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%.

Volatility continues to be the name of the game in the energy markets for Downstate New York and New England. An example is the rollercoaster ride of international liquefied natural gas (LNG) prices that rose to record all-time highs above $90/MMBtu in September before falling back down below $30/MMBtu in November. This recent drop in LNG prices has taken some of the premium out of both power and natural gas prices for this winter, but the cooler-than-normal temperatures over the past two weeks seem to have added a bit of fear into the minds of energy traders who are concerned that this could signal a colder than average winter.

Algonquin is one of the major pipelines that carry natural gas into New England from its origination point in New Jersey. The price for this winter’s (December – March) gas delivered on Algonquin is shown in Figure 1. This chart shows that prices in late July and August were trading near $35/MMBtu, but as international LNG prices fell throughout September and October, prices for this winter’s delivery dropped down to a low of $20, before rallying back up to around $28/MMBtu during the second half of November.

The New Jersey Board of Public Utilities (NJBPU) recently approved nearly $1.1 billion in transmission system upgrades to the state’s electricity grid. These upgrades will enable electricity generated from offshore wind assets to be connected to the power grid and are a part of the state’s plan of creating 7,500 MWs of offshore wind capacity by 2035. The project, the Larrabee Tri-Collector Solution (LTCS), is estimated to cost $504 million and was proposed by JCP&L and Mid-Atlantic Offshore Development, a joint venture of EDF Renewables North America and Shell New Energies US. The NJBPU also awarded additional onshore transmission upgrades to accommodate the additional generating capacity from LTCS and other planned offshore wind projects. These awards went to ACE, BGE, LS Power, PECO, PPL, PSE&G, and Transource at an estimated cost of $568 million. In a press release, the NJBPU stated, “These project selections will establish the first coordinated solution for offshore wind transmission in the U.S., testifying to New Jersey’s status as a national forerunner in clean energy production. This coordinated transmission solution will minimize cost and other impacts while supporting the continued expansion of offshore wind energy in the state.” New Jersey is looking to the Ocean Winds project as the first step in achieving the state’s offshore wind goals.

The Ocean Winds One project will be located approximately 15 miles off the coast of New Jersey (see Figure 1) with a generating capacity of 1,100 MWs through nearly 100 General Electric Haliade-X 12 MW turbines. These massive turbines are 850 feet tall with a blade radius of 750 feet. Ørsted and PSEG are the owners and developers of the Ocean Wind project, which will be New Jersey’s first utility-scale offshore wind farm. Project construction is scheduled to begin in early 2023, with commercial operations expected at the end of 2024. A second and adjacent project, Ocean Winds Two, is expected to add an additional 1,100 MWs of generating capacity. Construction on that project is not expected until 2028. The Oyster Creek Nuclear Station was closed in September 2018 and removed approximately 650 MW of generating capacity from the state’s grid. Ocean Wind One and Two are intended to not only replace that asset but also add an additional 1,550 MWs of carbon-free electricity capacity. Given the difference in availability of offshore wind compared to nuclear energy facilities, the additional capacity will be needed to help offset Oyster Creek production.

After Winter Storm Uri in February 2021, the Texas legislatures passed Senate Bill 3, which includes provisions intended to improve the reliability of the grid. One specific portion of this law in Section 18(3) calls for the competitive procurement of additional ancillary services to ensure there is enough electricity supply to keep up with demand during future severe winter weather events.

The Public Utility Commission ordered ERCOT to develop a “firm-fuel” product that would improve grid stability by procuring 3,000 to 4,000 MW of capacity from generation resources that do not depend on natural gas delivered through pipelines. The intent of this provision of the law is to ensure that a certain amount of additional deployable generation capacity can operate even during times of low natural gas pressure in the state’s pipeline system. This new ancillary service is known as Firm Fuel Supply Service (FFSS). The provision required the procurement of this additional reserve capacity to not exceed $54 million and covers the period from November 15 through March 15. In all, 2,941 MW of generation capacity was procured from 19 different generation assets across the state at a total cost of $52.9 million.

Eighteen of the nineteen assets that cleared the auction will use fuel oil (diesel) as the backup fuel source with only one asset relying on onsite natural gas storage capabilities. It is interesting to note that 77% of this capacity is from older, inefficient steam turbine power plants built between 1958 and 1978. These assets use steam, produced from boilers to spin the turbine blades which produce electricity. The remaining 23% of the FFSS capacity was procured from generators that entered service after 1988. These “newer” plants burn fuel in large gas turbine engines, similar to marine turbine generators used in naval and commercial vessels. These engines can run on natural gas, jet fuel, or diesel. A summary of the generating assets procured through this inaugural FFSS auction is shown in Figure 1.

