No one outside Chevron really knows the reasons driving the downward revision of longer term commodity prices that led to the $10 to $11b impairment charge, reduced capex and move to divest Appalachia shale gas and Kitimat LNG. We think the takeaways come from what we believe is the likely linkage between short cycle shale gas and long cycle greenfield LNG – it’s a view for lower longer term Asian landed LNG prices. US natural gas prices and values are increasingly linked to LNG prices. Kitimat moves from one of two LNG projects in Chevron’s 12 major capital projects. Kitimat LNG is a greenfield LNG project, albeit with the chance to be close to brownfield capital, but close to brownfield capital costs likely doesn’t cut it in a lower Asian LNG price outlook. Future growth in US natural gas supply essentially has to be exported primarily thru the Gulf Coast, which makes US gas supply a price taker. And that price goes down with every $ reduction in Asian LNG prices basically flowing thru to the natural gas supply netback ie. LNG shipping and liquefaction costs don’t really change. A materially reduced gas supply netback hits the economics harder for the pure dry gas plays like Appalachia whose returns are based on natural gas price as opposed to associated natural gas from oil wells in Texas/Oklahoma whose returns are driven by the oil price. Even if we are right that it’s a view of lower Asian landed LNG prices, we don’t believe this impacts the expectation for LNG Canada Phase 2 to FID and for LNG Canada’s ~3.6 bcf/d to be the big plus to western Canada natural gas. But, post 2025 western Canada natural gas will be hurt by the chance for 2.4 bcf/d Kitimat LNG to go ahead is extremely low unless a new owner is found quickly and can link construction to LNG Canada to get as low as capital costs as possible. The biggest impact on western Canada natural gas in the near term would be if Appalachia shale gas can’t compete against associated natural gas for Gulf Coast LNG and it forces more Appalachia gas to Eastern Canada and US Midwest. So we think there is a linkage – a view of lower Asian landed LNG prices.
Chevron downward revision in its longer-term commodity price outlook led to massive impairment, reduced capex and potential divestment of Appalachia and Kitimat LNG. There is no question Chevron surprised investors with its Tues release [LINK] that included Chevron writing “As a result of Chevron’s disciplined approach to capital allocation and a downward revision in its longer-term commodity price outlook, the company will reduce funding to various gas-related opportunities including Appalachia shale, Kitimat LNG, and other international projects. Chevron is evaluating its strategic alternatives for these assets, including divestment. In addition, the revised oil price outlook resulted in an impairment at Big Foot. Combined, these actions are estimated to result in non-cash, after tax impairment charges of $10 billion to $11 billion in its fourth quarter 2019 results, more than half related to the Appalachia shale. “We believe the best use of our capital is investing in our most advantaged assets,” Wirth continued. “With capital discipline and a conservative outlook comes the responsibility to make the tough choices necessary to deliver higher cash returns to our shareholders over the long term.”
A big negative shift in their views on longer term natural gas price and related natural gas asset views since their March Security Analyst meeting. The Chevron announcement caught the US analysts by surprise and understandably so since Chevron went thru positive views on the Appalachia and Kitimat in their analyst meeting. For the Appalachia, mgmt. said “We’re actively developing attractive shale and tight assets in Argentina, Canada and Appalachia”, ““a growing source of new production is the other shale and tight assets, including Vaca Muerta, Kaybob Duvernay and Appalachia, shown in dark blue”, and “the Marcellus and Utica Shale in Appalachia is predominantly a gas play and with low development costs and improved infrastructure in the region, realizations have strengthened and returns are competitive.” For Kitimat LNG, its one of the two LNG projects that were both in the design stage (along with Gorgon Stage 2) on the list of 12 Upstream Major Capital Projects that were driving Chevron’s mid to long term production growth, and “We also have the unconventional gas plays up in Western Canada with Kitimat that offers some opportunity. We’ve been working hard to get the development cost of the plant proper to a point, where it’s competitive with US Gulf Coast delivered into Asia Pacific.”
