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A Site Selection Web Exclusive, March 2018
WEB Exclusive story

Lessons from the Neverending Winter

Experts urge customers to lock in rates as 2018 energy prices increase.

by Tim Comerford and Joe Santo

How can companies plan for energy price swings this year? There is a tug-of-war going on right now in the natural gas market. On one side is increased demand from cold weather, exports and liquefied natural gas, which puts upward pressure on pricing. That is being offset by a large supply of natural gas and increased production on the other side.


For much of 2017, the Henry Hub Spot price for natural gas averaged $3.12 per dekatherm (dth), a 19.5-percent increase over the 2016 price of $2.61. The U.S. Energy Information Administration (EIA) is forecasting a natural gas price of $3.21 per dekatherm (dth) for 2018, a 2.9-percent increase since last year. Meanwhile, the cold in January saw that price spike to nearly $7.00 one week, and to just over $5.00 two weeks later:


Now is the time for customers to lock in their energy supply rates to maximize savings.

Impacted Regions

Natural gas prices are spiking nationally, but the Northeast is seeing the greatest swings. In some areas of New York, the average spot price for natural gas rose to over $50.00/dth for the first week of the year, versus the average 12-month strip price on the NY Mercantile Exchange of just under $3.00/dth.

We have not seen anything like this since the 2014 polar vortex. The culprit is the fact that the Northeast does not have adequate pipeline capacity to transport natural gas from Appalachia into the New York region. ISO New England’s 2018 Regional Electricity Outlook, published in February, reports that new gas-fired power generation capacity is growing by leaps and bounds, but the pipeline development to get the gas there is not.

Although the Northeast is the most susceptible to large price swings, other parts of the country are also impacted. According to Bloomberg Markets, prices doubled in the Dominion South hub, which supplies Southeast Pennsylvania, Eastern Ohio, Maryland, West Virginia and Virginia. Natural Gas Intelligence (NGI) reported that prices were up $2.00/dth throughout Texas.

EIA’s 2017 average retail price for commercial customers was $7.97/dth with a forecast calling for a slight increase (0.6 percent) in 2018. The industrial sector’s 2017 price was $4.20/dth with a forecasted increase of 2.4 percent in 2018. 

However, as shown in the chart below, actual delivered prices vary considerably based on market sector and region of the country:


Despite the short-term volatility, longer-term future contracts have remained stable due to increased production. However, prices are on the rise throughout the energy industry.

Electricity Volatility

Wholesale electric prices have been extremely stable over the past three years, but a price increase could be seen in 2018. Even as spring arrives, the record cold we have seen blanket the country is also creating price volatility for electricity. The EIA reported in March that Southern Company set a new 12-month daily peak demand high on January 18 at nearly 46 GW. In Texas (ERCOT), a new all-time winter peak demand record was set at nearly 65.8 GW on January 17, far above the record before this winter of 59.7 GW set last January.


Electricity prices are highly correlated with natural gas prices, as natural gas is the input fuel to electric generation facilities across the country. Consequently, the run-up in natural gas prices seen at the start of the year has had a direct impact on electric rates. According to ISO New England, wholesale prices have topped $200 per megawatt-hour (MWh) — more than 10 times the typical price.

The Energy Information Administration (EIA) expects a 3-percent increase in commercial rates and 2.7-percent increase in the industrial sector in 2018, compared with last year.

Where Do We Go from Here?

Short-term pricing for natural gas and electricity has been impacted by the weather. As the cold trend has continued and New England has been struck by four consecutive weeks of Nor’easter storms, heating demand has increased and larger withdrawals from storage have resulted.

As of mid-January 2018, working gas in storage was 2,584 billion cubic feet (bcf). This was 368 bcf less than last year and 362 bcf below the five-year average. On March 16, working gas in storage was down to 1,446 bcf. In fact, as shown in the chart below, storage has been below the five-year average for a very short period over the past two years. If forecasts are correct, there will be a large deficit to the five-year average coming out of the winter and this will drive prices skyward.


According to the EIA, during what has been called the longest sustained period of high temperatures under 20 [Fahrenheit] degrees in over a hundred years in New England, “many natural gas demand records were set during the first week of January, culminating in a massive 359 billion cubic feet (Bcf) of natural gas withdrawn from storage for the week of December 30 – January 5. This far surpassed the previous record draw of 288 Bcf set in January 2014 and was more than double the five-year average draw for that week.”

While an increase in natural gas demand could be expected to occur in the short term due to cold weather, it is also expected to increase in the long term. One main reason is that natural gas has become the fuel of choice, especially as more and more coal plants have been or are scheduled to be retired. 


Don’t Get Complacent

Long-term natural gas and electric prices have remained stable over the past couple of years and it is easy to fall into the trap of thinking that prices will remain steady in the future. However, history has shown us that prices can change quickly, due to such factors as sustained cold weather or a supply disruption. In addition, the balance between increased production and the expected longer-term demand growth will be a key factor affecting future prices.

Taking advantage of current market conditions and locking in all or a portion of your company’s future energy requirements is a sound strategy that will limit the impact of higher prices down the road. 

About the authors:

Tim Comerford is SVP of Biggins Lacy Shapiro’s energy services group and principal of Sugarloaf Associates. Tim is focused on assisting companies, developers, municipalities and real estate advisors with issues that pertain to energy procurement, renewable installation, infrastructure assessments utility relocation, with a special focus on mission critical facilities.

Joe Santo is a principal and director of business development at Premier Energy Group, LLC, an energy consulting firm specializing in energy procurement for commercial and industrial customers. Joe has over 25 years of experience in the energy industry, with over two decades in the deregulated retail market.

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