Community solar is a financial structure implemented by states and utilities that allows the financial benefits of solar electricity production to be shared with members of the community. Here is how it works: A solar developer builds a solar project and sells all the power and renewable energy credits (RECs) generated to the utility in exchange for “solar credits”. Those solar credits are applied as a dollar value credit to utility bills, reducing the amount owed for electricity provided by the utility. The developers then sell their solar credits to members of the community at a discount. Community members sign contracts with developers to purchase solar credits at a set discount rate, a percentage savings on the dollar value of the solar credit. In New York State, the market-rate discount is 10%. That means that by signing a contract with a developer, an electricity customer in New York can pay $90 to a developer for solar credits that will reduce the customer’s utility bill by $100. In some cases, that $90 is paid to the solar developer (or a third-party billing company hired by the developer), and the $100 solar credit is applied to the customer’s utility bill. New York has consolidated billing, which means there are not always two separate utility bills. The $10 savings is subtracted directly from the utility bill and the customer pays only $90 to the utility. In the end, the developer receives 90% of the per kWh value of solar and the remaining 10% of the value is spread among the community solar subscribers.

On behalf of the team at 5, I am pleased to forward our November market letter. This letter discusses: (i) the upcoming Mid-Term Elections, and how the results could impact energy policy; and (ii) the challenges facing grid system operators in Texas, New England and New York as they work to integrate large volumes of intermittent resources into the grid mix.

The Mid-Term Elections

Recent polls favor Republicans to take control of the House and perhaps the Senate as well. As a result, several clients have asked what such a change in Washington could mean for energy policy. The question is particularly interesting because the landmark Inflation Reduction Act (IRA), which allocated some $369 billion to the energy sector, was passed by the Senate and the House without a single Republican vote.

The Inflation Reduction Act: The short answer is that the election results will probably have little effect on energy policy. While a change in control of the House or the shift of a single Senate seat would have doomed passage of this legislation, since it was passed and signed into law by President Biden, it will be difficult to repeal it. Even if the House and Senate pass legislation to repeal or amend portions of the IRA, President Biden has veto power, and overriding a veto requires a vote of two-thirds of the members in the House and Senate. This is good news for developers of renewable power, energy storage, electrical vehicle manufacturers and others that will benefit from the incentives found in the IRA. But this does not mean that the IRA and its various energy incentives are immune from challenges in the courts.

There are some interesting parallels between the IRA and the Affordable Care Act (ACA). Like the IRA, the Democrats used budget reconciliation to get the ACA approved by the Senate, and all Republicans in the House and Senate opposed the ACA. President Obama signed the ACA in March 2010, and in the November 2010 mid-term elections, the Democrats lost control of the House, in part, because of opposition to the ACA. The new congress did not reverse or upend the ACA, in part because politicians have little appetite for taking benefits away from voters. Yet the law became the subject of extensive legal challenges, one of which ended up in the Supreme Court.

While there is considerable opposition to the IRA, and it will undoubtedly face legal challenges, even though the law does not appear to be subject to the same serious constitutional challenges (for example, the constitutionality of the insurance mandate) that faced the ACA. In addition, as in the case of the ACA, we expect that in the two years remaining in the Biden Administration, a significant amount of the benefits will be granted to various energy projects. Once grants are made, it will be difficult if not impossible to reverse them.

Congressional Oversight: While the IRA may be safe from legal challenges, we expect that a Republican controlled house will use its oversight powers to review almost all aspects of the IRA and other programs that address climate change. This could certainly cause some delays in the implementation of the IRA’s programs and slow or halt other efforts to address climate change such as the SEC’s plan to require ESG reporting. For example, comments from Rep. Garland “Andy” Barr of Kentucky, a member of the House Financial Services Committee, indicated that ESG principles, “will be one of the major focuses of oversight of a Republican majority” adding that “My view is that ESG investing is a cancer within our capital markets,” Barr said. “It is a fraud on American investors.”

