Big Positives For Kitimat LNG – May Get Some Brownfield Economics And Meet CleanBC Emissions

Apr 5, 2019


In exactly one month, the Chevron/Woodside ~2.4 bcf/d Kitimat LNG project has jumped from a hint that a FID could be coming in 2020/2021 to an LNG project that is pointing to being able to solve all the major issues that would hold back a FID in 2020 – size, capital cost and meeting Clean BC emissions levels.  At its March 5 analyst day, Chevron’s Q&A comments provided us with the view that that Chevron might be pointing to a FID in 2020/2021. It was far from a direct comment, but their comments and slides clearly pointed to a probable FID.  This week, the comments from Chevron and Woodside were direct and positive to pointing to FID – Chevron is moving to double the size of Kitimat LNG to ~2.4 bc/d, piggy back on LNG Canada to effectively get some “brownfield” cost advantages to a “greenfield” project, and moving to use hydroelectric power instead of natural gas to power the LNG plant so it can meet CleanBC emissions limits.  There was also big disclosure this week that is good news for a number of western Canada natural gas producers, Woodside says they will have a “different” natural gas supply model and will be contracting natural gas supply from a number of natural gas producers.  If 50% of the Kitimat LNG gas supply goes to this “different” model, there will be ~1.2 bcf/d of gas supply up for grabs from western Canada natural gas producers, which is about 20% of current Canada’s net natural gas exports to the US. Chevron and Woodside haven said when FID is coming. In fact, Woodside CEO said this week FID was not expected in 2019.  But when we think about the last month, it reminds us of how we wrote in the several months leading up to LNG Canada’s FID – there were multiple clear signs and comments that they are ticking all the boxes of the items need to make a FID.  In this Kitimat LNG case, they ticked perhaps the biggest boxes this week, which is why we think they are pointing to a FID in early 2020.

Chevron/Woodside Kitimat LNG now planning to be 2.4 bcf/d.  This week, Chevron applied to the NEB to increase the export license from 10 mtpa (1.3 bcf/d) to 18 mtpa (2.4 bcf/d). The new plan for the project involves two six million tonne LNG trains, with the option to add a third to ramp up to 18 mpta or 2.4 bcf/d.  The expanded size should improve the project economics.  Kitimat LNG is a 50/ joint venture between Chevron and Woodside Energy. The key economic factor (discussed below) for Kitimat LNG is that it only 10 km from LNG Canada’s location.

Location of the Chevron/Woodside LNG vs LNG Canada

Source: BC O&G Commission

The first hints of a change in momentum came at the Chevron March 5 analyst day.  Our March 10, 2019 Energy Tidbits memo highlighted Chevron’s March 5 analyst day, in particular our takeaway from the Q&A on Kitimat LNG.  We then wrote “Is Chevron Pointing To A Potential FID of Kitimat LNG in 2020/2021?” And “But one item that caught our attention was mgmt’s response in the Q&A on its LNG inventory.  We were a little surprised as they seemed to present Kitimat LNG as one of their next potential LNG projects.   We weren’t looking for anything new on its Kitimat LNG project but their verbal comments got us to dig deeper.  In the Q&A, mgmt. was asked if “Is it multiple years of just working out Gorgon and Wheatstone and then pulling the trigger? Or is there something you’re looking for in the broader LNG sort of financial returns potential before you make another move in that area?”  Mgmt discussed Gorgon/Wheatstone, and then said “And then we’ve got other options. Certainly, we’ve got Kitimat. We’ve looked at things in other parts of the world and continue to look for the right opportunities. The key on big LNG investments is to be down the cost curve. You do not want to be out at the high-end of the cost curve, really want to be in the lower cost facilities because those are the ones that are likely to get funded to get built into the economic. And so that’s how we’re thinking about it.”  But what got our attention even more was the Chevron slide deck.  We think of supermajors being exceptionally careful on written disclosure, which is why we mention the single Kitimat LNG reference in the entire slide deck.  The single reference seems to point to a potential Kitimat FID in 2020 or 2021.  Its not just that Kitimat LNG is the first LNG project named after Australia, its that Chevron listed Kitimat LNG as one of their 12 upstream major projects   Chevron describes these major projects as “The projects in the table are considered the most significant in the development portfolio and have commenced production or are in the design or construction phase. Each project has an estimated project cost of more than $500 million, Chevron share.”  We recognize that Chevron says Kitimat is startup 2023+, but we can’t believe they would put that 2023+ unless it was within a 2 to 3 years of 2023 ie. suggesting to investors that that Kitimat LNG could go FID in 2020 or 2021.  We just can’t believe they would put a major project startup of 2023+ if they were looking at a start up of 2027 to 2029.   That would seem too long to start up to deserve inclusion on that list that they are highlighting at their analyst day.  Whereas a FID 2020 would likely point to a 2025 or 2026 start up.”

