Northeast natural gas prices have been flipped upside down over the last couple of years and have shown unprecedented weakness relative to Henry Hub due to capacity constraints preventing booming production reaching new demand markets. New infrastructure projects should relieve this congestion in the next two years but as we explain today, the current market view – expressed in the forward curve - does not appear to reflect that reality.
This is Part 5 in our natural gas forward curve blog series. In Part 1 we defined the forward curves, reviewed their mechanics and examined the fundamental factors underlying the U.S. natural gas forwards markets: supply, demand, storage, transportation/infrastructure and weather. In Part 2 and Part 3 we looked at how the forward curves in two Northeast gas markets – Transco Zone 6 in New York and Dominion South in Appalachia -- have been completely reshaped by the shale revolution and resulting production growth in the Northeast. Northeast gas prices have gone from being the highest in the country to some of the lowest as the region has transformed in the last few years from being a demand-heavy market to a major producing region on the verge of becoming a net gas supplier to the U.S. In Part 4, we previewed the fundamental drivers influencing the Northeast forward curves for the next several years as new infrastructure comes online to connect production to markets outside the region.
Today, we look more closely at the timing of these fundamental changes and how they correlate to current Northeast forward curves. Our analysis of a recent Dominion South Point (Dom S) forward curve suggests a possible disconnect between the current market view and the expected timing of infrastructure changes.
We start with some definitions required for our analysis, beginning with the concept of “variable transportation cost” as it relates to basis. Basis, as you’ll remember from Part 1 is the differential or price spread between a regional hub and Henry Hub, LA. Variable transport cost is the fee customers pay to pipeline companies for the volume of gas they actually flow on a pipe. The variable cost, as defined by a pipeline’s tariff (rate schedule), is usually in addition to a fixed/flat “demand” charge paid by those who reserve long-term capacity on the pipeline (firm capacity commitments). The demand charge is effectively a sunk cost, a sort of flat rental fee to reserve the capacity. But the variable cost factors into daily decisions about how much gas to flow in a given direction. [Typically the variable transport cost is the sum of the pipeline’s commodity rate (paid on each therm of gas moved) and the pipeline’s fuel charge – the cost to run the pipeline’s compressors charged to shippers based on the price of natural gas.] The price spread between the receipt and delivery point must at least cover the variable cost in order to make it economical to flow gas in that direction. Since prices and price spreads change daily, so does this calculation.
In a balanced market, basis should theoretically reflect the variable transport cost for gas flowing between two points.. But when fundamentals are out of whack at the receipt or delivery points, basis can swing wildly to well below or well above the variable transport cost. The imbalance can materialize for various reasons, including fundamental constraints in three key areas: transportation, supply or demand. Thus, basis is not only determined by a hub’s immediate supply/demand balance, but also the balance at other hubs to which it is connected. If a fundamental imbalance skews basis wide enough and for long enough, it can incentivize investment dollars for projects to relieve constraints and essentially “capture the spread,” such as by building additional pipeline capacity. This new capacity, if it relieves the constraints can be expected to lead basis to “correct” to be more in line with variable cost.
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