There was also no change to their Appalachia and Kitimat LNG views in their Nov investor update. The other reason why we expect the US analysts were surprised was that there were no hints or anything in Chevron’s recent 90-slide Chevron 2019 Investor Presentation November 2019 [LINK] that may have pointed to a big negative shift on natural gas or on the Appalachia and Kitimat LNG compared to the March analyst day. For Kitimat LNG, it was still one of the two LNG projects on their 12 major capital project list. Appalachia slides were also the same. We even looked at their bubble map of core vs non core assets (slide 12 below) to see if any of the unnamed bubbles in the core side of assets had shifted over to the non-core side. The bubbles representing Chevron core and non-core assets were identical in classification in the March and November slide decks. There were no shifting of bubble (assets).
Excerpt Chevron 2019 Investor Presentation November 2019
How does a downward revision in Chevron’s longer term natural gas view impact both short cycle Appalachia and long cycle Kitimat LNG? Chevron’s downward revision of their longer term commodity price view led to over $5 billion asset impairment on short cycle Appalachia shale gas. Only those within Chevron likely know the full reasons because Chevron did not disclose their longer term price assumptions or how these longer term views impacted both short cycle Appalachia and long cycle Kitimat LNG. We could go thru pages on our case for linkage, but here are three main points as to why these diverse assets are no longer advantaged gas assets that can attract capital within Chevron. (i) Kitimat LNG is a long cycle greenfield LNG project that we thought could get close to brownfield costs if it linked construction LNG Canada. Chevron’s Appalachia is short cycle, but is primarily dry natural gas so the economics stand on the natural gas whereas the economics of associated natural gas from oil wells in the Permian or Eagle Ford or SCOOP/STACK is primarily driven by the oil component. (ii) The vast majority of any increasing US natural gas supply has to be exported via LNG primarily from the US Gulf Coast and compete in Asia or Europe against LNG or pipeline gas. At the same time, US natural gas has significantly surprised to the upside since Feb/March. The EIA’s Short Term Energy Outlook Dec 2019 forecast for US natural gas supply is approx. 3 bcf/d higher for 2019 and 2020 than forecast in Feb/March ie. more US natural gas than expected only increases the reminder that most of future US natural gas growth has to be exported. (iii) A lower mid to long term landed Asian LNG price. Our Oct 7 SAF Group 2020 Energy Market Outlook webcast [LINK] said we expected lower “mid term Asian LNG price of +/–$8”, which would link back to a HH price to a $2.50 –$3.25. We believe for capital allocation Chevron could be looking to stress test against Asian landed LNG prices even lower than our +/-$8, possibly in the $7 range. We don’t think they would be looking at a long term $6 Asian landed LNG price because, if they did, they probably wouldn’t be looking at any LNG. Since their March analyst meeting, a number of significant LNG or LNG alternative supply projects to Asian/Europe LNG markets have been confirmed or about to be confirmed – Qatar brownfield LNG expansions to add 6.5 bcf/d, Exxon’s 2 bcf/d initial phase for its greenfield Mozambique LNG to FID in early 2020, Total’s June FID for greenfield phase 1 Mozambique 1.7 bcf/d LNG, Total’s Nov announcement looking to FID brownfield Mozambique LNG phase 2 to add another 1.7 bcf/d, Gazprom’s Dec 1 start up of Power of Siberia 3.6 bcf/d gas pipeline to China, and final approvals to complete the Gazprom’s 5.3 bcf/d Nord Stream 2 pipeline to Germany expected on stream in mid 2020, plus a number of other items. (iv) Appalachia dry shale gas is disadvantaged vs associated natural gas from oil wells in Texas/Oklahoma or dry shale gas in the Haynesville. Associated natural gas from Texas/Oklahoma oil wells is almost like a by product, doesn’t drive the economics of the oil wells, and can therefore withstand lower gas prices. Plus there is a massive increase in Permian natural gas pipelines to bring associated natural gas to the Gulf Coast with the Sept start up of the 2 bcf/d Gulf Coast Express, 2.1 bcf/d Permian Highway pipeline to startup in late 2020, and 2 bcf/d Whistler gas pipeline to start up in Q3/2021. And the dry Haynesville is right at US Gulf Coast export points.
