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.

In many ways, Mark Detor defines why it is important to work with an energy advisor with regional energy market expertise. Mark was born and raised in Syracuse, NY, and spent a good portion of his youth playing baseball, basketball, and football. And when he was not playing any of those sports, there is a good chance that you could find him in one of upstate New York’s numerous lakes and rivers fishing for trout or bass. Always good at math, but unsure of what to study in college, Mark decided to pursue an engineering degree.

One of Mark’s claims to fame is that he graduated from every academic institution in and around Syracuse. After completing his Associate’s degree in Engineering Science from Onondaga Community College, he attended Syracuse University, where he graduated with a BS in Electrical Engineering and a Math minor. A few years after completing his bachelor’s degree, he got his MBA from Le Moyne College.

While at Syracuse University, Mark worked as an intern for the local utility, Niagara Mohawk. He began working there after graduation as an Energy Utilization specialist. In this role, Mark worked with large energy users to help them capitalize on various energy efficiency and rebate programs being offered by the utility.

Given his acumen for working directly with customers, Mark ultimately became an Account Manager with Niagara Mohawk for the largest commercial and industrial customers in central New York. In that role, he applied his expertise toward a variety of energy-related projects, including the evaluation of complex cogeneration systems. When the electricity markets in New York were deregulated in the late 90s, Mark moved over to Niagara Mohawk Energy Marketing, which was the deregulated affiliate of the utility company.

Over the next twenty years, Mark worked for a variety of Energy Service Companies (ESCOs), including Select Energy, Hess, Direct Energy, and NRG.  There he worked with and helped hundreds of commercial and industrial customers throughout New York and beyond. An expert in both natural gas and electricity supply, Mark was able to help a countless number of clients make good energy decisions for their businesses. In 2022, Mark had the opportunity to join the team at 5.

Clients who work with Mark enjoy a higher order of service and energy advice.  They benefit from his decades of experience in both the regulated and deregulated electricity and natural gas markets. Today, he continues to live in Syracuse and is one of the most accomplished and knowledgeable energy advisors in the company. Mark’s three daughters, Samantha, Grace, and Brittany are his pride and joy. And when he is not working to support his clients, he loves to play a bad game of golf and travel.

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.

Leaves are changing and temperatures are falling, which can only signify one thing: PJM’s coincidental peak season is behind us. In PJM, there are five Coincidental Peaks (5CP) that are determined by the five highest daily peak hourly loads for the summer. Once the 5CP season comes to an end, the utilities begin the process of calculating Peak Load Contributions (PLC) and capacity costs for the upcoming year. Typically, 5CP events occur in PJM when the hourly load forecast approaches 140,000 MWs. The summer of 2022 was no different.