Canada’s LNG export potential for the next few years as larger projects continue to struggle with investment commitments and commercial costs.
As such, developers around the world will look to lower cost projects first (the US primarily but places like Papua New Guinea and Qatar as well) but will move on Canada once the expected demand emerges in Asia. Canada’s rule of law and proximity to northeast Asia will be attractive for investors.
The core challenge is whether the industry timetable matches the needs of the BC and Alberta governments. The BC government has promised a lot to the public on the fiscal windfall from LNG, promises that were premature and under-estimated the price sensitivity of these projects and the availability of alternative investment destinations.

3. Strategy

Given the challenges above, what strategy makes sense for the oil sands and Canadian LNG going forward? Is there a role for public policy? The role of the federal government, in our view, is likely to become more important in the very near term- despite industry, provincial and government aversion to “national energy policy.”

Government should take more risk in stakeholder engagement to build a cohesive national energy strategy

This is a call for more action and less talk on two fronts. First, no one is quite sure what to do with First Nations opposition to West Coast pipeline and LNG export projects. Many voters and investors are unsure exactly what the problem is.
The solution here is two-fold. First, clearly define what is required under the principle of “duty to consult” with First Nations groups along the pipeline corridors. The government should state what that process looks like- where it begins and where it ends. The government should also clearly state what sovereign rights it is prepared to assert once the newly-clarified duty to consult process is complete. This should not be left to the provinces, or worse, to industry, to have to explain. The Western provinces and industry are not neutral actors in this process despite best intentions and Ottawa must define and defend its standards. Ultimately such standards would be reviewed by Canadian courts but a clarification of intent by the legitimately-elected government in Ottawa would be helpful. Such a clarification, in the eyes of many oil patch industry leaders, should simply confirm that the granting of a public interest determination by the National Energy Board with follow-on approval by the federal cabinet does in fact constitute a “social license to operate.” While such a confirmation may seem unnecessary, it would put an end to the growing view that there is an additional, open-ended, multi-stakeholder process of negotiation that must follow any NEB determination before work can begin.
Once Ottawa has unambiguously and clearly stated its approach and timelines on First Nations consultation, the Prime Minister should then decide whether or not these projects are in the public interest, once conditions around economic benefit and environmental safety are in place. In the context of the Northern Gateway project decision confirmed by the federal cabinet in 2014, it is quite evident that the NEB process was simply the beginning of the process but not the end, as once intended in the 1959 National Energy Board Act. Given this reality, the Prime Minister should then facilitate and lead a dialogue between industry, provinces, and First Nations to reach a commercial agreement with a fixed clock time period for negotiation.
The government can determine that the First Nations have an effective veto either through a de jure “high bar” definition of duty to consult, or through a stated unwillingness to enforce pipeline approvals through the sovereign authority of the government. While such a policy would be unpopular in the oil and gas industry, it would at least clarify what the actual protocol is for energy infrastructure development and force project developers to account for First Nations “buy-in” much more aggressively and earlier in the planning cycle.
The government can also determine that there should be no de facto veto by First Nations groups (or provincial/municipal governments) once the duty to consult has been completed and a public interest determination has been made. It would then also need to declare that it will back the public interest determination with the force of the law. Obviously, this would be the preferred position of industry, to know that the duty to consult standard is high and must be met, but once it has been the government will enforce its permitting decisions as it routinely does in the building of public works projects.
Fairly or not, the current perception in industry is that no one knows which of the above two positions are held by the government or either of the opposition parties. Certainly, it is risky for any of the three parties to take a strong stand in either direction. But it is worse to have ambiguity- it doesn’t serve the interest of the First Nations or of industry and has created little more than a regulatory logjam.
Many elements of the above also apply beyond the First Nations, whether in Burnaby where the local government opposes the TransMountain pipeline expansion, or in Ontario and Quebec in regards to development of TransCanada’s Energy East pipeline project. Ultimately, the national public interest must be reconciled with local opposition.
