In the dead of the natural gas winter season when US producers count on strong margins from higher gas prices, the Transco Z6 New York hub is trading on average nearly flat with U.S. benchmark Henry Hub, LA – the delivery point for the CME NYMEX natural gas futures contract. This is a dramatic departure from historical winter norms in the Northeast market, where prices relative to Henry and just about every other gas hub in the Northeast have traditionally carried hefty premiums in the winter. Moreover, the forward curves indicate these basis levels are the new norm for Northeast pricing. The forward curve for Transco Z6 New York shows basis for 2015 barely above Henry Hub for the year, with several months at more than $1.00/MMBtu discount. Today we look at what’s behind major changes in northeast forward curves.
This is Part 2 in our natural gas forward curve series. In Part 1 we explained natural gas forward markets and defined a forward curve. We clarified that forward curves are not the same as price forecasts because forwards reflect today’s value for future delivery of the gas, and that this value reflects the market’s expectations of supply and demand fundamentals for that future period. We explained that forwards in the gas market transact in terms of differentials to NYMEX Henry Hub, known as “basis,” and that adding the basis to the corresponding NYMEX contract derives the outright value of a forward market. Part 1 also reviewed the concept of seasonality in gas market forward curves. Patterns and trends in forward pricing are driven primarily by longer-term expectations for supply and demand dynamics at a particular hub for that future period. Forward curves within each major region of the US and even individual price hubs have unique characteristics and behave differently, depending on how much supply they receive, how much demand is served, what infrastructure and transportation is available and at what cost.
The Northeast region historically has been a supply-short, demand intensive and capacity constrained market, notorious for panic premiums, particularly in the coldest months. It had minimal local production of gas, but huge winter heating demand because of its concentration of heavily populated urban areas. Data from our friends at Bentek show that between 2005 and 2010, Northeast gas demand in the summer made up about 20% of the US national total, while in the winter that proportion increased to about 25%. But back then the region only produced 4% of the US national total and could meet only 13-20% of its gas demand from that production. As a result, the Northeast relied heavily on gas supply from other US regions and Canada, and from overseas via LNG terminals. During the winter, demand outpaced incoming supply capacity from outside the region leading to extensive withdrawals from underground storage in the region to meet peak requirements. Thus, the Northeast traditionally was a premium market, a gas “taker,” quite often with the highest natural gas prices in the US. In the winter demand for gas was primarily driven by heating and in the summer it was driven by the need to fill depleted storage capacity in time for winter. This perpetual short-fall in supply kept a floor under prices even during low-demand summer months. At times during winter months, regional demand also would exceed the capacity available to transport sufficient gas to the demand centers, leading to intense volatility and price spikes as Northeast buyers competed to secure the last possible molecule of gas. Gas suppliers across North America scrambled to get their gas to the Northeast in order to capture these premiums. Investment dollars targeted pipeline projects that would bring gas to the Northeast in order to capture these spreads.
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