As natural gas production growth in the U.S. has shifted from the Gulf Coast region to the Northeast’s Marcellus and Utica shale, some have suggested that time may have passed by Louisiana’s Henry Hub as the national benchmark for all U.S. gas prices, and have questioned whether it can maintain its position as the third largest physical commodity futures contract in the world. Should Henry be replaced by some pricing point in Appalachia? Is Henry really in trouble? In today’s blog, we continue our series looking at what makes Henry Hub tick with a closer look at the implications of changing physical and futures volumes at the hub.
Recap
This is Part 4 in the Henry Hub blog series. In Part 1, we told the story of how in the late 1980s, two Texaco execs took the struggling Sabine Pipeline asset and transformed it into the U.S. natural gas benchmark Henry Hub, first as a physical cash hub and later as the location for the CME/NYMEX Henry Hub futures contract. In doing so, they established several firsts for the North American natural gas market: the first multi-pipeline operational imbalance agreement, the first simplified flat fee structure, and the first online, automated title transfer accounting mechanism called “intra-hub title transfer service,” or IHT. The young, relatively small and nimble Sabine team – the sole operators of the hub (another plus) – essentially came up with innovative solutions that simplified trading activity relative to other market centers, then gave the hub a catchy, marketable name – Henry Hub. All of these things spurred market liquidity and gave the Hub an edge that helped land the futures contract. In Part 2, we dived deeper into what makes a successful futures contract, in particular the underlying deliverability and flexibility of the physical market location it represents. These characteristics build confidence among market participants that the futures contract – pricing, volumes, etc. – is founded on a fundamentally sound and liquid market. Henry Hub has proven to elicit that market confidence in its 25 years of operation. However, its liquidity does not come from traditional physical flows. In Part 3, we established that, in fact, most deals at Henry are IHT deals are book transfers that happen behind the scenes in the accounting system and are not physically delivered.
So, what really flows through Henry? In fact, very little. And, what’s more, a look at historical volume data shows that it has been that way since the earliest days of Henry’s existence as a high profile hub and NYMEX delivery point. As we’ll discuss below, that is good news, not bad news. Because physical flows utilize such a small piece of the capacity at Henry, there is minimal chance of any sort of delivery disruption due to a capacity constraint. That puts Henry in a great position as the best location for a U.S. natural gas benchmark price.
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Physical Flows at Henry Hub
Figure 1 below is a snapshot of average pipeline gas flows flows through Henry Hub for the most recent full calendar year, 2014, culled from our friends at Genscape. The center circle represents Henry Hub, and the boxes around it pipeline interconnects. Each interconnect box shows average 2014 receipts, deliveries, net flow (receipt minus delivery) and design capacity. All volumes in Figure 1 are in million cubic feet per day (MMcf/d) and are from the perspective of the Hub, meaning receipts are volumes received by the Hub (positive numbers) and deliveries are volumes sent out (negative numbers). The center box summarizes net inflows and outflows from each interconnect.
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