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Energy Market Update: August 24, 2020

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With so many moving parts in the energy and gas markets, it's often hard to know which pieces to pay attention to. 

Fortunately, Direct Energy Business Strategist Tim Bigler is here to break down this summer’s most consequential movements in this week’s Energy Market Update.


Natural Gas Prices Climbing

After a period of stability following April’s turbulence in the markets, natural gas futures have spiked in cost over the last month. The 2021 calendar year strip was priced at around $2.60/MMBtu in mid-July; today, that same strip is close to $2.90.

To complicate matters further, prices are up for the forseeable future. In the lead-up to April, futures prices were following a contango pattern, meaning that prices for shorter-term contracts were lower than prices for longer-term contracts. 2022 contracts were cheaper than 2023 contracts, which were cheaper than 2024.

Now -- following a shaky April-July period -- prices for these calendar strips have spiked, clustering around the $2.55 range. One notable exception is calendar year 2022, which is trading near $2.65. Needless to say, these futures have eschewed their contango pattern. Also of note, however, is that 2021 and 2022 strips are relatively expensive compared to 2023, 2024, and 2025 strips. Previously, contracts expiring further in the future were priced at a premium -- but if the market continues in the direction we are seeing this month, this may no longer be the case.

It is important that these strips are no more expensive than they were a year ago. In fact, a few (notably 2024 and 2025) are significantly less expensive than they were in August of last year. While we are seeing a spike in futures prices virtually across the board this month, these prices are still moderate within the context of the last 12+ months.

A consistent theme of natural gas markets in recent years has been the growing role played by gas in electricity generation. With that in mind, an assessment of energy prices across various U.S. regions in recent months may reveal what effect (if any) higher gas prices can have on the price of energy futures.


Effects of Gas Prices on Power


California is the exception to the rule. The state has experienced rolling blackouts and power shortages due to a devastating heat wave which has sparked wildfires and forced power plants offline. As a result, prices in CAISO’s SP15 (Southern California) region have shot up dramatically.


In Texas, ERCOT serves as an example of what happens when electricity generation is heavily dependent on gas -- as Henry Hub natural gas prices go up, so do Texas prices. It should come as no surprise, then, that the calendar strip for 2021 power futures in ERCOT has seen a price surge corresponding to similar movements in the natural gas markets.

NYISO, PJM, New England, COMED

In contrast to ERCOT, other regions in the country may be benefiting from favorable basis prices. “Basis” refers to the price differential between the Henry Hub national benchmark price and the actual available price in a given region. If basis prices within a region are negative, then gas is cheaper there compared to the Henry Hub price. For this reason, regions exhibiting negative basis prices may be less sensitive to market shocks, and prices in these regions will not spike as dramatically. This phenomenon is an example of a counterforce against rising natural gas prices. Other factors, like renewable energy growth, smart demand response programs, and more efficient gas-burning power plants can also keep power prices relatively low in cases of expensive gas.


Shift in Gas Supply & Demand

Supply and demand make price -- it’s a basic idea, though never quite as simple in practice. In the wake of the pandemic, two things have happened: total year-over-year supply of natural gas in the U.S. (from imports and domestic production) has dropped by about 4.5 Billion Cubic Feet (Bcf) per day; at the same time, total Y-O-Y demand has dropped by about 1 Bcf/d. The result is that net demand is about 3.5 Bcf/d higher than it was a year ago.

What does this mean? Heading into the COVID-19 crisis, Liquefied Natural Gas (LNG) exports were at an all-time high of more than 9 Bcf/d. Exports subsequently crashed as the world shut down and industrial usage slowed, leaving LNG exports at a low of 3 Bcf/d in July. However, in August alone, LNG has rebounded to almost 5 Bcf/d, taking many analysts by surprise. Meanwhile, U.S. exports into Mexico have been climbing since the pandemic began, even setting a new all-time high of 6 Bcf/d in late July (up from 4 Bcf/d in May). In just a short time, 4 Bcf/d of incremental natural gas demand has been introduced into the market.

In addition, the power sector is demanding more natural gas for electricity generation than ever before. Last month is likely to rank as one of the hottest Julys in history, and with so many folks working from home, demand approached 45 Bcf/d at the month’s peak (up from ~41 Bcf/d in 2019, and much higher than the 5-year average of ~37.5 Bcf/d). This is a result of new, efficient plants coming online which can create more power out of less gas. These plants make gas a more attractive resource for power generation, assuming gas prices remain relatively low.

What about the industrial sector? Natural gas demand here dropped, as the world shut down from March through June. But now, demand from the industrial sector has crept up to 21 Bcf/d, which is above the 5-year average level, but below 2019 levels. Should this trend continue, industrial gas demand will be as strong as ever toward the end of 2020, adding to the overall demand picture and thereby boosting net demand.


The Other Side of The Scale

Demand is up in general, and so is net demand. But there is also supply to consider. Baker Hughes collects data on active rigs -- oil rigs, horizontal rigs for shale, and natural gas rigs. By their count, all three groups are running all-time lows: 207 horizontal rigs, 172 oil rigs, and just 70 gas rigs are currently active. This implies reduced production. The last time gas (and oil, for that matter) spot prices dropped below the $2/MMBtu ($50/Barrel for oil) price floor was back in 2016, and we saw a dramatic drop in active rig counts then, too. The difference now is that today’s rigs are much more efficient; an active rig can currently produce up to 50% more gas than a rig could in 2016. This means that you need fewer rigs to produce the same amount of gas and it also means that every inactive rig corresponds to a greater loss of production than before. This could signal a longer-term dip in production, and potentially also another reason for prices to continue climbing.

Finally, the natural gas storage situation suggests a possible price support. Current storage levels are over 3.3 Trillion Cubic Feet (Tcf), which is 22% higher than this time last year. A portion of this surplus could be reintroduced into the market in the event that routine production tapers off. Alternately, producers could redirect some gas meant for storage back into the market instead, and the current surplus would keep levels safely in the same range as 2019. While strong forces are elevating demand, production may enjoy some tailwinds of its own as we enter the autumn of an eventful year in the markets.

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Posted: August 24, 2020