On the state level, we have already seen several states, pushing back against BlackRock and other investment firms that prioritize ESG principles. Texas has passed legislation that restricts the state’s retirement and investment funds from doing business with firms that “boycott” the oil and gas sector. Echoing this approach, Louisiana Treasurer John Schroder recently pulled $794 billion in pension fund money from BlackRock funds due to their use of ESG criteria in making investment decisions. “Your blatantly anti-fossil fuel policies would destroy Louisiana’s economy,” Schroder said. “In my opinion, your support of ESG investing is inconsistent with the best economic interests and values of Louisiana,” Schroder said.

Other than some minor changes to the approval process to FERC commissioners, we cannot think of other ways that a change in House or Senate leadership will impact federal energy policy – but as noted above, there is no shortage of ways in which the House and Senate can investigate the energy industry.

Looking past the mid-terms, if a Republican candidate is elected President in 2024, we might see an effort to pass legislation repealing the IRA. When President Donald Trump was elected in November 2016, Vice President Mike Pence stated, “President elect Donald Trump will prioritize repealing President Barack Obama’s landmark health care law right ‘out of the gate’ once he takes office.”

But as I expect will be the case with the IRA, once the energy community is offered the $369 billion in incentives, it will be very difficult for a future administration to repeal these benefits.

Permitting Reform: While repealing the IRA may be top of mind, the fate of Sen. Manchin’s effort to expedite permitting of critical energy infrastructure is equally important. In the run up to passage of the IRA, Senate Majority Leader Schumer agreed to support Manchin’s permitting bill (which included a requirement that Federal Agencies approve the controversial Mountain Valley Pipeline that Manchin supports) in exchange for Manchin’s support of the IRA. The bill seemed to be a good compromise, angering both Republicans who said it did not do enough for the fossil fuel industry and Democrats who said it did too much.

After the mid-term elections, it will be interesting to see if the Manchin bill can form the basis of bipartisan legislation that addresses the need to upgrade the nation’s energy infrastructure. As we note in the last section of this letter, there is a growing consensus among all participants that the grid envisioned by the energy transition does not yet exist. A recent Washington Post story is emblematic of the issue faced by new generation and transmission projects across the nation.

In this case, nearly ten years into the permitting process, a geo-thermal company had started construction of a plant that would provide carbon free energy to California residents. Late into this process, developers found out that: (i) the warm water drawn from the earth to power generation may threaten a rare toad, and (ii) the project’s location impinges on a sacred healing place for the Shoshone Tribe. The U.S. Fish and Wildlife Service has ordered the project stopped, while the Bureau of Land Management has pointed to the project as one of the ways the Biden administration is successfully confronting the climate crisis. This is just the kind of permitting delay that the Manchin bill was designed to address.

Intermittent Resources and The Energy Transition

Intermittent resources are generating assets that are not continuously available such as electricity that comes from wind farms and solar arrays. The growth of intermittent generation continues to challenge system operators who are responsible for ensuring a reliable supply of electricity. In the balance of this letter, we discuss ways in which intermittent supplies are challenging three markets, ERCOT, the New England ISO (NEISO) and New York ISO (NYISO).^[1]

ERCOT: In ERCOT, the state in the country with the highest volume of wind and solar generation, we are clearly seeing the challenge that intermittent generation places on the system operators responsible for managing the reliability of the grid. As shown in Figure 1, on one day in Mid-October, wind resources generated approximately 18,000 MWs in the morning and only 1,200 MWs in the afternoon. The variation of solar output is equally dramatic. The chart below shows the combined hourly output of wind and solar over the last several weeks.

Forward commodity markets were created to allow market participants to mitigate price risk for a given commodity. Long before the world ran on oil and natural gas, agricultural commodities traded in the forwards. By the 1860s, the Chicago Board of Trade was using standard instruments to trade wheat, corn, cattle, and pork. By the 1870s, the New York Mercantile Exchange was created by a group of Manhattan dairy merchants looking to standardize the chaotic butter and cheese markets. Over the next 100 years, these markets matured and expanded, but their purpose has remained the same: to create a marketplace that allows buyers and sellers to access a standard and liquid market that mitigates forward risk to commodity price volatility.

Often in commodity trading, it isn’t always the straight-forward market drivers that catch the market off guard. Rather it’s the counter-intuitive things that seem to side-swipe a market. Lately, there has been a negative correlation between the price of crude oil and the price of natural gas. This summer, a decrease in the price of crude oil has coincided with a rally in natural gas prices. This month, the inverse relationship between these two commodities will be examined in more detail.