cont....
However, all did not stay as it was in 2011-2015, nor had it always been that way. If we shift the graph to look at a wider time period, we see two important elements often omitted from the stories of this past week.
First, look to the left end of the graph. Unbeknownst to many, for a long time, both Canada and the U.S. were looking at becoming LNG importers. Yes, importers. The U.S. built and operated significant numbers of re-gasification plants (more on that later), and as late as 2007, Canada was
permitting import facilities on the B.C. coast to bring gas in! During that time, gas prices in Alberta where actually higher than prevailing LNG prices, and so developers thought they could earn a return re-gasifying LNG on the B.C. coast to ship inland to supply our homes and businesses.
Next, look to the right of the graph, and what’s happened since 2015—global prices have come into much closer balance, with Japanese import prices recovering a bit recently but still sitting about $7/GJ above Alberta and B.C. gas prices, which are at near-historic lows. Now you see what people are talking about when they say that the LNG window has closed, at least for now. At today’s prices, you would certainly not make a reasonable rate of return on an LNG asset in BC. Simply put, if the interest in LNG is to drive higher values for Alberta and B.C. gas than we are currently seeing, the market isn’t there globally to allow that to happen today. The difference in price between B.C. gas and global LNG wouldn’t be high enough to pay for the operating and capital costs of pipeline and liquefaction assets.
It’s worth taking a step back, with costs in hand, to consider the three most frequently-raised issues we’ve seen in the past week—the role of government policies (including GHG policies and regulatory timelines), the reasons the U.S. and Australia seemed to get ahead of us in this market, and then get back to the future for the industry in B.C.
Regulatory hurdles
Beginning with the regulatory timelines, Petronas has not had an easy time in Canada. Their initial purchase of Progress Energy in 2012 was initially rejected by the federal government, then eventually approved at the eleventh hour. The B.C. government of then-Premier Christy Clark introduced special royalty and tax provisions for LNG, as well as specific greenhouse gas policies. Furthermore, the Christy Clark government reviewed GHG policies in 2015, during which potential LNG emissions were a primary focus. Finally, the recent election of the NDP government, while not a signal that the project would be derailed, was certainly a source of further regulatory uncertainty and likely increases in production cost. The most direct question, to which we may never have an answer, is whether Petronas would have committed to build the project and begun construction had they received immediate approval in 2012. Even then the project was huge and risky—an $11 billion terminal and a $7 billion pipeline to a still-developing gas play banking on the hope that the extraction, shipping, and liquefaction costs would combine to be less than global LNG prices and allow a return on investment.
The LNG projects impact on emissions
What about GHGs? How much would the project have emitted? Through the various environmental assessments the project was required to pass, many estimates of the emissions from the project are available. The most comprehensive, from the federal government’s environmental assessment, puts the emissions from the facility itself, and associate operations, at 5.2 million tonnes per year. Further analysis found that the emissions associated with the natural gas production to feed the project would add a further five to nine million tonnes per year to Canada’s emissions inventory.
Whatever your preferred final number is, the emissions impact of a facility this size will not be small and GHG policies could be material to the overall costs of the project, but that’s not likely the case for current policies. At the high end of the range above, with total GHG intensities in Canada of a little over 0.21 tonnes of carbon dioxide equivalent per tonne of LNG shipped, carbon costs would not materially alter processing costs. A $30 per tonne carbon price, as is currently in place in B.C., applied on emissions, would increase processing costs by about 12 cents per gigajoule. B.C.’s previous government had enacted provisions to shelter the average costs of production from GHG costs, but there was no guarantee this would continue and the new government has indicated that GHG policies will become more stringent. While I don’t believe the project was cancelled because of risks from proposed changes to GHG policies in B.C., it’s certainly possible that any change in GHG policy would have a material impact on the expected costs of liquefaction. It’s out of the money now, so it’s not likely driving the decision, but that’s not to say it wouldn’t ever matter. LNG is all about margins, and costs here will decrease potential margins.
The American experience
Next, the question I’ve most often heard this week is: if this is purely a market story, why is it not happening in the U.S.? The U.S.
has built and is
still building LNG export facilities and, these facilities are challenged by current market conditions. So, why did the U.S. build while we didn’t? In effect, the U.S. had an advantage from being far behind—in the mid-2000s, the U.S. was very short natural gas, and built a lot of import capacity, as shown in the graph below. Many of those import sites, with pipeline infrastructure, docks, storage, and such were converted to export facilities as the U.S. gas market swung from short to long after 2013.
These facilities are facing the same cost pressures I described above. Recent
analysis from Jason Bordoff and Akos Losz (2016) discusses just how tight US LNG margins have become and, as you can see from their graphic below, facilities faces challenges to even meet their variable costs, let alone recover the costs of sunk capital.