Canadian LNG: the road to success

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Thomas Liles, Oil and Gas Analyst, Rystad Energy
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Figure 1. Pacific Oil & Gas Montney production by hydrocarbon type and proposed Woodfibre LNG output (million ft3/d). Source: Rystad Energy UCube.

Thomas Liles, Rystad Energy, Norway, takes a detailed look at the current state of the Canadian LNG market and where it is headed.

The Canadian LNG industry entered the new decade with only a single sanctioned LNG export project: Trains 1 and 2 of Shell-operated LNG Canada, located in Kitimat, British Columbia (B.C.). Following LNG Canada’s positive final investment decision (FID) in October 2018, sentiment around Canada’s LNG potential grew increasingly cautious as 2019 progressed with no additional FID activity. By November 2019, industry voices were warning of Canada’s late arrival to an increasingly crowded global LNG market. 4Q19 impairments by Chevron and Woodside of their respective shares in the Kitimat LNG project only seemed to compound this sentiment.

Although Canada will not become the LNG behemoth envisioned by industry players and policymakers prior to the onset of East Asian price volatility in 2015, several developments over the past year suggest that there may yet be potential for additional large scale LNG development in the long-run. Most importantly, there has been a concerted push for greater integration between export projects and local sources of supply, both in terms of upstream acquisitions made by LNG operators, as well as producer-led export initiatives. While current proposals vary in feasibility, the trend nevertheless indicates that Canada’s active remaining LNG players maintain a long-term interest in the industry.

Figure 2. Pieridae Energy production by historical company proposed growth profile and proposed Goldboro LNG output (million ft3/d). Source: Rystad Energy UCube; Rystad Energy research and analysis.

The shift towards integrated LNG models

Whereas LNG Canada always featured a high degree of overlap between its working interest partners and upstream suppliers in the prolific Montney play, smaller LNG players have increasingly moved towards an integrated model through major upstream acquisitions in the Western Canadian Sedimentary Basin (WCSB).

Notably, in May 2019, Pacific Oil & Gas – an Indonesian independent and developer of the 2.1 million tpy Woodfibre project in Squamish, B.C. – announced an agreement to acquire Montney pure-play Canbriam Energy for an undisclosed value. Rystad Energy estimated Canbriam’s net present value (NPV) at approximately US$900 million at the time of the announcement, which included over 180 000 net acres of Montney lands in northeast B.C. and some of the best operating cost performance across the entire Montney play. In addition to its high-value liquids yields and competitive cost structures, Canbriam’s fractured horizontal Montney wells typically featured lower decline rates, thanks in part to the company’s water strategy and active well defence.

With the acquisition of Canbriam, Rystad Energy estimates that Pacific will be able to ramp up its Montney output with a modest level of drilling activity and operate as an integrated LNG player by the time Woodfibre is commissioned in the mid-2020s.

Pieridae Energy, which is aiming for a 2020 FID on the first train of its 10 million tpy Goldboro LNG facility in Nova Scotia, likewise continued to push forward with a more integrated development concept following its December 2018 business combination with Alberta Foothills gas producer Ikkuma Resources. In June 2019, Pieridae announced further consolidation of its upstream Foothills position through the acquisition of Shell’s conventional legacy assets in the area, whose production stood at approximately 120 million ft3/d of natural gas, 5700 bpd of natural gas liquids (NGLs), and 3200 bpd of condensate and light oil. The deal consisted of a cash consideration of CAN$175 million and the issuance to Shell of 15.2 million common shares valued at CAN$15 million.

The Shell transaction essentially doubled Pieridae’s natural gas output to more than 200 million ft3/d, and the company subsequently announced plans to grow production to an ambitious 800 million ft3/d to supply the first 5 million tpy train of Goldboro in time for commissioning in 2024 – 2025. The company has indicated a ~CAN$1 billion upstream investment program to grow output, which would involve drilling between 25 and 35 development wells annually over four years. The upstream development program is underpinned in principle by US$1.5 billion in German Government loan guarantees, with the stipulation that Pieridae refrain from hydraulic fracturing in the extraction process.

