Decreased demand for oil and natural gas due to the coronavirus pandemic has weighed upon the midstream industry. The midstream segment also faces a number of legal challenges, but development work continues.
In a large blow to the industry over the summer, Dominion Energy Inc. noted in July the cancellation of its 1.5-bcfd Atlantic Coast Pipeline (ACP) project, citing “too much legal uncertainty.” The pipeline was to carry Marcellus shale natural gas production from West Virginia across Virginia to North Carolina.
The US Supreme Court on June 15 ruled 7-2 that the US Forest Service properly exercised its authority under the Mineral Leasing Act of 1920 to grant a permit for ACP to pass through a national forest beneath the Appalachian Trail. The decision overturned one of several judgments by the US Court of Appeals for the Fourth Circuit, but left the case pending before that appellate court (OGJ Online, June 16, 2020).
ACP was approved by the US Federal Energy Regulatory Commission in October 2017. Owners in addition to Dominion are Southern Co. and Duke Energy Corp., including Duke subsidiary Piedmont Natural Gas.
Other projects face uncertainty. In a July note outlining possible future increased Permian gas flaring due to COVID-19 delays to pipeline construction, Rystad questioned the feasibility of certain projects. “The Pecos Trail evaluation is on hold and the Permian to Katy (P2K) pipeline also appears inactive,” the firm said.
In mid-August, Tellurian Inc. deferred construction on three of the four pipelines proposed to supply its 27.6-million tonne/year (tpy) Driftwood LNG plant with natural gas as part of decision making regarding a Phase 1 final investment decision (FID). By doing so the company hopes to trim 30% off the project’s initial costs. Tellurian earlier this year delayed FID until 2021.
Pipelines deferred include the 2-bcfd Permian Global Access pipeline (625 miles, 42-in. OD, Waha, Tex., to Lake Charles, La.) and 2-bcfd Haynesville Global Access pipeline (160 miles, 42-in. OD, Haynesville-Bossier shales to Lake Charles), according to the company’s Aug. 12, 2020, investor presentation.
Moving forward
Elsewhere, projects push forward. Tellurian said it would proceed with the 4-bcfd Driftwood pipeline (74 miles, 48-in. OD, 11 miles, 42-in. OD, 11 miles, 36-in. OD), connecting the plant with gas from various transmission systems. It did not mention the status of its 2-bcfd Delhi Connector (180 miles, 42-in. OD).
Meanwhile, in October, Energy Transfer LP received approval from the Illinois Commerce Commission (ICC) to expand its 570,000-b/d Dakota Access crude oil pipeline to 1.1-million b/d. The ICC said the project would promote both security and convenience for the general public.
Energy Transfer expects to have the expansion complete by third-quarter 2021. The company began work on a new pumping station in Emmons County, ND, in October.
Both the approval and ETP’s planned schedule come despite on ongoing suit in US District Court for the District of Columbia attempting to force Dakota Access to cease operations while its environmental permitting is reviewed (OGJ Online, Aug. 27, 2020).
Dakota Access runs more than 1,000 miles from Bakken shale in North Dakota to a pipeline and refining hub at Patoka, Ill. Connections there take oil as far as the US Gulf Coast.
In another development, the company added more than 400,000 b/d of NGL capacity out of the Permian and Delaware basins with the completion of its Lone Star Express Pipeline expansion project.
The new 352-mile, 24-in. pipeline originates in Winkler County, Tex., and connects into the existing Lone Star Express 30-in. pipeline at the Morgan Junction in Bosque County, Tex., south of Fort Worth.
The pipeline system ultimately connects into Energy Transfer’s Mont Belvieu integrated liquids storage and fractionation. Energy Transfer’s seventh fractionator at Mont Belvieu was brought online earlier this year, bringing the partnership’s total fractionation capacity to more than 900,000 b/d.
Elsewhere, confidence grows that the Permian Highway Pipeline, which originally reported an in-service date of first-quarter 2021, and the Whistler project, which reported an in-service date of third-quarter 2021, are both moving ahead.
On Oct. 21, Kinder Morgan Inc. (KMI) told investors that its 2.1-bcfd Permian Highway pipeline was still tracking to plan. The operator acknowledged a reduction in earnings from product pipelines due to adverse market conditions and the resulting weight on various planned expansion projects, but reaffirmed development plans for Permian Highway, which will use 430 miles of 42-in. OD pipe to transport gas from the Waha area in Texas to the US Gulf Coast and Mexico.
“Our project management team made excellent progress this quarter on the Permian Highway Pipeline project, [which is] more than 97% mechanically complete. As previously announced, we expect the project to be in service early in 2021,” said KMI President Kim Dang.
As for the Whistler project, Whistler Pipeline LLC in June received $325 million from Global Infrastructure Partners (GIP) to fund construction of the 500-mile, 2-bcfd natural gas pipeline. Expected to enter service in third-quarter 2021, the line will connect the Permian basin to Agua Dulce hub near Corpus Christi, Tex. The funding “confirms that project-related work on the pipeline is occurring,” said Artem Abramov, Rystad Energy’s head of shale research, in a July note.
Whistler is owned by MPLX LP, WhiteWater Midstream, and a joint venture of Stonepeak Infrastructure Partners and West Texas Gas Inc.
For information on additional construction projects please see Oil & Gas Journal’s Worldwide Construction tables, published through OGJ.com in May and November of each year. These tables detail both ongoing and planned midstream and downstream construction, including refineries and LNG plants as well as pipelines, petrochemical plants, and gas processing plants.