February 2017, Vol. 244, No. 2

Features

Northeast Natural Gas Pipelines: Is More Capacity Needed?

The ability of natural gas production from the Appalachian Basin, primarily the Marcellus and Utica shale plays in the Northeast, to reach growing demand centers in the Gulf Coast and Midwest is largely a function of expanding pipeline infrastructure.

The Appalachian region has witnessed significant growth in natural gas production and represents about 27% of total U.S. production, up from virtually zero at the beginning of the decade. Navigant’s North American Natural Gas Outlook, Fall 2016 shows continued growth in Appalachian production is expected to reach a remarkable 38 Bcfd, 34% of total U.S. production, by 2040.

Because this growth is predicated upon the continued expansion of natural gas infrastructure, we explore pipeline development in the Northeast in the context of announced delays to several major Appalachian pipeline projects due to a slowing regulatory process in the region and growing opposition to new pipeline construction, among other factors.

With about 22 Bcfd of capacity on more than 28 projects already in advanced stages of development and scheduled to come online during the next several years, Navigant evaluated the outlook for the Appalachian pipes and reviewed the key drivers for pipeline development in the Northeast.

One of the primary motivators for pipeline expansion to enable Appalachian production to reach markets in the Northeast and beyond is strong production growth that has been enabled by robust operational improvements and gains in production efficiency.

Producers continue to take measures to improve productivity to both reduce costs and boost production. For example, in the Utica play, producers have reduced drilling days from 29 days in 2014 to 16 days in 2016 for a typical well, a decrease of 45%.

The average lateral length has increased to 9,000 feet from 8,543 feet over the same period, representing a 5% change. In the Marcellus play, the reduction in drilling days from 29 days in 2014 to 15 days in 2016 represents a decrease of 48%, while the average lateral length has climbed from 8,052 feet to 9,000 feet, an increase of 12%. These performance improvements have resulted in decreased wellhead costs.

Over the same period, drilling and completion (D&C) costs per 1,000 feet of lateral have decreased from $1.55 million to $1.04 million in the Utica and $1.34 million to $0.90 million in the Marcellus. These reductions represent decreases of 33% for both shale plays and are part of the reason Utica and Marcellus production is expected to grow to 4.6 Bcf/d and 23.3 Bcf/d by 2020, representing an increase of 25% and 40% from current levels, respectively.

In addition, wellhead estimated usable recovery (EUR) per 1,000 feet of lateral increased from 1.4 Bcf in 2014 to 1.6 Bcf in the Utica and from 1.5 Bcf to 2 Bcf in the Marcellus, representing increases of 14% and 33%, respectively.

What is remarkable is that these operational improvements occurred despite weak prices (the average Henry Hub price decreased from $4.37 in 2014 to $2.62 in 2015 and has averaged $2.40 in 2016 YTD). The Utica and Marcellus remain important sources of future supply growth, and the projected increase in production is the key driver for more takeaway capacity from the basin.

This growth in production requires significant pipeline expansion to enable the gas to reach markets. A large number of new pipeline projects have been proposed. However, it is important to note that approval of pipeline construction often requires long lead times. In addition to approval from the Federal Energy Regulatory Commission (FERC), which issues a final environmental impact statement (EIS) pending receipt of permits from the Clean Water Act, Coastal Zone Management Act and Clean Air Act, state permits are also required in order to receive FERC approval. As a result, growth in pipeline expansion has not kept pace with production capability.

After years of insufficient pipeline capacity out of the basin, several large projects in the Marcellus and Utica are in the approval process. In the Utica shale play, four major projects are undergoing FERC review and would add nearly 7 Bcfd of export capacity by 2018 to the 10 Bcfd of existing capacity. These projects include:

• Energy Transfer Partners’ Rover pipeline, which received a final EIS from the FERC in July 2016, is designed to transport 3.25 Bcfd of natural gas from the Marcellus and Utica Shale areas to market hubs in Ohio and Michigan, where interconnections with other pipelines will enable deliveries to the Dawn Hub in Ontario.

• TransCanada Corp.’s Leach XPress and Rayne XPress projects, both of which received a draft environmental impact statement (DEIS) from FERC, seek to add 1.5 Bcfd and 0.6 Bcfd, respectively, of natural gas takeaway capacity along the Columbia Pipeline Group’s network to facilitate deliveries to Gulf Coast markets.

• Spectra Energy Corp.’s Nexus Gas Transmission project, which received a final EIS from the FERC in November, is designed to deliver 1.5 Bcfd of natural gas supplies from the Utica region to markets in northern Ohio, southeastern Michigan, the Chicago Hub in Illinois and the Dawn Hub.

Several Northeast pipeline projects faced significant setbacks caused by insufficient market interest or delays in permitting. In some cases, this has caused developers to cancel projects.

The Constitution pipeline project, intended to move gas from Appalachia into northeastern New York, has been put on hold indefinitely after failing to receive water permits from the state. The Northeast Energy Direct (NED) project, designed to move gas from Wright, NY to Dracut, MA, has been canceled due to insufficient contractual commitments.

Williams Partners recently announced a delay from late 2017 to 2018 of its 1.7 Bcfd Atlantic Sunrise project after FERC delayed the approval process (See Projects). The project is designed to expand Transco’s Leidy Line deliveries of Marcellus gas to the Mid-Atlantic and Southeast markets on its Transco pipeline. Other pipeline projects that are facing environmental opposition or lack of strong interest by shippers include:

• Atlantic Coast Pipeline, a joint venture of Duke Energy, Dominion, Piedmont Natural Gas, and AGL Resources designed to serve South Atlantic markets with 1.5 Bcfd of capacity, is fully subscribed by utilities but is facing local environmental opposition.

• Mountain Valley Pipeline, which is also designed to serve the South Atlantic with 2 Bcfd of capacity, received its DEIS in September. Although it is fully subscribed, key shippers include several producers that may not need the capacity in the near term.

• Nexus Gas Transmission, which uses an existing right-of-way for much of its route, connects Spectra Energy’s Texas Eastern and Union Gas systems in Ontario, but is not fully subscribed for its 1.5 Bcfd of capacity.

• Access Northeast, a joint project of Eversource Energy, National Grid and Spectra Energy, has a capacity of 925 MMcf/d designed to serve growing gas and electric markets in New England, but is not expected to enter service until 2019 or later due to legal opposition to entering into transportation agreements with utility shippers.

• PennEast, a 1.1 Bcf/d pipeline designed to transport Marcellus production to markets in New Jersey and Pennsylvania, received a favorable DEIS in July. However, in November, FERC announced a delay on the final EIS citing route modifications filed by PennEast as “a contributing factor in its decision to prolong the environmental review schedule.” PennEast is a joint venture backed by a consortium of utilities, gas marketers, and midstream companies, including NJR Pipeline Co., Public Service Enterprise Group, SJI Midstream, Southern Company Gas, Spectra Energy Partners LP, and UGI Energy Services.

Navigant’s North American Natural Gas Outlook, Fall 2016 projects the Appalachian region to become a leading provider of natural gas to markets in the Southeast, South and Midwest regions in the next five years. Beyond that timeframe, deliveries of Appalachian production to the Gulf Coast are expected to reach 2.4 Bcf/d by 2025.