As 2015 is ushered in, about 40 U.S. pipeline projects are in various stages of development for receiving natural gas from the Marcellus and Utica shales, including six that came on line in 2014. All together, the projects represent more than 33 billion cubic feet (Bcf) per day of capacity and about $20 billion of investment, if all are ultimately built.
The projects that came on line in 2014 – including two that are not Marcellus related – added 3.5 Bcf per day of natural gas transportation capacity. They include the Texas Eastern Appalachia to Market (TEAM) 2014; TEAM South; the Tennessee Gas-Utica Backhaul; and the ANR Lebanon Reversal.
In 2015, another 4 Bcf per day of gas pipeline capacity is scheduled to be completed, according to information compiled by Black & Veatch. Some of these projects involve installing new pipe over relatively short distances, such as Transco’s Leidy Southeast, which in 2015 is slated to add 30 miles by looping existing pipeline. This will eliminate bottlenecks for Marcellus shale gas moving from Pennsylvania to reversed-flow pipes heading south to Mid-Atlantic states.
Other natural gas pipeline projects are more extensive, such as Kinder Morgan’s Tennessee Gas Pipeline Co. Northeast Energy Direct project. This project would involve more than 400 miles of new pipelines – including 135 miles of greenfield pipes taking gas from the producing areas of Pennsylvania and 177 miles of new and co-located pipe bringing the gas north to the Dracut hub near Boston. The in-service date is proposed for 2018.
“Projects that do not require laying down long stretches of greenfield pipeline will likely move first,” said Denny Yeung, Principal with the Natural Gas and Power Fuels Group of Black & Veatch’s management consulting business. “Most are intended to bring low-cost Marcellus shale gas to the growth markets in the Midwest, Northeast, Southeast, and for export as liquefied natural gas (LNG).” Seven LNG export terminals projects – located on the East, West and Gulf coasts – have been granted licenses from the Department of Energy.
The increased capital expenditure within the industry is detailed in Black & Veatch’s Strategic Directions: U.S. Natural Gas Industry report.
“A lot of the reverse flow projects heading to the Gulf are the lowest cost,” Yeung continued. “The next tranche – likely years down the road – will get expensive, since it will require new long-haul greenfield capacity which will require new rights-of-way. The lowest-cost expansions – the low hanging fruit – are largely already in place.”
Expansion in New England
The New England region is again facing severe constraints on pipeline delivery capacity and the ensuing gas price volatility, and Black & Veatch believes that New England will need another 1.2 Bcf to 1.5 Bcf per day of pipeline capacity by 2020. During last winter’s “polar vortex,” the tight regional gas market drove spot wholesale prices to record highs, spiking wholesale electricity costs. Compounding the problem, the region’s electric power sector is increasingly dependent on natural gas as a generation fuel as older coal, oil, and nuclear plants are retired and replaced with gas-fired capacity.
But any relief for New England is two seasons away – the winter of 2016-2017 – when Spectra Energy’s Algonquin Incremental Market (AIM) expansion project is scheduled to come on line. This project will add 342 million cubic feet per day through new segments largely along the existing right of way from the New York-New Jersey border, diagonally across Connecticut and into the Dracut hub. It is important to note, however, this incremental capacity will not completely alleviate the pipeline capacity constraints in the region, and additional capacity is still necessary, Yeung said.
An article recently appearing in the New York Times chronicled the electric rate shock hitting New Englanders as last winter’s wholesale costs are finally passed through in retail bills. The article also notes that there is vigorous opposition to the planned pipeline expansions from environmental groups.
“There was a lag in transparency, and what happened last winter didn’t show up in bills until November 2014,” Yeung said. Now, companies are saying bills could go up another 40 percent. “People are starting to re-think this.”
FERC Green Lights Two Projects
Meanwhile, the Federal Energy Regulatory Commission (FERC) in December 2014 granted a Certificate of Public Convenience and Necessity – essentially a green light to proceed – for the Constitution Pipeline, a 124-mile pipeline proposed by Williams Partners, and three other companies.
Constitution will move Marcellus shale gas production from northeastern Pennsylvania to the Wright Hub in upstate New York, crossing various other lines along the way, by late 2015 or early 2016. Wright also connects with the Algonquin and Iroquois lines into New England and Long Island, although that location will still be a bottleneck for northeastern-bound shipments because the take-away capacity is limited, which the Kinder Morgan Northeast Energy Direct project would help alleviate.
Spectra and Northeast Utilities in September also announced their planned Access Northeast project which could be another potential solution to the New England market. Access Northeast is envisioned as a complement to AIM and is targeted to be in-service by late 2018, bringing supplies directly to local distribution companies as well as numerous gas-fired power plants along its right-of-way.
More recently, on Dec. 18, FERC issued a Certificate of Public Convenience and Necessity to Spectra Energy’s Uniontown-to-Gas City Expansion Project. This line will provide bidirectional, firm transportation service by late 2015 from the Marcellus shale gas supply area near Uniontown, Pa., to the interconnection with the Panhandle Eastern Pipe Line system near Gas City, Indiana, for delivery to Midwestern markets. The capacity is slated to be up to 425 million cubic feet (MMcf) per day.
Mid-Atlantic States See Growth
In the Mid-Atlantic market, the gas utility load in the Carolinas has not changed that much, and power generators have some firm capacity contracts, said Peter Abt, Managing Director of Black & Veatch’s Natural Gas & Power Fuels Group.
“The motivation here is that they believe their electric loads are growing, and they’d like some of the lower cost Marcellus gas and its supply diversification.” Their positioning on the Transco system gives buyers the options of both Gulf Coast and Marcellus supplies, Abt said.
Elsewhere, Kinder Morgan’s Natural Gas Pipeline Co. of America unit recently completed an open season to solicit interest in the expansion of its Gulf Coast mainline system from an interconnection with the Rockies Express Pipeline in Illinois to points north. This project would increase NGPL’s capacity by up to 450 million cubic feet per day to the Chicago area by late 2016.
Kinder Morgan also said that its El Paso Natural Gas unit’s Sierrita Pipeline went into service in 2014, taking gas 60 miles from El Paso’s existing mainlines near Tucson, Ariz., to the U.S.-Mexico border, where the system interconnects with a gas pipeline in Mexico.
Toward the Canadian border on the West Coast, Northwest Pipeline, a Williams unit, has two projects under consideration, tied to two LNG export terminals proposed for the region. The Pacific Connector would carry up to 1 Bcf per day 230 miles from interconnects near Malin, Ore., to the Jordan Cove LNG terminal proposed for Coos Bay, Ore. The Washington Expansion project would bring 750 million cubic feet per day to the proposed Oregon LNG project.
The boost in pipeline capital projects is giving gas buyers and sellers new flexibility for sourcing gas or finding wider markets, Abt said. Over the long run, this will enhance market efficiency and likely dampen price volatility.
By Samuel Glasser
Published originally on Black & Veatch Solutions
