Default Gas Supply Rate Trends for New England Utilities

For most New Englanders September is a time to enjoy what remains of the warm weather, begin another season of Patriots football, and start thinking about the upcoming heating season. Early September is a great time to get your heating equipment serviced and budget for expected heating costs. Nearly all natural gas consumers in New England (except a handful of municipal systems) have the choice between the local utility and competitive gas suppliers for the commodity portion of their natural gas requirements. 

Over the last year or so, many small and medium sized natural gas consumers have realized that the default supply costs offered by the utilities are better than the offers from competitive energy suppliers. This is especially true for winter heating loads where natural gas usage is concentrated between November and March. The default supply price offered by natural gas utilities can go by many names. In New Hampshire and Massachusetts, its known as the Cost of Gas (COG). In Connecticut, its called the Purchased Gas Adjustment (PGA). In Rhode Island, its known as the Gas Cost Recovery (GCR). The graph below shows the default natural gas supply rates offered by various New England utilities to a medium size commercial customer who uses natural gas primarily for winter space heating.


Nat Gas Default Rates.png

Despite the geographic proximity of these various utilities, you'll note significant variations in the seasonal cost patterns. National Grid in Rhode Island changes the GCR infrequently and holds it steady for many months at a time. Unitil's New Hampshire gas division tends to have the highest COG due to constraints associated with the utility's geographic location and the composition of the COG. All of the other utilities tend to follow a similar pattern where natural gas supply costs go up in the fall and drop in the spring. Oftentimes, the natural gas supply cost offered by Massachusetts and Connecticut utilities is below market during the spring and summer months. This trend of below market supply costs during certain warm months has repeated itself over the last few years and is a result of the way the utilities are regulated. They are prohibited from making a profit on the sale of the natural gas commodity and instead earn their rate of return through the distribution rates. At the conclusion of the winter heating season, if they have over-collected revenues from consumers relative to the actual costs of their natural gas supply portfolio, then they will refund any overcharges to consumers in the form of below market rates until any surplus has been dissipated. 

The natural gas supply prices offered by New England utilities will reflect the broader regional natural gas price environment, but there is a lag between current market conditions and the supply rates offered by the utilities. Note that the rates for last winter do not reflect the volatility and high prices experienced in the New England spot market during that time period. In addition, although the utilities are prohibited from making a profit on the sale of natural gas to customers, they are not prohibited from engaging in prudent hedging, risk management practices, and utilization of existing long-term contracts for pipeline capacity. Existing long term contracts for pipeline capacity, when included in the utility's calculation for default natural gas supply costs, currently have the effect of reducing the winter basis component of the gas supply price relative to current market prices. Each utility is unique and this phenomena varies in its price impact on natural gas supply costs offered by each utility in the region.

For a small to medium size consumer with a natural gas load primarily driven by winter heating, the reduced cost of basis enabled by existing long term pipeline capacity contracts embedded in the utility gas supply portfolio can make the utility a better option than competitive supply (at least in this market). When a consumer gets a quote from a third party energy supplier, the quote is driven by the individual cost to serve which will reflect current basis quotes, current NYMEX natural gas quotes, and the amount of peaking and storage capacity that must be acquired to serve the account. The graph below shows the current quotes for basis swaps on the Algonquin natural gas pipeline.

Algonquin pipeline monthly basis swap price data from 9/6/2013. NYMEX OTC symbol NYMEX.B4

Algonquin pipeline monthly basis swap price data from 9/6/2013. NYMEX OTC symbol NYMEX.B4

Note that January 2014 basis is trading just below $0.80/therm. If the NYMEX contract for January 2014 is approximately $0.40/therm and capacity and supplier margin for a winter heating driven gas load add another $0.10/therm to the total cost to serve, then a typical winter heating consumer could see a quote from a competitive energy supplier of $1.30/therm for the month of January 2014. Over the course of the winter heating season, a smaller natural gas consumer with a load driven by space heating requirements will likely see quotes for natural gas supply in excess of $1/therm. While its possible that they may still beat the utility (and you'll only know this in hindsight), it's unlikely. For large natural gas consumers, competitive supply is often the better option, but for the smaller consumers who need natural gas for heating, just taking the utility default gas supply option is looking better and better.

