Matthew D. Keen and Emily Chan, Norton Rose Fulbright, Canada, look at some of the risks faced by LNG projects in British Columbia and the possible consequences of recent industry trends.
Over 20 major greenfield LNG projects have been proposed for the coast of British Columbia (B.C.), Canada. Their common goal is to connect major shale reserves in the western provinces of B.C. and Alberta with growing Asian markets across the Pacific Ocean. Development has slowed over the past four to five years however, and now only a small handful of major projects are expected to proceed. To date, only two smaller projects near Vancouver have announced final investment decisions (FIDs): FortisBC Energy’s Tilbury Expansion project in Delta, and the Woodfibre LNG project in Squamish. Other prominent projects have delayed FIDs, even after receiving the necessary regulatory approvals. This article examines some of the risks faced by B.C. LNG proponents, and the potential effects of recent industry trends.
World prices and demand for LNG
A major factor that spurred initial interest in B.C. LNG projects, in addition to abundant supply and proximity to Pacific markets, was the significant price difference between North American natural gas and JCC-indexed LNG pricing in Asian markets. That differential has eroded in recent years, as world energy prices have declined. Despite cheaper natural gas feedstock, overall economics are more challenging than in the 2009 – 2013 period, when many projects were first announced.
Some proponents have specifically cited low natural gas prices as the reason for delaying or cancelling LNG projects. Royal Dutch Shell PLC announced in March 2017 that it would discontinue development of the Prince Rupert LNG project, planned for Prince Rupert.1 At the same time, Shell announced that it would still advance the CAN$40 billion LNG Canada project that it is leading, located in Kitimat.2
In July 2017, Petronas and its partners announced that the Pacific NorthWest LNG project in Prince Rupert would also not be built due to the “extremely challenging environment brought on by the prolonged depressed prices and shifts in the energy industry.”3
Despite low North American prices for natural gas, global demand for LNG in 2030 is expected to be double the demand in 2012.4 Asia’s growing population and shift away from coal (and in Japan, nuclear power) are creating a market for relatively cleaner-burning LNG. Many of the LNG developments worldwide are targeted towards these markets.
Climate change policy effects
B.C.’s LNG projects are being developed against rapidly developing carbon pricing and climate change policies. The region has long had a carbon tax and, in 2014, announced a supplemental ‘intensity-based’ emissions regime designed to ensure any LNG industry was the ‘world’s cleanest’, but still provide price certainty to potential investors.
For its part, in late 2016, Canada announced a new action plan following the Paris Agreement. Under the new federal plan, provinces and territories must adopt a carbon pricing scheme by 2018 by either imposing a direct price on carbon or implementing a cap-and-trade system. Otherwise, they will be subject to the federal ‘floor’ price, set at CAN$10/t of carbon emissions for 2018 and increasing by CAN$10/yr to CAN$50/t by 2022. Provinces and territories implementing a cap-and-trade system are subject to two additional requirements: they must decrease their emissions in line with Canada’s target (i.e. 30% reduction below 2005 levels of emissions by 2030) and with reductions in jurisdictions that choose a price-based system.
B.C.’s carbon tax has been set at CAN$30/t of carbon dioxide equivalent gas (CO2e) since 2012, meaning that it will not be required to increase its carbon tax until 2021. The tax applies to greenhouse gas (GHG) emissions from all LNG facilities. As part of B.C.’s commitment to have the ‘cleanest LNG in the world’, LNG facilities are also subject to a GHG ‘emissions intensity’ benchmark of 0.16 CO2e for each tonne of LNG produced. LNG proponents can meet this ratio either reducing their emissions directly or by creating or purchasing offsets or purchasing technology fund units for CAN$25/t.
Provincial climate change policy, LNG, and energy policy generally now face further uncertainty, after the minority government elected in B.C. on 9 May 2017 was toppled by a vote of non-confidence on 28 June 2017. The parties that will form the new government ran on election platforms that called for increases to carbon taxes, opposition to the Kinder Morgan oil pipeline expansion, and closer scrutiny of LNG projects. The current minority situation adds additional uncertainty, given unpredictable election timing.
In addition to the existing federal regime, the federal environmental assessment conditions for the well-advanced Pacific Northwest LNG project imposed an additional project-specific carbon cap, and limited the project’s ability to use offsets fund units under the provincial regime. Major projects that complete federal environmental assessments in the future may face a similar cap. The cumulative effect of these policies may, ironically, inhibit projects designed to export a low-carbon ‘bridge’ fuel to overseas markets and thereby reduce emissions.
Recent provincial initiatives
Despite climate change policies that add costs, the B.C. government has attempted to make LNG investment more attractive by introducing incentives to proponents.
Smaller LNG proponents can take advantage of a new ‘eDrive’ electricity rate, which prices electricity for LNG purposes at the standard embedded-cost industrial rate. The eDrive rate is intended to incent electric drives for liquefaction, which has the dual benefit of reducing GHG emissions and the resulting carbon taxes, and taking advantage of an electricity surplus from almost exclusively renewable sources predicted in B.C. in the next decade. However, the eDrive rate may have limited application because power generation and transmission infrastructure limits make it an impractical near-term incentive for large loads.
The provincial government has also attempted to create more certainty and favourable conditions for other LNG projects by issuing special directions to the B.C. Utilities Commission for the Tilbury Island Expansion Project and Woodfibre LNG project. Those steps short-circuit standard regulatory hearings that would otherwise be required (e.g. considering provincial energy objectives, local impacts, and the broader public interest). Specifically, the proponents of these two projects may add their projects to ‘rate base’ earlier and hence earn a return earlier, increase a cap on rate base costs (presumably initially imposed to compensate for the lack of commission scrutiny), and have new rates set based on those changes.
This is part one of a two-part article written for LNG Industry’s Auguts issue and abridged for the website. Subscribers can read the full August issue by signing in. Non-subscribers can access a preview of the August 2016 issue here.
Read the article online at: https://www.lngindustry.com/liquefaction/28082017/bc-lng-on-standby/