On the downstream side, Pieridae initially entered into an agreement in 2013 to supply German utility Uniper with 4.8 million tpy of LNG over a 20-year term. Uniper retains the right to terminate the agreement if Goldboro fails to meet certain deadlines, however. Sanctioning for Train 1 has already been deferred several times, although Pieridae in July 2019 negotiated an extension of its positive FID deadline to the end of September 2020, with commercial deliveries to Uniper guided for a startup date at some point between November 2024 and June 2025.

While the purchase from Shell could signal Pieridae’s long-term commitment to Canadian LNG on the one hand, doubts persist over the company’s financial resilience. In particular, the Shell deal raised local concerns regarding the ability of such a modestly capitalised player to cover its asset retirement obligations should market conditions result in insolvency or a withdrawal of German Government financial
support. A senior executive from Canadian Natural Resources Ltd criticised the transaction in a letter to the Alberta Energy Regulator in November 2019, complaining that the regulator’s current system of rating liabilities was flawed and failed to accurately account for well abandonment costs. Complicating the matter is the idiosyncrasy of hydrocarbon production in Alberta’s Foothills. Natural gas from the area is higher cost and contains higher levels of poisonous hydrogen sulfide (H2S), thus complicating any reclamation work that would need to be carried out under a potential receivership scenario.

Local mid-size upstream players, prompted by persistently volatile natural gas prices in western Canada, have likewise emerged as proponents of a more integrated LNG approach. In February 2019, a group of 10 Canadian natural gas producers with a collective output of approximately 3 billion ft3/d formed the Rockies LNG Partnership. The consortium’s stated aim is to receive regulatory approval for a 12 million tpy facility, attract a larger partner to provide capital, and ultimately supply the project with its own natural gas. Consortium members include Deep Basin natural gas producer Peyto Exploration & Development, as well as Montney producers such as Advantage Oil and Gas, Birchcliff Energy, and Seven Generations Energy, among others. Canbriam Energy withdrew from the consortium following its acquisition by Pacific, reducing the number of members to nine.

In October 2019, Rockies LNG CEO Greg Kist indicated an imminent start to the regulatory process with a commissioning date tentatively scheduled for 2026. Additionally, the consortium plans to supply the project via a long-haul pipeline with some existing regulatory approvals. Project partners have expressed interest in Enbridge’s Westcoast Connector Gas Transmission Project and TC Energy’s Prince Rupert Gas Transmission route, which was originally intended to service Shell’s Prince Rupert LNG project (21 million tpy) and the Petronas-operated Pacific Northwest LNG project (18 million tpy), respectively. Both LNG schemes were cancelled in 2017, although their corresponding midstream projects already have environmental certificates and have completed a certain amount of permitting.

Considering the pipeline routes under consideration, Rockies LNG’s implied site location is likely to be somewhere in B.C.’s Prince Rupert area, which is located near the Alaska border approximately 115 km northwest of Kitimat. Additionally, project partners have tentatively indicated plans to develop the project as a floating LNG (FLNG) facility. Under this scenario, Rockies LNG would potentially require three barges and forego capital-intensive land-flattening activities associated with onshore developments, although no cost estimates have been disclosed yet.

The emissions imperative and federal policy carrots

In tandem with greater integration with upstream supply, Canadian LNG development concepts have taken a greener turn since late 2018. In large part, this development has resulted from B.C.’s increasingly stringent greenhouse gas (GHG) emissions requirements, although the federal government has provided some financial support for improvements in energy efficiency.

On the regulatory front, the B.C. provincial government in late 2018 adopted stricter provincial GHG emissions targets as part of the CleanBC plan. CleanBC ultimately aims to reduce provincial emissions to approximately 12.75 million tCO2e annually by 2050, or 80% below 2007 emissions levels. In terms of the energy industry specifically, the plan caps emissions from LNG plants at 0.16 million tCO2e, meaning that new LNG developments of any size would effectively be required to utilise electric drive technology to comply with provincial standards. Electric drive, in turn, would have the benefit of powering the liquefaction process through B.C.’s abundant hydroelectric resources as opposed to higher-emitting natural gas turbines.