Dual Fuel Capabilities - More Valuable Than You Thought

Hi all,

Until natural gas prices started to collapse in late 2008, it was common for large facilities to optimize between fuel oil and natural gas based on the price of each fuel. Since Nov. 2008,  burning natural gas has been a no-brainer and any dual fuel activity has been centered around utility interruptible programs, not economic optimization. The natural gas prices experienced in the Northeast over the last ten weeks makes me think that many end users exposed to spot natural gas rates may want to revisit their dual fuel strategies. 

The delivered costs of No. 2 and No. 6 fuel oil vary based on customer location and purchase quantities, but generally speaking the current delivered price in the Northeast for Nos. 2 and 6 fuel oil are $24/MMBTU and $16/MMBTU, respectively. For the last several years, natural gas prices have almost invariably been below the price of fuel oil, but as the graphic below demonstrates, there have been several days this winter when burning oil instead of natural gas would have been economic for anyone exposed to spot gas rates.


Although every facility will have different opportunity costs and operational constraints around their ability to switch fuels, lets walk through the economics for a hypothetical oversimplified customer. Lets presume that we have a facility that burns 500 MMBTU/day and purchases natural gas with an energy supplier. Lets presume that the gas supply contract is based on a gas daily spot price plus a fixed $/MMBTU fee and that this customer can switch fuels instantaneously with no opportunity costs. If this customer is located in the New York City area and buys natural gas based on the Transco Zone 6 NY price benchmark, they could have saved either $22,000 or $42,000 by burning Nos. 2 or 6 fuel oil, respectively on days when the Transco Zone 6 NY index exceeded the price of fuel oil. If this customer is located in New England and buys natural gas based on the Algonquin City Gates price benchmark, then they could have saved either $24,500 or $75,000 by burning Nos. 2 or 6 fuel oil, respectively on days when the Algonquin City Gates Index exceeded the price of fuel oil. I've found that the more sophisticated natural gas suppliers (e.g., Hess, Sprague) are good at helping customers execute a dual fuel strategy, but if this winter is a harbinger of things to come in the physical gas market, I'd dust off your dual fuel policies and procedures.

New England's Wild Winter Power Market

Hi all,

This is a blog post I've been meaning to write for some time. New England is increasingly dependent on natural gas for power generation. This is unlikely to change anytime in the near future (good luck trying to build anything that isn't gas or renewables). In the last ten weeks, we've seen clearly that New England's heavy reliance on natural gas has a trade off which is extreme price volatility when physical natural gas supplies get tight due to high demand for natural gas from winter heating load on very cold days. 

Although there are five natural gas pipelines in New England, the Tennessee and Algonquin Pipelines are the most important due to the volume of gas they deliver to the region and due to the high quality pricing data associated with New England zones of each pipeline. Prices for Zone 6 of the Tennessee Pipeline and Algonquin City-Gates tend to be similar. The stunning increase in price volatility in daily physical spot natural gas prices is clearly shown in the graphic below. The winter of 2010-2011 was cold and snowy and spot prices flirted with $15/MMBTU in January 2011 (which I thought was high at the time). Each winter and summer since then we've had some transient price excursions to near ten bucks, but nothing all that worrisome from the perspective of the consumer. Then, around Thanksgiving 2012 things started to get crazy. 

Algon CGs.png

This graph is very important for power prices because the New England deregulated electricity market, administered by the Independent System Operator of New England (ISO-NE), uses a pricing system where the spot price for power is set by the cost of the last marginal unit of supply used to meet the last marginal unit of demand. As demand increases, higher cost units come online to meet the increasing demand. This is called merit order dispatch. Most natural gas power plants do not have firm delivery contracts for natural gas. They take what is known as interruptible service and are price takers for whatever the spot price of natural gas is on the pipeline that serves them. They bid into the ISO-NE marketplace based on the spot price of natural gas, the heat rate of the power plant (to be discussed in future blog posts), and whatever margin they require. When prices for spot natural gas go berserk, natural gas power plants offer into the market at prices that reflect the cost of their input fuel. Now that ISO-NE is heavily reliant on natural gas power generation, this causes power prices to come unglued as detailed in the graphic below.

Algon CGs and MA Hub Avg DA LMPs.png

The purple bars represent the Algonquin City Gates Mid-point spot natural gas price. The blue represents the average ISO-NE Day Ahead Locational Marginal Price (DA LMP) of electricity at the Mass Hub pricing node. The natural gas prices are shown on the axis on the right side of the graph. Up until the last three months, spot natural gas prices over $20/MMBTU were very rare. Now, they seem to be occurring weekly. I'm going to delve deeper into this topic in the coming weeks, but I bet there are a lot of energy consumers out there who can't wait until spring.