The same risk-taking approach should also apply to climate change policy. The current government has recently pledged to cut the nation’s GHG emissions by 30% by 2030, slightly higher than the US’ pledge of a 26-28% reduction by 2025. The pledges are being made by individual countries to the United Nations ahead of the climate talks in Paris this December. The federal government has also promised to propose new regulations on methane emissions from the oil and natural gas sectors, producers of chemicals, and gas-fired power plants. However, the Conservative government as still opted not to move ahead with GHG regulations for the upstream oil and gas sector. The resistance appears to be driven by two factors. The first is an apparent distaste in some quarters of the government, particularly in the caucus, for GHG policy stemming back to the devastating attacks on Stephane Dion’s “Green Shift” program in the 2008 election. In fairness, that has not prevented government from taking action on emissions from power generation or heavy-duty trucks, but nothing yet on upstream oil and gas.
The second and likely more material cause for the delay is a desire to align the Canadian regulations with the US system. This seems smart at first glance given the vast amount of cross-border trade of commodities and manufactured goods and concerns about putting Canadian projects at a cost disadvantage. Yet the US carbon policy debate will continue to ultimately be about coal, while ours will ultimately be about the oil sands. The Obama administration’s regulatory approach to reducing GHG emissions in the coal-fired electric power generation sector is not an obvious model for the oil sands. The oil sands industry would prefer a more simple system that allows for flexibility in meeting GHG emissions reduction requirements, through a carbon tax.
We will never know if proactive action on say, a $25/ton carbon tax tied to a 25% reduction in GHG emissions would have pushed the Obama administration to approve Keystone XL, by giving further comfort that the Canadian government has a plan for the climate change effects of the oil sands. Claims that such action would have “guaranteed” the project’s approval are over-stated and under-estimate the impact of the Nebraska and South Dakota-level issues and the strategic political importance of inflows of donations from environmentally-motivated Democrats. The point is we will never know but we might have found out if we had taken the risk of leading on a policy, that may not have been politically popular across the board and might have received some pushback from industry. Such leadership would also help inoculate a host of actors, from European super-majors to California refiners, from political resistance from home governments that feel Canada has not done enough on climate change.
It is noteworthy that four Canadian provinces (BC, Alberta, Quebec, and most recently Ontario) have a carbon tax or cap and trade program. Yet inaction on the upstream oil and gas sector at the federal level undermines the larger climate change mitigation, given the rapid growth of GHG emissions expected as oil sands production doubles or even triples, as some forecasts predict, over the next 20 years. In this context, even a lower rate of GHG intensity will not prevent the overall growth of GHG emissions due to production growth. That is not to say that greater steam-oil ratios (meaning less natural gas burned to create steam for well injection) and other programs such as carbon capture and sequestration cannot be game changers over the medium term. But from today’s perspective and today’s technology, Canada’s GHG emissions will grow with the oil sands as the largest driver.
Instead of meaningful policy action at the federal level to address the concerns, too often our industry and government leaders have tried to match scientific arguments from oil sands opponents with their own scientific studies and analyses. It used to be said that you can choose your arguments but not your facts. That is not necessarily true when oil sands opponents just need to create confusion and uncertainty about the environmental impact of the projects. Even studies from Obama’s own State Department showing Keystone XL would be climate neutral were muddied by other (less robust) studies arguing that developing the oil sands would cook the planet. Oil sands industry leaders have argued (not without merit) that the emissions of the oil sands are dwarfed by a handful of the largest coal power plants in the US. Our government officials and diplomats have pointed to improvements in energy efficiency and carbon intensity in the oil sands. It wasn’t enough. It didn’t work.
Canada needed, and needs, to do something bigger and meaningful, particularly now that the Obama administration has finally released its draft rule for GHG standards on coal-fired power plants. Outsiders don’t understand the primacy of the provinces on energy policy and want to see what Ottawa thinks, and is prepared to do. The carbon tax seems like the best available idea and has been supported across industry, although not by everyone in the oil patch to be sure. The risk is that Canada will move ahead of the US and upstream oil and gas plays in Texas and North Dakota will gain a cost advantage, although that advantage could be offset by a US carbon tax. Or the US could move on policies that do not synch up with the carbon tax approach north of the border, forcing industry to manage two systems instead of one. The reward is that unilateral action would put the ball back in the US court. Talk to industry and decide what price, baseline year, and reduction target we can live with- then go out and defend it against all critics.

