EIA Predicts Lower NatGas & Electric Prices on the Way in 2023
Yesterday MDN poked fun at the gyrating up-and-down predictions from the U.S. Energy Information Administration (EIA) with respect to the spot price of natural gas at the benchmark Henry Hub (see EIA 2H22 Henry Hub Price Prediction Continues to Gyrate Up & Down). Our sarcasm and dry wit were lost on at least one humorless reader. Our point was that EIA tries to do the impossible–predict prices months or even years out. Nobody can do it reliably. But that doesn’t stop them from trying. EIA is predicting natural gas prices in 2023 will go down significantly from current levels, and along with the lower HH price, the price of electricity will go down too.
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Once a month, the analysts (interns?) at the U.S. Energy Information Administration grab the official Henry Hub pricing dart board and play a quick game to determine what price they will predict for the average Henry Hub spot price for natural gas for the rest of this year, and then an average price for all of next year. At least, that’s what EIA’s predictions have come to feel like. How else to describe the wild gyrations both up and down in EIA’s monthly Short-Term Energy Outlook predictions? Here’s what we mean…
Enverus, a leading global energy data analytics and SaaS technology company, earlier this week released Macro Forecaster, a new report that assesses the continued impact of COVID-19, the Ukraine war, and the weakening global economy on near-term oil and gas balances. Enverus predicts the price of oil will be somewhere in the range of $80s or $90s per barrel by the end of this year. The company also predicts natural gas will slump to about $4.50/MMBtu by next summer.
Not all that long ago, the spot (physically traded) price of natural gas around the Marcellus/Utica region, and the regions it feeds, including the Southeastern U.S., had some of the lowest spot prices for natural gas in the U.S. We recall being excited to see the price per Mcf (or MMBtu) get above $1 in northeastern PA. That all changed over the past year or so. According to RBN Energy, “cash and forward prices in the Mid-Atlantic and Southeast have rocketed, becoming the highest gas prices in the land, and in some cases are at never-before-seen levels for this time of year.” What happened? Why is the price so high now, in a region flooded with natural gas, where once we couldn’t get the price to go over a dollar?
There’s something of a mystery brewing–something nobody seems to be able to explain. Since January, the U.S. rig count has added 150 rigs–hitting the highest level of rigs active in the field since late 2019. In addition, new well counts are up, and more completions are happening. More rigs and more wells getting drilled and completed. Yet natural gas production this summer has evened out and is not increasing. Why?
Trying to follow the ups and downs of natural gas prices–predicting where prices will go–will drive you crazy. A little over one month ago, the NYMEX front-month futures price for natgas was hitting new modern highs, closing in on $10/MMBtu (see 
According to Bloomberg, natural gas is “the hottest commodity in the world” right now. Since the start of last year, the price natural gas fetches in Europe has risen a staggering 700 percent! In a separate article from the U.S. Energy Information Administration, the EIA points out the Henry Hub NYMEX price of natgas has doubled over the past 12 months. Natural gas, says Bloomberg, now rivals oil as the fuel that shapes geopolitics. And there isn’t enough of it to go around. This is a golden opportunity for the U.S. to produce and export more of it.
Wow! What a difference two years can make. At the dawn of the pandemic, the share price for publicly traded oil and gas stocks (in particular Marcellus/Utica drillers) was in the basement. With the pandemic now in the rearview mirror (we hope), and demand increasing for both oil and natural gas, the price of oil and gas has skyrocketed, and along with it, O&G companies are raking in the cash. How are M-U drillers using their newfound piles of cash to compensate investors?
Each month the U.S. Energy Information Administration (EIA) issues a monthly Short-Term Energy Outlook (STEO). In May, the STEO made the startling prediction that the average Henry Hub price for natural gas (the national benchmark) would average $8.59 for the entire second half of this year (see 
Yesterday the NYMEX natural gas price lost 20% of its value in a single day for the second time in two weeks. When news broke on June 14 that the Freeport LNG plant would not likely return to full service before the end of this year, the NYMEX front-month contract lost $1.42 (19.75%) to close at $7.19/MMBtu (see 
Strap in–the roller coaster ride continues. Yesterday the NYMEX Henry Hub front-month (July) futures contract for natural gas plunged 10%, by $0.62, following news that more gas was stored (“injected”) than previously anticipated by analysts and traders. Storage inventories rose to 2.169 Tcf (trillion cubic feet) for the week ended June 17 following a 74 Bcf (billion cubic feet) injection. Most people thought the injection would be no more than 60 Bcf. No doubt the ongoing outage at Freeport LNG pushing an extra 2 Bcf/d on the domestic market had something to do with the extra storage build. Models predict cooler weather is coming in the next few weeks. Throw it all into the pot–higher storage, Freeport offline, and cooler weather–and traders got spooked.
Freeport LNG provided an update yesterday to inform the public about what happened at its export facility just south of Galveston, Texas, situated on the Gulf Coast. Freeport said an “incident” occurred in pipe racks that support the transfer of LNG from the facility’s LNG storage tank area to the terminal’s dock facilities located on the intracoastal (i.e., north) side of Freeport LNG’s dock basin. None of the liquefaction trains, LNG storage tanks, dock facilities, or LNG process areas were impacted. Freeport originally said the facility would be back online in three weeks. That’s a pipe dream (pun intended). Yesterday Freeport revised their estimate to three months minimum before partial operations are back online. It will be the end of the year for full operations exporting all 2 Bcf/d are back online, according to Freeport.