Hurricane season officially began this month and in a report at the end of May, NOAA predicted between 17 and 25 named storms for the period between June 1 and November 30. According to NOAA, “The upcoming Atlantic hurricane season is expected to have above-normal activity due to a confluence of factors, including near-record warm ocean temperatures in the Atlantic Ocean, development of La Nina conditions in the Pacific, reduced Atlantic trade winds and less wind shear, all of which tend to favor tropical storm formation.” It is only three weeks into hurricane season and Tropical Storm Alberto has already pounded Mexico and parts of Texas with torrential rain and flooding. Many clients ask how hurricane and tropical storm activity affect energy prices. In the past, significant hurricane activity in the Gulf of Mexico had a major impact on natural gas prices. In the 1990’s, hurricane tracking was one of the most important fundamentals energy traders watched. The destructive capabilities of a powerful hurricane in the Gulf of Mexico heading towards the large production regions (Corpus Christi TX to Mobile AL) would cause drilling and production platforms in the Gulf to evacuate their personnel, typically requiring the well to be closed. This would result in a dramatic reduction in the amount of natural gas produced for a week or more if there was substantial damage to the platforms. As shown in Figure 1, the highest natural gas prices in the last thirty years occurred in the wake of Hurricanes Rita and Katrina in 2005. Both storms caused major disruptions to the production and flow of natural gas.   

On behalf of the team at 5, I am pleased to forward our May 2024 market letter.  In this edition, we discuss several interrelated topics.  First, we look at ongoing legal challenges to two new federal energy regulations, (i) the SEC’s climate change reporting rules, and (ii) the EPA’s new power plant emission standards. Second, we address a question we are hearing often from our clients, especially those faced with rising energy prices: “Could President Trump’s election reduce the price of electricity?”  

In late January, the Biden Administration paused all LNG export facility applications, so that the Department of Energy (DOE) can assess whether any additional LNG export capacity is in the public interest. There seems to be a little confusion in the general public as to what exactly this pause does to short-term and long-term LNG export capacity and therefore natural gas supply and price. We thought it would be helpful to illustrate what this suspension means in terms of actual natural gas supply and demand.

We will skip the politics of the decision for now and jump straight to the facts of the matter.

First, this suspension only impacts pending applications requesting to export to countries without a Free Trade Agreement in place with the US ¹. That’s the first carve out. Second, there is already 14.28 Bcf/day of export capacity in operation in North America (not affected by this order), and another 12 Bcf/day under construction (also not affected by this order). Finally, there is also another 22 Bcf/day of approved capacity not yet under construction (also not impacted by this order), most of which is still working toward a Final Investment Decision (FID), meaning the developers of the sites are still trying to gather enough long-term contracts to move forward with the construction phase of the project.

All in all, by the end of 2026, North America will have a total daily output capacity of almost 25 billion cubic as shown in Figure 1. To put that into perspective, the total global LNG demand in 2023 was about 400 million tons, which is the equivalent of about 53 Bcf/day. The entire market demand is currently 53 Bcf/day, the US, Canada, and Mexico have 14 Bcf of active export capacity online and another 34 Bcf of capacity under construction, or approved (bringing the total to 48 Bcf). Given that the US is not the only game in town (Russia and Qatar also have another 27 Bcf/day in development), it seems as though our future LNG export capacity might exceed global demand, even with forecasted demand growth ².

While it has become common over the last few years for the bears of the natural gas market in the US to rule the month of December and drive down the coming winter’s (January and February) contract, this fall it seems like December came early. For almost the entire month of November, warmer-than-normal weather forecasts, both weekly and monthly, have been relentless for any traders holding on to long positions.  Since Halloween, the Dec. ’23 – Feb. ’24 strip has dropped about 75¢, from $3.65 down to $2.90 per MMBtu as shown in the blue line in Figure 1. This chart also shows that prices have fallen for the April 2024 to November 2024 strip (black line) over the last several weeks. 

On behalf of the team at 5, I am pleased to forward our September market letter. If you had any doubts that the energy transition is happening, recent events in Texas and New York confirm that the answer is yes. As discussed below, these states have very different approaches to energy regulation, and both have struggled to incorporate intermittent resources in the energy mix. For clients in Texas, New York, or any other deregulated market, planning for the challenges of the energy transition, including increased regulatory risk, should be a key component of your energy management strategy.

One of the most utilized pieces of fundamental analysis in the natural gas industry is the Energy Information Agency’s (EIA) Natural Gas Storage Report, which is released every Thursday morning at 10:30 ET.  This report summarizes the results of a weekly survey of most natural gas storage facilities across the US and shows how much natural gas the nation has in storage. It also gives a regional breakdown, along with a reference to normal storage levels for each week of the year as shown in Figure 1.  Many industry analysts use this data and the amount of natural gas in storage compared to what is normal (the 5-year average is commonly used) to understand and forecast natural gas prices.

