Natural gas production in the United States showed consistent growth from 2006 through 2015, which spurred the development of interstate natural gas pipelines, and, more recently, increased efforts to export natural gas, as well as liquefied natural gas (LNG) by way of pipeline. Exploration and production (E&P) companies played a pivotal role in support of these “supply push” natural gas pipeline projects by providing increased gas supply and entering into precedent agreements as anchor shippers. Nearly two years ago, during the nadir of the commodity downturn, counterparty risks, primarily for gathering and processing contracts, surfaced, eventually leading to E&P bankruptcies. Is it conceivable that the E&P firm transportation agreements that spurred this development will be renewed at reduced rates? Or, worse yet, what contracts will not be renewed?
In order to receive a Certificate of Public Convenience and Necessity, a project developer not only needs to undergo an extensive environmental review, but must also demonstrate need. In determining whether to grant a certificate, the FERC must balance these two competing requirements. A need is primarily demonstrated by contracting the available project capacity with firm transportation commitments. Historically, a lack of commitments (not non-binding memoranda) for contracted capacity has proven fatal. For example, the FERC rejected a certificate for Veresen’s Jordan Cove Energy Project and Williams’ related Pacific Connector Pipeline on these grounds. Similarly, Kinder Morgan’s Northeast Energy Direct Project failed to launch, due to, in the words of Kinder, “inadequate capacity commitments from prospective customers.”
Concerns have also been raised about the duration of the agreements, especially with the growing number of E&P anchor shippers. Because of the variability in market conditions, E&P companies, unlike their demand pull counterparts, typically pursue shorter terms. While an E&P shipper may only be interested in a 10-year contract term, a power generator, with a reliable base rate and predictable revenue stream, may be more interested in a 20-year contract term. For those E&P contracts entered into in 2006-2008, the expiration dates for these precedent agreements are quickly approaching. Will the market prices and production quantities be there to support renewal on these supply push pipelines?
Of course, E&P shippers would not necessarily seek to terminate contracts early, but if conditions do not prove favorable, the shippers may fail to renew, thus leaving supply push pipelines with little recourse. The Energy Information Administration projects growth in both natural gas production and, to a lesser extent, prices in 2018. But much of this growth is driven by exports. With the Trump administration’s policies regarding NAFTA yet to be sorted out — and most pundits predicting no resolution before 2019 — these projections could prove unrealistic.
A particular issue that bears watching is that pipeline operators involved with the early supply push projects in 2007 through 2010 designed pipelines to transport gas from newly developing basins located in traditional supply areas to the traditional demand areas in the Midwest, Southeast and Northeast. For example:
- Tallgrass Energy designed the Rockies Express to “link supplies of natural gas in the Rocky Mountain supply basin to major markets in Illinois, Indiana, Ohio, and the eastern United States.”
- Kinder’s Fayetteville Express Pipeline “has a capacity of approximately 2.0 billion cubic feet per day and brings much needed natural gas from the Fayetteville Shale in Arkansas to pipelines serving the Midwest and Northeast.”
- Energy Transfer designed its ETC Tiger Pipeline to connect production in the Texas shale plays with other pipelines “for ultimate delivery to markets across the Northeast, Southeast, Mid-Atlantic and Midwest.”
But soon after these pipelines went into operation in 2009 and 2010, the commodity world changed. The explosive growth of the Marcellus/Utica plays has displaced gas from these traditional production areas. The original 1.1 Bcf/day of contracts on the Rockies Express project expire in 2019; and 1.325 Bcf/day of original contracts on the Fayetteville Express project expire in 2020, as do 1.5 Bcf/day of contracts on the ETC Tiger Pipeline. Both individually and together, that’s a lot of capacity. The negotiated rates vary on each pipeline, with the rates for the Fayetteville Express hovering around 0.25/dth/day, ETC Tiger Pipeline around 0.33/dth/day and Rockies Express being over 1.00/dth/day. The capacity held by individual shippers varies widely, as well. For example, Southwestern Energy has a single 1.2 Bcf/day contract on Fayetteville expiring, Shell Energy holds 0.5 Bcf/day in capacity and ConocoPhilllips holds 0.4 Bcf/day, but EOG Resources holds less than 0.1 Bcf/day.
So will the E&P companies that hold these early phase contracts renew or not? The answer may turn on whether the production company has an alternative outlet for its production that creates a better netback (i.e., price of commodity minus transportation cost) to the shipper. By using LawIQ’s shipper search function, a user can quickly find the entire capacity supply portfolio for each of these companies, which will help inform your view as to whether these contracts will be renewed. If so, these renewals will likely be at a lower rate, competitive with similar regional contracts, which you can also access via our platform. Similarly, our dynamic projections about when new projects from these supply basins may come into service will also provide insight as to the viability of these expiring contracts.
E&P Anchor Shippers