It is not news to anyone impacted by the price of hydrocarbons that markets from natural gas, to NGLS, crude oil, and refined products are decidedly out of balance at present. Over the past decade, there have been more instances where ‘out of balance’ statements in the hydrocarbon complex were due to oversupply than undersupply. A temporary instance of this last occurred in 2020 when a pending undersupplied market was obscured by governmental restrictions on mobility. Where we now stand in late 2021, the ability of hydrocarbon producers to satisfy end-user demand is notably in question and signified in decadal highs for just about every molecule that can be defined in Btu terms.
In today’s Friday Focus, we will share some thoughts on how we got here, how long tight market conditions may last, and what factors could cause a pendulum swing to either balance or a return to oversupply. Realistically, hydrocarbon markets will rarely ever find balance for an extended period, primarily due to the fact that weather has a material impact on the production, transportation, and consumption of Btus. As a result, both producers and consumers should contemplate what actions can and should be taken to protect capital deployed, and ensure returns are such that future investment is possible in a myriad of market conditions.
In the early innings of the shale era, North American dry gas production growth swamped a market without a commensurate change in the ability to store more molecules or dispatch them to non-domestic demand sources. This led to the ‘shift to liquids’ which was the buzzword of the year from 2012 through the first half of 2014. Subsequently, the liquids complex (crude and NGL) suffered a similar fate, with oversupply permeating from production growth exceeding storage + export capacity, while demand growth remained essentially in line with historical norms.
The four years between 2016 and 2020 were marked by a production response to elevated/stable forward prices in the first few years of this 5-year window. Funding of this growth was not as skewed towards majors and large independents like it had been in the previous 5 years of the shale era. Distressed/non-core assets were shed in the pricing routes of 2015-2016, and the private equity-funded acquisition of these assets shifted full-cycle breakevens and financial motivations for this sector of the global energy complex.
Over this same general time period (2015 to present) there was also a slow down in the magnitude of investment by non-North American hydrocarbon producers. Another factor contributing to the current imbalance was the remarkable pace at which a negative narrative around the funding of fossil fuels accelerated. Over the past 6-9 months there have been numerous multi-billion dollar investment vehicles that have either wholly exited or drastically reduced their exposure/contribution to fossil fuel-related entities. Fast forward to the present and the lack of growth capital allocated to the global hydrocarbon producing community has left consumers on the other side of the ledger dealing with the ramifications of blindly believing excess supply was always $1.00/MMBtu, $10/Bbl, or $0.50 a gallon away from showing up in no time at all.
Magnifying, and in some ways amplifying, current issues facing global energy markets is the equally powerful narrative that supply chain constraints are the new normal. Until supply chain issues are resolved a surge in production growth will be hampered by access to necessary materials, technology, and even workforce needs required to ‘produce our way out of this. As a reminder upward price pressure is also exacerbated by access to capital, which can also be seen as a supply chain constraint. If the supply of dollars is diverted to renewable energy only, there is a risk that production growth will be delayed until owners of the reserves can self-fund. This could be multiple years in the future since derivative losses on significantly underwater hedges often mean a producer is both subject to receiving only $0.20/MMBtu for every $1.00 increase in price, or on the liquids side $2.00/BBl for every $10.00/Bbl increase.
One of the most quoted spikes in energy pricing in recent weeks is the prolific rise in European and Asian natural gas pricing. Each of these markets has chased the other towards peaks of approximately $40.00/MMBtu and modestly settled back toward the mid $30s. With exports of LNG likely to max out through the winter it is still no guarantee that European and Asian consumers will have access to the supply that they need. Clearly, this is what pricing to all-time highs signifies. As a result, governmental action has been taken in Europe and Asia, while the search for any substitute for an MMBtu of natural gas has also been explored. The result of rushing to alternative fuel sources is a spike in global coal pricing to decadal highs and in some instances all-time highs. It should come as no surprise that power prices in the most elevated natural gas markets are also sky-rocketing. In short, the search is on for ways in which demand might be curtailed, and/or ways that energy demand might be satisfied by fuel sources recently viewed as undesirable (coal, fuel oil, and even wood). Ironically, the rush to eliminate fossil fuels has led to a critical need for them. How this plays out over the next couple of decades is the topic of a different discussion.
A potential solution to the disconnect between various global markets and their corresponding flow of Btus is searching for which Btus can most efficiently be consumed in each market. Open markets are precisely designed to solve such problems, and they will do so if not manipulated or interfered with. However, when risks become almost unbounded there is a higher probability of non-typical influences becoming integrated. The aforementioned statement may be a bit abstract for some of our readers so we will attempt to provide an example of how this concept can be practically applied in our conclusion below, and what the resulting pricing impacts would be.
If a downstream LNG destination market is A) importing at max capacity B) curbing demand through higher prices C) importing alternative fuel sources at an increased rate D) tapping all known sources of incremental supply (European requests to Russia) and E) preparing to temporarily wave carbon emission penalties the only other solution is looking to heavy industry to shift its production to lower-priced markets. Alternatively, this can be solved through the price of goods. Consider a fertilizer, steel, or plastics producer with operations in Europe or Asia. In today’s pricing environment, it could make economic sense to ramp up production at alternative sites in North America in lieu of production in Europe or Asia. This would obviously reduce the Btu requirements in Asia and/or Europe and increase them in North America. Effectively this could aid in closing the $25/MMBtu plus arb. Of course, it would require spare productive capacity in North America for such industrial production. The concept of geo-switching may become a very necessary tool in the tool belt for markets seeking balance because the prospect of rationing basic need supply is not something that should even be possible in today’s modernized and connected world.
How long the current cycle will last is a question best answered by the public and private sectors’ willingness to consider a more balanced approach to an energy transition. Like energy markets, the public and private sectors are out of balance on the energy transition topic for the moment. A pragmatic approach to setting expectations on duration would be to expect at least a few years of elevated volatility, with an upward bias to prices with the caveat that weather is a force without equal, capable of obscuring or magnifying underlying market conditions.