Like a bat out of hell part three: Gas more resilient than oil
The third in a five-part series from the BRG energy and climate practice evaluates the impact of plunging oil prices on natural gas and LNG
The oil market crash will have critical knock-on effects on the production and price of shale gas in the US. Lower oil prices will remove a crucial production cost credit for associated gas output in major centres such as the Permian basin and the Bakken shale play. Lower oil prices will also keep down prices for liquefied petroleum gas (LPG) and competing natural gas liquids (NGLs), both of which are highly correlated to oil prices. This will reduce the production cost credit for NGL-rich gas output from prolific shale plays such as the Marcellus and Eagle Ford.
Our analysis and forecasts indicate that most producers will maintain output from existing wells, leading to sustained high gas production for the next few years.
The Energy Information Administration (EIA) estimates there were 7,576 drilled-but-uncompleted (Duc) shale production wells in the US as of March 2020. This is despite the severe reduction of oil and NGL price incentives for the continued drilling of oil-associated and other liquids-rich plays, and the likelihood of a sizeable number of bankruptcies leading to the potential abandonment of producing wells. The more productive of these Ducs can be economically fracked and brought into production at oil prices of at least $25/bl.
The volume of oil and gas contained in the Ducs is estimated to be enough to sustain oil production at current levels for over a year, but enough to sustain gas production for only less than half a year. Recent evidence suggests larger producers are continuing to drill through the downturn and that they will also frack and complete a substantial portion of their Duc inventories in Q4 2020.
Drilling of new oil wells in the Permian would require WTI spot and futures prices to maintain levels of at least $40/bl. However, the EIA indicates that Brent and WTI prices fell to a low of $10-15/bl in late April and recovered to only $20/bl in early May. That means gas production associated with oil- and liquids-rich plays will need to decline until prices rise sufficiently to stimulate additional investment in dry gas development, such as in the dry gas areas of the prolific Eagle Ford and Haynesville plays.
To support economic development of dry gas wells, gas prices would have to rise above the levels seen during early May, which have fluctuated between $1.62/mn Btu and $1.93/mn Btu, and eventually increase to a sustainable level of approximately $2.50/mn Btu. US gas prices are likely to remain low over the coming months, while there is still plentiful oil and associated gas production, and then increase to the levels needed to support increased new drilling for dry gas production as the economy recovers and demand for gas rebounds.
Our forecasts suggest a significant trend towards greater dry gas production as the economics for wet gas diminish with sustained low oil prices. The effect is even more pronounced if oil prices remain ‘lower for longer’ with an expected 18pc growth in US dry gas production from 2020-25 and a 29pc decline in wet gas production over the same period.
However, increases in gas prices will be moderate because of the abundance of US shale gas resources and the demonstrated resilience of shale producers. That means gas will remain a competitive source of supply over the coming years.
Impact on global gas and LNG
The outlook for oil and gas prices will also cause major changes in the global gas and LNG trade. LNG markets and prices were suffering even before 2020 as a result of mounting oversupply and unprecedented low spot prices, combined with substantial downward pressure on new long-term contract prices and in price reviews for existing contracts. Sustained low oil prices are bringing long-term oil-indexed LNG contract prices into closer alignment with rock-bottom spot prices.
The ample supply and sustained low prices for gas and LNG will support demand recovery from the pandemic crisis. The Covid-19-induced economic recession has reduced gas and LNG demand in Asia and Europe only moderately, at levels much lower than the 30% collapse in oil demand. The International Energy Agency (IEA) indicates that gas demand fell by 3pc year-on-year in Q1 2020 for North America, Asia and Europe, and that global gas demand is expected to decline by 5pc for 2020 overall. As a direct result of this decline, LNG intake has fallen in the fuel’s major import markets. For instance, Japanese LNG demand fell by 3pc in Q1 2020 and will likely decline by 1.1pc in 2020 as a whole. As a marginal source of swing supply, US LNG exports have felt an immediate impact, with the recent cancellation of up to 33 cargoes for loading in June—with potentially more on the way.
In a base case-scenario in which oil prices recover quickly, we project that US gas production will recover with oil prices, keeping Henry Hub prices at a low level. Meanwhile, there will be a substantial increase in European and Asian gas prices relative to US gas prices as the LNG supply glut and excess storage inventories are brought back into balance, as shown on the left of Figure 2. In a scenario where oil prices remain ‘lower for longer’—approximately $20/bl below our base case after 2025—US gas prices will increase the most due to lower associated gas production. As shown on the right of Figure 2, this will have an upward effect of at least $0.20/mn Btu on Henry Hub prices in the following years with only a low-to-moderate effect on European and Asian gas prices.
The result of these trends and sustained low oil and gas prices will likely be to generate bankruptcies, further reduce the sector’s access to capital, and delay or destroy a substantial amount of the planned investment in gas and LNG infrastructure. In particular, there are early indications of a sharp curtailment of new investment and financing activity in LNG production until investors become confident about when the market will rebalance. That timeframe will probably slip back from the early 2020s, as previously expected, until the late 2020s.
This would leave at least another year or two before new FIDs are needed so construction can begin. The list of project development and FID delays is already long and growing. For example, state-owned Qatar Petroleum has delayed its four-train North Field LNG expansion; ExxonMobil has pushed back FID for the 15.2mn t/yr Rovuma LNG project in Mozambique; US LNG developer Sempra Energy has delayed FID on its US-based Port Arthur liquefaction project until after Q3 2020; Australian producer Woodside Petroleum has delayed its Scarborough project and Pluto Train 2 expansion; and Australian independent Santos has indicated that it will postpone FID for the Barossa field development project along with a 38 pc capex cut this year.
However, contrary to the oil industry’s severe decline and slow recovery from the deep reductions in road, air and marine traffic, gas and LNG demand have declined by much less and will recover more quickly. This is because gas is consumed primarily for heating, which has been little affected by the pandemic, and for power generation and industry, consumption by both of which will rebound quickly as lockdowns end. As gas and LNG prices snap back faster than oil during the rebound, these fuels are poised to resume healthy trade and help accelerate the transition to a mix of economically and environmentally efficient energy sources.
This article is the third of a five-part series from the BRG energy and climate practice that analyses the near- and long-term effects of the Covid-19 pandemic on global energy markets, the energy transition and the climate-change imperative. The next article in the series will assess the effect of the pandemic on power market prices, the long-term implications for power generation and the outlook for renewables.
Chris Goncalves is chair and a managing director of the energy and climate practice at Berkeley Research Group, LLC (BRG). He has 30 years of experience in the LNG, natural gas, thermal generation and renewable energy industries, with expertise in energy markets, economics and finance. He provides both expert witness and business advisory services.
Robert Stoddard is a managing director in BRG’s energy and climate practice. He has over 30 years of experience as an energy economist in the US and European electric power industry, both as an expert witness and business advisor. He is also CEO of an ocean wave energy technology company and a member of the Energy Working Group of the State of Maine Climate Council.
Alayna Tria is an associate director in BRG’s energy and climate practice. She specialises in financial, market and economic analysis for business advisory and dispute resolution in the areas of oil, natural gas, LNG and renewables.
Tristan Van Kote is a senior associate in BRG’s energy and climate practice. He provides analysis in the areas of power and natural gas markets, climate change policy and project finance.