All Gassed up and Nowhere to go

Encana Corp., the Calgary-based oil and gas conglomerate descended from the CPR and a government-owned energy company founded by Peter Lougheed, joined the capital flight from Alberta last month, announcing it was halting investment in a Peace River gas plant to accelerate investment in a Texas shale oil play. Encana president and CEO Doug Suttles said the decision was provoked by the new NDP government’s current review of the province’s oil and gas royalty regime. “We need to know the rules of the game before we start to play,” said Suttles.

The Encana announcement, like many other capital redeployments out of the western Canadian energy sector this year, was undoubtedly influenced by factors other than royalties, including the NDP government’s corporate tax hikes and the new carbon taxes and emission restrictions in its Climate Leadership Plan. Low natural gas prices and market access issues likely played a role too.

But of all the variables that influence when and where private capital is invested in the Canadian natural resource sector, it is clear that tax and regulatory policies make a big difference. From the failed Mackenzie Valley gas pipeline project in the 1970s to the more recent stagnation of the Ring of Fire chromite mining megaproject in northern Ontario, government policies have long played an outsized role in determining Canadian resource industry investment flows.

If the Mackenzie pipeline had gone ahead in the 70s, when prices and continental demand were rising, Canada would have sold multi-billions of dollars’ worth of Arctic gas to consumers in the United States. Instead, by the time all the land claims and other regulatory obstacles to development were (more or less) resolved decades later, the market opportunity had passed and there was no business case for investing in the Mackenzie pipeline.

The latest and perhaps biggest missed opportunity in Canadian resource investment and development also involves natural gas. Until recently, foreign and domestic investors were lining up to bet billions on the construction of new port facilities in British Columbia for the shipment of liquefied natural gas from Canada to new markets across the Asia-Pacific region. Today not a single LNG plant has been built on the B.C. coast and the prospects for doing so grow dimmer by the day. Excessive government regulation is not entirely to blame, but the fact is that gas production and LNG export infrastructure are booming in countries like the United States and Australia that have gone out of their way to seize the global market opportunity.

Why did B.C. miss the LNG boat? Partly because the global gas market got a lot more competitive. Only four years after the International Energy Agency asked, “Are we entering a golden age of gas?”, the Chinese economy has slowed, Japan has restarted its nuclear plants, the U.S. shale gas revolution has created a North American supply glut, and new LNG plants are coming online everywhere but Canada. In 2016, global LNG producers are expected to add 50 million metric tons of new capacity. This is the largest single annual capacity increase in history, equivalent to roughly a fifth of current global demand.

From a certain perspective, Canada’s failure to join this parade looks like genius. LNG prices are weak and the economics of new projects will remain challenging for the medium term. LNG plants are multi-billion-dollar ventures which cool gas into liquid form at minus 160 degrees Celsius before loading it on to purpose-built tankers for shipment overseas. These projects have historically been underwritten by long-term supply contracts (20-25 years) which link the amount paid per million British thermal units (MMBtu) to the oil price. In early 2014, the spot price for LNG cargos reached nearly $20/MMBtu. It has subsequently fallen to below $7/MMBtu and could drop to $4/MMBtu. Some analysts expect the oversupply (and lower prices) to continue to 2025.

Did Canada avoid a hazardous plunge into this market because its policymakers had better foresight than others? Hardly. A Fraser Institute report released this fall, LNG Exports From British Columbia: The Cost of Regulatory Delay, found that the Canadian LNG regulatory process was simply too long and too expensive compared to its peers. Other jurisdictions had regulatory structures that were faster and cheaper to negotiate. And it’s not like those competitors were offering far lower environmental protections than Canada. Ten of the 17 new LNG plants now under construction in the Pacific region are American or Australian, countries with comparable environmental standards. According to the Fraser study, Canadian gas producers could have had up to 72 percent of the Asia-Pacific market by 2020 if it had export infrastructure in place. Instead it will not have a single LNG plant built by then, at a foregone loss to the B.C. economy of some $20 billion a year.

https://www.fraserinstitute.org/studies/lng-exports-from-british-columbia-the-cost-of-regulatory-delay
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In August the Economist Intelligence Unit published a report titled “Canadian LNG: Late to the Party?” It focused on the current “window” of opportunity for LNG investments, and concluded that with world prices as depressed as they are, the window has now closed. The EIU predicted the next one may not open until 2025.