Figure 3. British Columbia (B.C.) historical greenhouse gas (GHG) emissions by industry and future targets (million tCO2e/yr). Source: Province of B.C.

Figure 4. WCSB natural gas production by offtake/demand source (billion ft3/d). Source: Rystad Energy GasMarketCube; Canada Energy Regulator; company reporting.

Although CleanBC was followed by the cancellation of ExxonMobil’s Westcoast Canada project (December 2018) and Steelhead LNG’s Kwispaa scheme (February 2019), at least one major project sought to reconcile its emissions profile with B.C.’s revised targets.

In April 2019, Chevron submitted an amended application to the Canada Energy Regulator (CER) for the Kitimat LNG project, a 50/50 joint venture with Woodside Energy. Originally consisting of two gas-powered liquefaction trains with a total capacity of 10 million tpy and a 20-year export licence, the revised application envisioned the project’s expansion to three trains with capacity of 18 million tpy and a 40-year export licence. Most crucially, Chevron committed to powering the facility with electric drive as opposed to feed gas, thus reconciling Kitimat with CleanBC. In December 2019, federal regulators approved the reconceptualised project.

LNG Canada also saw a reduction in its emissions profile and something of a policy carrot. In summer 2019, the federal government provided the project with CAN$220 million in funding for more energy-efficient gas turbines, which aim to lower fuel use in the liquefaction process and thus reduce the emissions profile of Trains 1 – 2. The investment builds on an emissions profile that is already comparatively low in terms of global LNG projects. In any case, 80% of LNG Canada’s power needs were slated to come from natural gas feedstock, with the remaining 20% being sourced from hydroelectric utility BC
Hydro.

Woodfibre LNG had already committed to electric drive following community consultations in Squamish in 2014. Woodfibre likewise received regulatory support in August 2019, when the federal government exempted the project from fabricated steel duties that the Canadian International Trade Tribunal had previously imposed in 2017. As such, one of the final barriers to a positive FID was removed and Woodfibre ordered a major piece of project equipment. A positive FID, however, was punted further into 2020 due to last-minute amendments to its worker accommodation plans. Given the duties exemption and Pacific’s successful acquisition of Canbriam Energy, however, Rystad Energy expects a positive FID for Woodfibre at some point in 2020.

Local solutions to Canada’s LNG challenge

Regulatory approval for the Kitimat amendments notwithstanding, Chevron put its 50% stake in the project up for sale in late 2019 following a review of its long-term natural gas price outlook. The supermajor recorded an impairment of approximately US$10.4 billion in 4Q19, driven by its share in Kitimat, as well as upstream shale gas projects in the Appalachian Basin. Similarly, in February 2020, Woodside recorded an AUS$720 million impairment of its Kitimat asset, which includes both its stake in the LNG export terminal as well as upstream assets in the Liard Basin.

Recent experience with Kitimat has been bittersweet, perhaps. While its conceptual retooling demonstrated the global competitiveness of lower-emissions LNG projects, Chevron’s announcement likewise underscored the continued vulnerability of Canada’s LNG industry to the vagaries of portfolio optimisation, particularly when major foreign players with diversified portfolios are involved.

Looking forward, the experience of Rockies LNG may prove most salient for Canada’s LNG future. While LNG Canada and Woodfibre – that is, projects with the highest chance of success at this point – will no doubt be a boon to the industry, large scale future developments may ultimately hinge on the collective efforts of local upstream players with more skin in the game. To be sure, the WCSB’s natural gas potential is enormous, bolstered by large reserves of liquids-rich gas with favourable economics. While western Canada’s upstream industry will, of course, benefit from greater connectedness to markets in eastern Canada and the US in the coming years as well as modest increases in in-basin demand, market diversification away from North America will no doubt prove crucial in the long-term.

ORIGINALLY PUBLISHED BY LNG INDUSTRY