New And Upcoming Permian Natural Gas Pipelines To Gulf Coast Export Points
If Asian landed LNG prices are ~$7, it makes it extremely difficult for greenfield LNG projects like Kitimat LNG. Our outlook webcast highlighted how our view of lower mid term Asian LNG prices put an increasing necessity for LNG projects to minimize capital costs. And if Chevron has a sensitivity for capital allocation less than ~$8, it makes low capital costs even more critical. (i) Kitimat LNG. We have been saying that Chevron would need to get as close to brownfield capital costs as possible to go FID and, to do so, it would have to FID on Kitimat LNG years earlier than expected (ie. in 2020) to take advantage of a continuous LNG construction cycle on the BC coast. We detailed our thesis in our July 19, 2019 blog “Chevron’s Kitimat LNG Expansion Plan Points To A LNG Canada Phase 2 FID in 2020 and A Continuous BC LNG 2020’s Runway of ~6 bcf/d” [LINK]. The key being to keep the BC LNG service contractors after LNG Canada and to also line up the in demand Asian fabricators. However, if Asian LNG prices are ~$7 for a capital allocation decision, close to brownfield capital costs are likely not enough. Plus Chevron’s key working interest natural gas that would supply to Kitimat is from the shale gas play in the Horn River and not from associated natural gas from liquids rich Montney wells that have their economics driven by condensate and not the associated natural gas. (ii) Other greenfield LNG. There is no change to our view that the key will be to get brownfield capital costs, but a lower Asian LNG price means that it will be very difficult for future greenfield LNG projects to go FID unless they can meet a capital allocation decision under ~$7 Asian landed LNG prices. The other linked disadvantage of greenfield projects is that there is a longer time to first LNG sales. (iii) Brownfield LNG. A lower Asian landed LNG price will impact the returns of brownfield LNG projects, but these projects have two key advantages that should keep them as FID likely. The brownfield phases (ie. an LNG Canada Phase 2) have superior returns than the initial greenfield phase 1 that must carry all the costs of infrastructure. Whereas the brownfield phase only picks up the new capital costs related to a new train or two, but a lesser relative capital cost for any infrastructure expansion instead of starting from scratch. The superior returns in a Phase 2 are normally counted on to enhance the overall returns. The reality is that most LNG projects wouldn’t be going ahead if there is only a phase 1. The other big advantage is time to first LNG sales. The cycle times are much shorter and therefore there is less risk to returns with getting cash flow year quicker. (iv) The wave of LNG FIDs in 2019 also likely made it even tougher for Chevron to be close to brownfield capital costs. All of these FIDS are signing up LNG service contractors and Asian fabricators, which likely caused Chevron to re-evaluate their capital cost/time for Kitimat LNG. We don’t know the nature of LNG Canada’s contract with LNG service contractors and Asian fabricators, but we would be surprised if their contract for phase 1 didn’t include some sort of option/retainer for a continuous schedule or near term slot for phase 2. We expect all greenfield LNG projects have these option/retainers. Its why we see announcements like Total talk about phase 2 FID less 6 months after phase 1 FID. But it also means that a greenfield Kitimat LNG has to fight for slots with the new wave of greenfield plus their phase 2 brownfields.
