Investors with long positions in natural gas can take comfort in growing industrial sector demand, according to an industry veteran who spoke Monday in Chicago.
IRI Columbia University Chairman Jim Duncan, who spoke Monday at the LDC Gas Forums Midcontinent conference, said the Great Lakes region is No. 1 for newly commissioned chemical plants with 775. He cited data from Industrial Information Resources, the U.S. Department of Commerce and corporate filings. The second top region is the Gulf Coast area, including Texas, with 655 newly commissioned plants.
Duncan, who spoke with NGI on the sidelines of the conference, said the link between gas demand and fertilizer plants is strong.
“You lose 50% of U.S. fertilizer production if natural gas goes above $5/MMBtu.”
Fertilizer production, as well as industrial demand including co-generation, are the “unsung heroes” of natural gas demand in the Lower 48 states. Co-generation allows an industrial plant to convert excess heat from feed gas combustion into useable or sellable electricity.
Fertilizer production is prominent in gas demand in the upper Midcontinent while methanol production figures heavily into the demand picture for the South and Gulf Coast areas, Duncan said.
The availability of inexpensive natural gas, thanks to booming production and infrastructure that is bringing previously stranded supply to market, incentivizes plant expansions and development, he said. Consequently, industrial gas use could provide a growing outlet for increases in piped gas flows from new and expanded pipelines in the region.
Separately, U.S. industrial demand for gas has increased by 2.2 Bcf/d year/year as of May, having grown steadily on an annual basis since 2015, according to BTU Analytics LLC CEO Andrew Bradford. He wrote about the demand in a blog post in August, affirming the fertilizer-methanol connection.
The analysis, limited to interstate pipeline data, showed a positive growth trend from 2014-2016 to 6.6 Bcf/d in 2019 year-to-date from an average of 5.3 Bcf/d. Regions commanding most of the industrial demand growth included the Midcontinent, Louisiana, Texas and the Southeast.
“Existing industrial sites, favorable regulatory frameworks, and proximity to low cost shale gas provided tailwinds for investments in these regions,” said Bradford.
The upper Midcontinent and Great Lakes region are particularly strong in boosting the regional industrial demand profile and pipelines are benefiting.
Energy Transfer LP’s 3.25 Bcf/d Rover Pipeline saw its utilization jump by 1.2 MMBtu/d year/year in the second quarter as the midstream company brought the pipeline fully into service, according to the 2Q2019 earnings results. Enbridge Energy Inc.’s 1.5 Bcf/d Nexus Pipeline started service in 4Q2018, so 2Q2019 flows were higher year/year, ranging from 1.1-1.2 Bcf/d during peak winter demand season, Energy Aspects analyst David Seduski told NGI.
Rover and Nexus were conceived as pipelines that would connect booming supply from Appalachia’s production zones to the dense end-markets of the upper Midcontinent and the Northeast through interconnections in Michigan.
Amid an influx of supply to the upper Midcontinent and massive injections of gas into storage, the ability of the end markets in the United States to absorb the supply is becoming less certain.
In the case of Rover, about one-third of the total flows are consistently interconnecting with Vector Pipeline, which ferries gas to the Dawn hub in Ontario.
“That’s about 1 Bcf/d out of 3 Bcf/d on an average day. It’s been remarkably stable,” said Seduski. The remaining two thirds are largely divided between TC Energy Corp.’s 6 Bcf/d ANR Pipeline and Energy Transfer’s 2.8 Bcf/d Panhandle Eastern Pipeline.
“It’s around 1.2-1.4 Bcf/d delivered to the ANR Pipeline system, and 0.6-0.8 Bcf/d to Panhandle Eastern,” he said. “When contracted volumes on Rover aren’t enough to cover the demand Dawn services, Nexus can ramp up and send an extra 0.1-0.2 Bcf/d to Canada, given its 1.5 Bcf/d in capacity is not fully subscribed.
“It’s tough to get a good comparison for what is normal for Nexus given last winter it was just entering service, but around 0.5 Bcf/d of the 1 Bcf/d that Nexus saw in receipts crossed the border at the St. Clair point last winter.”
Around one-third of the Nexus gas, or 0.4 Bcf/d, stays on the U.S. side of the border, he said. The amount of Nexus gas that goes to Canada versus the amount that services U.S. customers has been at the center of recent litigation against the pipeline.
Power prices in the region seem to indicate U.S. markets that have been targeted by midstream projects like Rover and Nexus are flush with supply, Energy Aspects’ Peter Rosenthal, head of North American power, told NGI.
“We’ve lowered our view on Chicago basis, even for winter,” he said.
Incremental demand growth in the United States is needed to absorb gas that is newly flowing on Rover and Nexus.
While exports are complicated by a difficult regulatory framework in Mexico and a trade war with China, U.S. industrial demand is quietly becoming a more important piece of gas monetization.
Western Canadian Sedimentary Basin gas competing with Appalachia and Bakken Shale gas in the United States has put downward pressure on Canadian spot prices. A relief valve on the southern side of the border, like growing industrial demand, has the potential to allow Canadian gas prices to lift.
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