Reduce market risk by supporting innovation and a move away from our current status as the “marginal” barrel

With today’s low oil prices, Canada’s position as a high cost producer could, under certain scenarios, become a precarious one again in the future. When oil demand slows and prices fall, the high cost or marginal producers are usually affected first. Projects are put on hold, rigs are idled, and the inflows of taxes and royalties to the Crown dries up.
In 2015 alone nearly one dozen Canadian oil sands projects have been delayed, postponed, or cancelled. This trend though could only be the beginning, especially in light of some analyst forecasts of about 60 new global projects awaiting approval as simply uneconomic at oil prices below $60 per barrel.
How is this likely to play out in the next five years? No one has a crystal ball with respect to oil prices, but there are few “possible” scenarios that are worth considering as they would likely threaten Canada as a high cost oil supplier:

• US/Iran deal on sanctions- a breakthrough on Iran’s nuclear program could lead to a gradual lifting of sanctions. A deal being made by July at the latest is the most likely scenario, which would include relief on oil sanctions. This relief could occur through a “big bang” approach which would free up full volumes of unused Iranian capacity at one point in time. As such, following a deal there would be a period of approximately six months that is likely to yield an incremental initial tranche 600,000 bpd, with around 1 million bpd within one year. While there is clearly capacity loss and the number of Iranian barrels is highly uncertain at this point, it is reasonable to expect that any volume increase would be meaningful while putting downward pressure on already depressed oil prices;

• US liberalization of crude export restrictions- despite the US having a surplus of light sweet barrels that is challenging available domestic refinery capacity, in the context of an oversupplied market with low oil prices, US production growth has begun to slow making the argument to lift the ban less relevant. According to the Energy Information Administration, US production is forecasted to drop in Q3 2015 by 250,000bpd from Q2 before essentially flattening out though mid-2016. Also, Republican lawmakers will become more reluctant to make a strong argument for ending the ban prior to the 2016 presidential elections when it could be used to cast blame on potential rising gasoline prices. For the time-being, any action on crude exports will continue to be focused on the administration’s preference to allow condensate exports under the existing statute. However, post-2016if the political decision to allow this US crude to be exported is made, it will push down the price of Brent oil;

• Reversal of resource nationalism- after watching US, Canadian, and European companies redirect capital to the North American shale gas, tight oil, and oil sands plays, governments like Mexico, Brazil, and even Russia are offering less rent-seeking and more competitive terms to maintain investment. This trend is driven by low oil prices and the continuation of “onshoring”–the trend by which capital inflows target US and Canadian onshore unconventional plays over other markets—and will likely encourage a more coherent opening of global upstream production. The trend is likely to continue, despite the price of Brent slowly showing signs of revival, although the process will be unevenly spread across many oil-producing states. The immediate sectoral impacts of reverse-resource nationalism will likely spillover into the broader economy in the next couple of years.