Every $ of lower Asian landed LNG prices will squeeze netbacks for source US natural gas supply. We believe there is an increasing linkage of US natural gas markets to global LNG prices especially as most US natural gas growth will have to find its way to export markets. And if so, it means that all US gas is moving to primarily compete in the Gulf Coast export market. Every dollar change in assumption for long term Asian landed LNG prices has a material impact on netbacks for the natural gas supply for US Gulf Coast LNG exports. From the perspective of natural gas being supplied to a non fully integrated LNG project because US natural gas has to find export markets, US natural gas supply is forced to be a price taker for LNG transportation costs to Asia and Gulf Coast liquefaction costs ie. every $1 drop in Asian LNG prices basically flows thru to the gas supply netback. It seems like most estimates for LNG shipping costs to Asia via the Panama Canal are in the ~$1.75 to $2 range. Most estimates of liquefaction costs look at from the perspective of the LNG project operator for capital and operating costs. We think a reasonable range is $2.75 to $3. On the low end, we looked at the US Dept of Energy LNG Monthly report for Nov 2019 [LINK] that includes the weighted average export price by export terminal. Importantly, the DOE notes that “Domestically-Produced LNG Delivered –Volume (Bcf) and Weighted Average price ($/MMBtu) by Export Terminal per month 2019 –YTD” schedule that shows the volume and export price by LNG terminal. The DOE notes that “*Beginning with July 2019 data, with the exception of some commissioning cargos as indicated in Table 2(a), all average export cargo prices include liquefaction fees”. We graphed the July/Aug/Sept average export price including liquefaction fees and plotted average HH gas prices to give an approximate “actual” for liquefaction cost of ~$2.75. For the high end, we used Cheniere’s recent June long term Apache supply deal that included a liquefaction fee of ~$3. If we assume shipping and liquefaction is $4.50 to $5, it shows how slim the netbacks are for US gas supply landed at the Gulf Coast export facility ie. at Asian $7, its only $2 to $2.50 landed in the Gulf Coast prior to the transportation costs to get the natural gas from the field to the Gulf Coast. This is why the Appalachia dry shale is disadvantaged vs associated natural gas from oil wells in the Permian, Eagle Ford and Oklahoma where the primary driver of returns is oil price. It is also why Haynesville dry shale has an advantage in closeness to the Gulf Coast.
Henry Hub and Weighted Average Price Incl Liquefaction Cost For US LNG Exports ($/mmbtu)
Shouldn’t impact LNG Canada potential to add ~3.6 bcf/d demand, but is a negative to western Canada natural gas. (i) This should not impact the key mid term upside for western Canada natural gas – LNG Canada Phase 1 and 2 will create demand for ~3.6 bcf/d of western Canada natural gas or approx. 20% of total western Canada gas supply. We don’t believe this points to any lessening of our expectation for LNG Canada Phase 2 FID assuming LNG Canada is part of a continuous construction cycle with Phase 1. Phase 2 has superior economics to Phase 1 and will enhance the overall return for LNG Canada. If anything, the rash of LNG FIDs places an even higher probability for LNG Canada Phase 2 FID years sooner than expected to ensure a continuous construction cycle with LNG Canada, much like we are seeing play out with Total’s Mozambique LNG phase 2. Shell’s Oct 2018 “LNG Canada Final Investment Decision” [LINK] for Phase 1 (trains 1 and 2) “estimated integrated project IRR ~13%” “at LNG price of $8.5/mmbtu (Tokyo DES, real terms 2018)”, and also said Phase 2 would increase the IRRs saying there was “upside with trains 3 & 4”. (ii) Not moving on Kitimat LNG would not impact western Canada natural gas supply/demand until post 2025 as it would eliminate ~2.4 bcf/d of demand for western Canada natural supply post 2025. This would also impact valuations prior to 2025. Chevron has put the for sale sign up for Kitimat. But we believe Kitimat LNG is unlikely to go ahead unless it (Woodside and whoever buys Chevron’s interest) can commit to FID soon enough to be part of a continuous construction cycle with LNG Canada Phase 1 and 2 so it can minimize capital costs for a greenfield LNG project. (iii) Reinforces our view that any large greenfield BC LNG project is highly unlikely to proceed in the next few years unless it can get in the queue within the next year or two to tie up LNG contractor services and Asian fabricators following LNG Canada. (iv) We don’t believe this points to any impact on the ability of liquids rich Montney as supply for LNG Canada. The liquids rich Montney has a similar advantage as associated natural gas in the Permian – its economics are driven by liquids (condensate in Montney’s case) and not by the natural gas. But ultimately a lower long term Asian landed LNG price flows back into a lower netback for the source gas ie. more of a cap. (v) This flow back into a lower netback will disadvantage western Canada dry gas wells that rely on the natural gas to drive the well economics vs liquids rich Montney well economics that are driven by condensate. (vi) The near term impact on western Canada natural gas will come if Marcellus dry gas isn’t competitive in the US Gulf Coast as it will force even more Appalachia natural gas into markets like Eastern Canada and Midwest US increasing competition for western Canada natural gas.