B.C. LNG plants are subject to regulation by both the National Energy Board and the provincial government. The latter also sets royalties on gas. Generally speaking, the higher the price, the higher the royalty taxes collected by government. So, if B.C. was shipping more gas into the current global market, it might collect less “rent” now compared to later, if prices are higher. But there’s a price to be paid for arriving late to the party too, according to the Fraser report: “Annual export revenues lost due to delay [of LNG projects] would have equated to between 2 and 9.5 percent of B.C. GDP in 2014, depending on assumptions about export volumes and prices.”

Australia bet very big, and very early, on Asia-Pacific LNG exports. It shipped its first load from the prolific gas fields of Western Australia in 1989. Last year the country produced 9 percent of global LNG and earned $14.1-billion from its exports. Three new major projects worth almost $100 billion that are currently under construction in Western Australia will more than double the country’s liquefaction capacity by 2017.

Ironically, Western Australia lost another big LNG plant to its neighbour, Australia’s Northern Territory, because the latter offered a more attractive regulatory and investment climate. In 2008 Tokyo-based Inpex, majority owner of the giant Ichthys offshore gas field in Western Australia, scrapped plans to build another LNG plant there because of regulatory delays, and instead built an 890-kilometre, 42-inch sub-sea pipeline to a new plant at Darwin, in the Northern Territory. At completion, on November 5, 2015, it became the fifth longest subsea pipeline in the world and the longest in the southern hemisphere.

This story illustrates not only the sensitivity of capital to regulation, but also the influence of technology in locating new plants. In the next window for new LNG investments, Canada may have to compete for capital with floating LNG plants that are currently in development by Petronas, a Malaysian company behind one of B.C.’s long-delayed onshore LNG projects. Floating gas plants could benefit from fewer regulatory hurdles and cheaper labour costs. It is clear that efficient and competitive regulatory systems will be key to attracting new LNG investments, now and in the future.

The B.C. Ministry of Natural Gas currently lists 21 LNG project proposals. Many have been approved by regulators, but by the time the approvals finally came through, global market conditions had changed, and now none of the projects’ proponents are willing to go ahead. U.S. energy economist Ken Medlock told a Canadian Energy Research Institute conference earlier this year that no new B.C. LNG exports are likely before 2040. Others are more hopeful for near-term progress on at least a couple of B.C. plants, but meanwhile, other jurisdictions are forging ahead. Last April, prior to a trade mission to India, Western Australia Premier Colin Barnett confidently predicted even more international LNG market share for his state: “We have got Japan absolutely mature [and] China approaching maturity,” he said. “India is the next big frontier for Western Australia”.

It is not all bad news for Canada. The long-term demand outlook is positive for a Pacific-based jurisdiction such as B.C. The November International Energy Agency World Energy Outlook report notes that Asia accounts for almost half of the rise in global gas demand and 75 percent of the increase in imports through to 2040. The lessons learned from failing to attract new LNG projects to B.C. in the current cycle may lead to a more business friendly, streamlined regulatory process before the next wave of investment.

Meanwhile, on the other side of the country in the Maritimes, a number of smaller LNG proposals have cleared the approval processes. The Bear Head project in Nova Scotia plans to use a new technology which requires lower capital costs. So B.C. may soon find itself competing with a Canadian jurisdiction along with all the rest.

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Andrew Pickford is an energy analyst with experience in Canada and Australia.

 

IMAGES:

– Cryptome

– Fraser Institute

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