 
The purpose of the paper is not to evaluate the likelihood of any of these, or similar scenarios. Rather, the goal is to point out that if Canada cannot lower its cost, we will always be the first one to lose our chair in the game when the music stops. The above scenarios are the triggers for such downside risks.
The good news is the free market works and the lowest cost producers in the oil sands are still being rewarded by investors with more capital which in turn spurs more innovation. Other companies seek to replicate or exceed the success of the leaders and the cycle continues.
The data shows that significant parts of the oil sands are becoming more cost competitive. SAGD production for the most efficient in-situ wells at Cenovus Energy is less than $50/barrel- a target for others in industry to pursue. Industry is also being much more cautious about capital allocation. Sequencing of projects by each major operator means less competition against themselves for labor and materials. This is a change from the growth at all costs period of 2003-2007 when the major players couldn’t break ground on projects quickly enough, only to face soaring cost inflation. Some industry executives even view a few years of low prices as a necessary “cooling off” period to reset the industry’s high cost structure.
There are lessons here for the BC LNG projects. There is almost no possibility that BC will have more than two large LNG projects under construction at the same time. This does not suggest collusion by developers but rather smart self-regulation, particularly for majors that can deploy capital across dozens if not hundreds of projects around the world.
While market discipline on cost is effective, government can encourage innovation in cost reductions through tax credits and public-private partnerships. Some notable partnerships through the Alberta universities are in place, but industry appears to have appetite for more. In many ways, the appetite is driven by the fact that today’s CEOs and oil sands leaders saw the benefits of research and development from AOSTRA under Peter Lougheed and understand what it can mean.
Some taxpayers might reasonably ask why the government should subsidize the same companies responsible for those maddening trips to the gas station where the price is already too high. Yet the answer is that it is in the taxpayer interest to give up a bit of the upside to protect against the downside. Innovation and lowering costs will protect the golden goose and make us more efficient in the current downturn as well as less vulnerable to the next downturn.

Know your customer

At times it feels like knowledge in certain parts of the oil patch about China and India is limited to the fact that they need a hell of a lot of oil and gas. If these countries are to be our new customers, we should understand our competition, the nuances of local market conditions, and how these markets are likely to evolve in the future. These countries will eventually face limits to growth similar to the US, where gasoline consumption peaked in 2005. Moreover, the energy outlook in these countries must be understood in the context of their appetite for specific grades of crude, further shaped by the existing web of geopolitical and commercial relationships.
China’s refineries are built to process light and medium barrels, not the heavy sour acidic grades from the oil sands. India’s newest private refineries can process virtually any kind of barrel but the bulk of their refinery sector is decrepit and controlled by state-owned companies. Future refinery investments in these countries will emphasize flexibility to allow the maximum range of crudes to be utilized, portending intense competition among suppliers, especially when demand is weak in a number of large “legacy” markets. Governments in both countries are also deregulating prices for petroleum products like gasoline and diesel, with China well down this road already and India formally deregulating diesel under its new government. New taxes and social policies to curb consumption of imported oil and gas should be watched closely, as should efforts to bolster domestic supplies like Indian coal or Chinese shale gas.
The emerging Asia market is prized by the Persian Gulf OPEC states who have watched their market share decline in North America while demand stagnates in traditional “sinks” like West Europe and Japan. This arguable is one of the main reasons why Saudi Arabia and OPEC made the decision last fall to resist cutting production and let global oil prices plummet in an effort to protect market share in places like China. Saudi exports to China have been declining, while Russia’s and Iraq’s have been increasing. This is likely the largest factor in triggering the current “price war” as Saudi barrels are directly competing with those medium-sour barrels from other OPEC and non-OPEC producers.
West Africa, Russia, and Latin America are eyeing the same prize and have been opening their upstream to Chinese national oil companies, embracing the state capitalist model China offers and the low cost financing it provides. China’s incumbent gas suppliers from Turkmenistan to Qatar will seek to protect market share, even if it means accepting lower prices.
Demand attracts supply. Incumbents compete to protect and preserve market share from new challengers. Oil and gas are no different than other goods in this respect. While oil is a commodity, suppliers can be creative not just on price but on using other carrots to differentiate and secure commercial contracts. For many suppliers, this is a “state to state” transaction, between governments and giant national oil companies. When CNPC sits down with Rosneft to do an East Siberia gas pipeline deal, Mr. Putin and Mr. Xi are front and center, not just to cut a ribbon but to ensure that deals get done in the interest of the state. This is not the right model for Canada but it’s important for us to understand who we are up against.
So what can Canada offer to compete, even in a low price environment? Plenty. Open up our markets. Share our expertise. Train their regulators. Look for opportunities to work together in 3rd party markets. Invest in joint R&D. Work together on sustainability and community development. Create a true partnership going beyond buyer and seller to shared strategic interest. Security of supply meets security of demand. In this context, Canada should be very cautious about restricting investment opportunities that do not already fall victim to prices in our upstream oil and gas sector from our future customers. While all energy companies, whether private or state-owned, should operate according to Canadian market and regulatory principles, Canada will need capital from all corners to ensure we reach our potential as a global energy exporter.