On May 11, 2023, the U.S. Environmental Protection Agency (EPA) proposed new rules designed to limit emissions from existing and new coal and natural gas fired power plants. This is the EPA’s third swing at regulating CO2 emissions from power plants. Its first at-bat dates back to 2015 when the Obama Administration’s EPA introduced the Clean Power Plan (CPP). The CPP proposed state-by-state emissions limits. These limits were quickly challenged by numerous states, particularly those with significant amounts of coal-fired generation. While these legal challenges were ongoing, President Trump was elected. Trump scrapped the CPP and introduced the Affordable Clean Energy Rule (ACE), which overrode the CPP and gave the states more power to set their own emission limits. The ACE also faced challenges in the courts.

In June 2022, the Supreme Court issued a ruling in West Virginia v. EPA that significantly limited the ability of the EPA to regulate emissions without a clear mandate from Congress. This ruling assures that the EPA’s new proposed rules, if finalized, are likely to face a lengthy legal battle.

The latest EPA plan sets out aggressive emission reductions and is likely to further accelerate the retirement of fossil fuel generation units. By 2030, the EPA plan requires any coal plant that intends to operate past 2040 to use a carbon capture and storage (CCS) system to eliminate 90% of its CO2 emissions. Large natural gas generation units will also be required to install a CCS that captures 90% of their carbon emissions by 2035 or operate on clean hydrogen by 2038. While there are different restrictions for smaller generation units, the EPA’s rules lean heavily on carbon capture, clean hydrogen and in some instances, use of dual-fueled gas plants with both natural gas and green hydrogen. At the same time, the EPA has acknowledged that CCS and clean hydrogen are not yet in widespread commercial use.

As filed last week, the EPA plan is a proposed rule, and the EPA will need another year or so to issue a final version. Once the final version is issued, states will have another two years to submit plans to comply with the regulations. This timetable will be delayed further by the inevitable legal challenges. West Virginia Senator Shelley Moore Capito and Attorney General Patrick Morrisey have already vowed to lead congressional and legal efforts to kill the rule.

A few things are clear. First, if the rules are adopted, the cost of generating electricity from coal and natural gas plants will increase dramatically. Second, even if the prospects for the EPA’s new rule are limited by various challenges, the proposed rules will cast a shadow over new investments in existing and new fossil fuel generation. Testifying before FERC on May 4, 2023, a bipartisan panel of FERC commissioners (2 Democrats and 2 Republicans) raised their shared concern that the reliability of our electricity grid is challenged by the fact that we continue to see fossil plants retire at a rate far faster than they are replaced by new emission-free generation. Of course, we will continue to monitor this important regulation on behalf of our clients.

Earlier this month, the weather sage, Punxsutawney Phil, saw his shadow, retreated into his burrow and proclaimed six more weeks of winter. The problem is that Phil doesn’t seem very plugged into the latest meteorological observations or forecasts. Natural gas markets aren’t listening to Phil either. In fact, just looking at natural gas prices, one might guess that winter either never arrived or ended when the Astros won the World Series in the first week of November. Figure 1 shows how natural gas prices for the calendar year 2023 (blue line), 2024 (black line) and 2025 (green line) have traded since January 2021. This chart clearly shows that prices have dramatically fallen across those three calendar years over the last six months. On September 1, natural gas for 2023 was trading at $6.69/Dth. Today, it has lost 60% of its value and is trading at $2.70/Dth. Prices for 2024 and 2025 have fallen by similar amounts. This natural gas correction is being driven by a very mild winter and warmer than average temperatures.

On behalf of the team at 5, I am pleased to forward our February market letter. This letter discusses: (i) the recent fall in natural gas prices and increasing natural gas price volatility, (ii) the 188th Congress and the potential impact of the election on Federal and State energy policy in 2023, and (iii) how the electricity grid held up during Winter Storm Elliott and the February cold snap.

What a difference three months make in the constantly changing landscape of the natural gas market in the US. Last September, the December delivery contract for NYMEX’s Henry Hub, was trading at approximately $9.50/MMBtu, while natural gas prices in Europe were trading near $90/MMBtu. On November 28, the December contract settled for the last time at a final price of $6.65/MMBtu, a drop of almost $3.00 from the August high, while major European trading hubs are now near $30/MMBtu.

There were several factors that moved future prices for this winter’s gas delivery down from its late-summer highs. However, many of those bearish influences have started to change and reverse direction.

First, inventory levels of US natural gas in storage grew through the months of September through November at a pace that was significantly higher than expected. In late August, the market consensus was that the US would have about 3,400 Bcf of natural gas placed into underground storage facilities. That belief was dramatically changed when more than 100 Bcf of gas went into storage for six of the next seven weeks. The 1,004 Bcf of injections between weeks ending September 2 and November 11 was almost twice as much as in 2020, and the largest of the last decade.

Those injections came to a dramatic reversal on the Wednesday before Thanksgiving when the EIA reported the first withdrawal of the season of 80 Bcf, with an even stronger withdrawal expected for Thursday, December 1. Figure 1 shows that the gap between gas in storage and the five-year average was reduced from 10.5% in late August to 0.4% on November 11. Last week’s 80 Bcf withdrawal was enough to open that gap to 3.3%.