We’ve spent a lot of time here in the RBN blogosphere discussing the trials and tribulations of natural gas producers in the Marcellus and Utica shales who are “trapped behind the pipe,” unable to get sufficient takeaway capacity to move supply to market (both within and outside the U.S. Northeast region) where they could get a higher price for their gas. Pipeline companies have ponied up billions of dollars to build lots of pipe to alleviate these constraints and much more investment is planned. Of course, those pipelines and their committed shippers hope that the investment will pay off long-term – that the economics for building the pipe will justify the cost. The pipeline will have scores of engineers, lawyers and accountants to figure that out. But what if you just want to make a quick-and-dirty estimate of the economics? Well, there is a way. In today’s blog, we walk through the factors you need to consider when your boss runs in and asks, “Hey—what would it cost to move gas there in a new pipe?”
New pipeline development is driven by both necessity and opportunity, and as we showed in Part 1 of this series, nowhere has that been truer in recent years than in the U.S. Northeast natural gas market, where a combination of rapid gas production growth in the Marcellus/Utica shale and a shortage of outbound transportation capacity from those areas has created pockets of extreme prices: exceptionally low prices near the supply growth and brief but extreme price spikes during peak demand periods in the populated demand centers, particularly New York and parts of New England. That reality has not been lost on midstream developers, who are competing to bridge the gaps. RBN’s Midstream Infrastructure Database Interface (MIDI) is currently tracking 24 natural gas pipeline projects specifically designed to add another 18 Bcf/d in takeaway capacity out of the Northeast producing areas and reach growing demand markets both within and outside the Northeast region, all by 2019. But as we also noted in Part 1, even in a market like the Northeast, there is a certain level of market uncertainty and financial risk involved, both for the developer and the shippers who make long-term commitments to the capacity beforehand, not to mention the cut-throat competition when there are that many pipes competing for what is now flattening supply growth. Lately, the news out of the pipeline sector suggests that some projects are buckling under the pressure. In recent weeks, several natural gas projects have announced cancellations and delays, due to both regulatory issues and market risk. Of course, these decisions aren’t taken lightly and can’t be boiled down to simple math. But as we alluded to last time, we do have a model – more like a rule of thumb – we like to use as a first-glance litmus test for the rough economics of a new, greenfield (stand-alone) pipeline project. So today we’ll walk through an example of how it works. Our example is from the perspective of a Marcellus producer targeting the New England consumption market, where they occasionally see price spikes during peak winter heating season because of pipeline constraints that limit the availability of gas supply.
Here’s your predicament: You work for a producer in the Marcellus Shale and your boss notices that over the course of a year of the past few years there is always a price difference between your supply price at Tennessee Gas Pipeline’s Zone 4 (TGP-Z4) pricing hub and the consumption market located about 500 miles away in Boston. It is over a dollar per MMbtu most of the time, and for a few weeks in the winter the differential blows out, running up over $30/MMbtu, and blasting to more than $70/MMbtu back during the Polar Vortex winter of 2013-14. Wouldn’t it be nice to have capacity on a 500-mile pipeline that would take gas from the Marcellus to Boston (see map in Figure 1 – Any resemblance between this hypothetical pipeline and any recently cancelled pipeline project is purely coincidental).
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