Services, the real “value-add”

The market access debate has focused on hydrocarbon exports. Yet there is a second and highly dynamic source of “energy” exports that is a national asset- our oil services companies. Here we are exporting not the raw commodity but the technology to develop increasingly complex oil and gas resources elsewhere, along with the know-how to make the technology work. Many companies that most Canadians (and most non-Albertan politicians in Ottawa) have never heard of are best-in-class providers of a broad array of oil services technologies that are in demand in every oil and gas province around the world. Without these technologies, overwhelmingly dominated by US and Canadian firms, there is no shale gas or tight oil revolution.
These fiercely entrepreneurial and independent companies are not looking for a helping hand from Ottawa although they too will benefit from the market access initiatives that will help their Canadian customers in the upstream move oil and gas to higher priced offshore markets. If anything, these companies have a story to tell Ottawa about success in the high growth emerging markets and how to navigate the dynamics of state capitalism and dealing with giant national oil companies. They do it all the time.
The best thing Ottawa can do to support this dynamic sector is to help ensure a continuing stream of engineering talent and skilled labor to sustain growth. In addition, a unified and coherent message about best regulatory and in “in the field” practices for safe hydraulic fracturing operations will support development of services opportunities in overseas markets. In many of these markets, public mistrust of fracking is high even when central governments are supportive. Yet it will be hard for Ottawa and the industry to convince skeptical landowners in shale-rich Eastern Europe or Colombia to drill when we can’t even convince our fellow Canadians in Quebec and New Brunswick.

Conclusion

A new operating environment defined by low oil prices has pushed Canada to an inflection point in its path to being a major oil and gas supplier to an energy-hungry world. Many oil and gas executives in Alberta still have a fatalistic view, hoping that “just one” LNG or oil sands pipeline moving forward would be a positive signal that we, as a country, still know how to get difficult projects done. To get there, it is the author’s view that greater leadership from Ottawa will be required. Most importantly, this leadership must define core principles on energy infrastructure development and climate change policy, and then move swiftly to implement and defend such principles. Waiting for the courts, industry, or Washington to move first is no longer good enough.
At the same time, we must look beyond our North American market to see what our competitors are doing and how demand-side dynamics in Asian markets are evolving. The world is not standing still while Canada debates its own path to getting our oil and gas to tidewater. Canadian oil sands and LNG projects are part of a global competition for capital and we must understand that failure to smooth the path for growth and development will lead to capital flowing elsewhere. While our political stability and huge resource base are major advantages, we have lost ground even further by failing to manage social and environmental issues effectively. These issues can be viewed either as a moral imperative or as a critical commercial challenge, but either way few would dispute they are the biggest factor standing between the Canadian oil and gas sector and its aspirations.
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About the Author

Robert Johnston is CEO and Director of Global Energy and Natural Resources at the EURASIA Group, a position he assumed in 2013 after seven years as founder and leader of the firm’s Global Energy and Natural Resources Strategy Group. RJ is responsible for directing firm strategy and leads oversight of the firm’s research, sales, and operations teams across three offices.