On Wed, they came up with a solution to overcome the top regulatory barrier – how to fit Kitimat LNG under CleanBC emissions limits.  One other hugely significant disclosure this week came in the Business in Vancouver Wed story “Kitimat LNG commits to electrification[LINK]. BIV wrote “A promise made in Kitimat today that the Chevron-Woodside Kitimat LNG project would use electric drive would be a game-changer, if fulfilled, not just for the LNG industry in B.C., but for independent power producers. At a conference on LNG hosted by the Haisla First Nation in Kitimat today, April 3, Rod Maier, vice president of public affairs for Chevron Canada, said the Kitimat LNG project would use e-drive, according to the First Nation LNG Alliance.  He was quoted as saying it would be “the Tesla of LNG plants.”  That is no mean pledge, as it would significantly lower the project’s greenhouse gas emissions profile, and significantly increase the demand for power. It would also meet the strict new best-in-class emissions benchmarks set out in the CleanBC plan.”  Kitimat LNG would take advantage of the massive being built Site C hydroelectric power generation to use electricity instead of using natural gas to power the LNG plants as is the norm.  BC Hydro [LINK] states “The Site C Clean Energy Project (Site C) will be a third dam and hydroelectric generating station on the Peace River in northeast B.C.  Site C will provide 1,100 megawatts (MW) of capacity, and produce about 5,100 gigawatt hours (GWh) of electricity each year – enough energy to power the equivalent of about 450,000 homes per year in B.C”.  We agree with BIV that this is a game changer as it would allow for Kitimat to get under the CleanBC emissions limits.  If so, then it becomes an economic question – how much more does electricity cost relative to burning natural gas.    But at least it means that it isn’t a non starter because of emissions.  Prior to this announcement, we were firmly on the record that CleanBC emissions limits would mean there couldn’t’ be another major BC LNG project (after LNG Canada) that could be built and fit under the CleanBC emissions limits.

On Wed, they revealed how they can get some “brownfield” economics in a “greenfield” project.  Perhaps the biggest holdback to any greenfield project is how much will the project actually cost, or at least having confidence in the capital cost estimates. Greenfield projects are brand new projects in new areas. But the Bloomberg terminal had an excellent story on Thurs “Chevron Partner Pleased Shell Moving First on Canadian LNG” that reminded us that Kitimat LNG will actually have some “brownfield” cost benefits even though it is a “greenfield” project.  Bloomberg wrote “* Shell’s LNG Canada will lay the groundwork for working in the area, Coleman said in a Bloomberg TV interview. “The two plants are only about 10 kilometers apart, so we’ll be using essentially the same infrastructure”  * “We’re working hard now with our partners to ensure that we are decision ready, really at the back end of the construction period for LNG Canada so that we can pick up that work force and take advantage of the work that’s already been done”.  This is excellent insight and reveals why they should be more confident in their capital costs estimates and project execution .

Woodside effectively put up an “open season” for western Canada natural gas producers for natural gas supply to Kitimat LNG. It may not be an official “open season”, but it was a clear invitation for western Canada natural gas producers to call Woodside if they want to contract natural gas for Kitimat LNG.  Woodside came out on Wed telling western Canada natural gas producers that it won’t be developing its own reserves/production for Kitimat LNG like is the current LNG supply model.  Rather it will be gong to industry to contract natural gas reserves/production to deliver to Kitimat LNG. Bloomberg’s reporting of Woodside’s comments on infrastructure made us go back to the full interview to see if there was anything else in the interview [LINK].  There was one other hugely significant comment from Woodside’s CEO – he said there will be a different LNG business model to secure natural gas for Kitimat LNG.  He said this different model would be a disaggregated model and not the historical model where the LNG company also owned/controlled gas supply to feed the LNG plant.  Rather they will tie up gas supply much like a natural gas aggregator by going to a number of natural gas producers and contracting the gas. This is a major switch in business models and is only possible because there is ample natural gas supply.

Here is the SAF Energy created transcript of the Woodside CEO comments. At 4:10 mark.  Coleman says “I think what you are seeing is a difference in the business model itself. There’s two parts to it.  People needed to be comfortable that the cost structure was going to be stable and the answer is that it is.  you can see a path forward now.  for us, we are starting to see what contractors are tendering on other projects so that validates some of our assumptions as well.  Of course government regulation has stabilized in Canada so you’ve got a  clear path forward there as well.   But I think now more importantly, people are looking at a different business model.  We’re now starting to think about a disaggregated business model, where the upstream supply may come from different suppliers rather than being a captured project, which historically they were.  So there’s a more capital efficient way of moving the projects forward now.  Its actually taking advantage of all of that gas that is produced in western Canada, which by the way hits the market place at AECO at a much lower price than Henry Hub.  So if you can projects moving on the Gulf Coast, you should be able to get projects moving on the coast line of Canada.“

Chevron hasn’t said they will do the same, but we expect they will also get 3rd party gas for some of the gas supply. Woodside did not say if Chevron is taking this different model for natural gas supply for any or all of the Chevron natural gas needs.  However, we expect that they will do so for some portion of their gas supply needs.  Part of the reason for our view is Chevron’s Horn River shale play has high CO2.   The well results have been excellent and high CO2 does not mean it won’t work. It just adds to the supply cost and/or the variability in the supply cost. We don’t believe the returns leverage to Chevron comes from the reserves part of the supply chain.  Rather, we think the key to the reserves part of the supply chain is predictable, consistent, low cost supply, and that is why we would expect to see Chevron also look to contract some natural gas supply for part of their needs.

It may not lead to M&A, but this “different” natural gas supply model is a big plus to western Canada natural gas outlook. This doesn’t point to a big M&A cycle, but it is pointing to a big plus to Western Canada natural gas.  If we assume that 50% of the total required ~2.4 bcf/d gas supply is ultimately done under this “different” model, that sets up a market for ~1.2 bcf/d of natural gas supply from western Canada natural gas producers. This is equal to ~20% of current Canada natural gas net exports to the US. The EIA estimates Canada net natural gas exports were 6.21 bcf/d in Jan. The National Energy Board estimates Alberta/BC marketable natural gas in Jan was 15.84 bcf/d.