LNG

The American Gas Association said the state of Nebraska’s state legislature became the 26th state to pass fuel choice legislation in a unanimous and bipartisan vote, securing the protection of energy choice for consumers in a majority of states across the country.

The AGA explained that consumer energy choice preserves access to safe, clean and affordable energy resources including natural gas that offer a sustainable pathway to the shared goal of reducing emissions while maintaining affordability, reliability and quality of life for Americans.

“Thanks to the bipartisan action of now 26 state governments, more than 157 million Americans and 58 million households have a protected choice when it comes to how to fuel their homes and businesses,” said AGA President and CEO Karen Harbert.

Natural gas usage

“The average home using natural gas for space heating, water heating, cooking and clothes drying has about 18 percent lower carbon dioxide emissions than those attributable to an all-electric home, and the average family using natural gas for those purposes saves an average of $1,132 per year,” explained Harbert.

“Over the past 10 years, American families have saved a total of $125 billion thanks to natural gas,” she stated.

“Those are numbers we can be proud of. They also highlight how harmful natural gas bans would be for American families,” Harbert stated.

The AGA represents more than 200 local energy companies that deliver natural gas throughout the US.

There are more than 77 million residential, commercial and industrial natural gas customers in the US, of which 95 percent, or around 73M customers, receive their gas from AGA members.

Fuel choice legislation preserves access to natural gas in homes and businesses in states that have enacted them across America.

Nebraska became the 26th state to pass such a law, joining Idaho, Montana, North Dakota, South Dakota, Wyoming, Utah, Arizona, Kansas, Oklahoma, Texas, Iowa, Missouri, Arkansas, Louisiana, Indiana, Ohio, West Virginia, New Hampshire, Kentucky, Tennessee, North Carolina, Mississippi, Alabama, Georgia and Florida.

Bipartisan moves

“Every state to pass fuel choice legislation has done so in a bipartisan manner,” said the AGA.

“Since 1990, emissions from the natural gas distribution system have declined by 70 percent, even as demand for and usage of natural gas has increased with natural gas served to 23.4 million more consumers and the number of miles of distribution pipeline increasing by 59 percent,” the AGA noted.

US Natural gas is currently 3.3 times more affordable than electricity and expected to remain substantially more cost-efficient through at least to 2050.

“The affordability of natural gas is a critical reason why more than 500,000 families signed up for natural gas space heating, rather than electric heat pumps, over the past five years,” the AGA said.

Williams Companies, a leading US natural gas pipelines operator with projects aimed at boosting feed-gas supplies for Gulf Coast LNG export plants, has reached an agreement to acquire a portfolio of natural gas storage assets from an affiliate of Hartree Partners LP for $1.95 billion.

The United States energy outlook for December has forecast lower benchmark Henry Hub natural gas spot prices for the rest of the winter heating season to March 2024 because of higher production and storage levels.

Kinder Morgan Inc. (KMI), the leading US pipeline feed-gas company for liquefied natural gas plants and a key energy infrastructure developer, reported lower second-quarter net profits amid steady cash flow as it responded to volatile market conditions.

The company said profits declined to $586 million during the three months to the end of June from $635M in the second quarter of 2022.

“The KMI board and management team are fully committed to the use of our strong cash flow to benefit our shareholders,” said Executive Chairman Richard D. Kinder.

“We focus on maintaining a strong balance sheet while internally funding capital projects that produce returns well in excess of our cost of capital - including projects that are part of the ongoing energy evolution,” the Chairman stated,

KMI’s distributable cash flow amounted to $1.07 billion compared with $1.17Bln in the prior-year quarter.

Asset values

“KMI once again saw the value of its existing natural gas transportation and storage assets that are able to respond to volatile market conditions caused by extreme weather events and an increasingly intermittent resource-based electric grid,” said Chief Executive Steve Kean.

“Our 700 billion cubic feet of operated natural gas storage capacity is particularly useful in back-stopping intermittent renewable electricity resources,” Kean explained.

“Financial contributions from the Natural Gas Pipeline business segment were up relative to the second quarter of 2022 and ahead of budget,” added the CEO.

“Our Terminals business segment also over-performed relative to both the second quarter of 2022 and budget,” stated Kean.

KMI President Kim Dang said that the performance of the Natural Gas Pipelines business improved in the second quarter of 2023 versus the prior-year quarter.

Dang cited higher contributions from Midcontinent Express Pipeline, the Texas Intrastate system, El Paso Natural Gas (EPNG), the Stagecoach asset and the Tennessee Gas Pipeline (TGP), partially offset by lower contributions from the company's Eagle Ford gathering system assets.

Natural gas transport volumes were up 5 percent year-over-year, primarily from increases on EPNG due to returning a pipeline to service and the retirement of a coal-fired power plant.

Texas Intrastate

KMI said that the Texas Intrastate system benefited from a variety of existing shippers and new contracts, partially offset by reduced volumes on the Tennessee Gas Pipeline.

“Natural gas gathering volumes were up 19 percent from the second quarter of 2022 across most of our systems,” Dang explained. 

Among several new projects, KMI said that the two-phase $678M Evangeline Pass venture will include modifications and enhancements to portions of the TGP and Southern Natural Gas systems in Mississippi and Louisiana, enabling the delivery of the full FERC-certificated project volumes to Venture Global’s proposed Plaquemines LNG facility.

“Construction activities are underway for phase 1 of the project, which includes general operational upgrades enabling TGP to provide approximately 900 million cubic feet per day of natural gas transportation capacity to Venture Global’s facility,” said KMI.

Dang added that contributions from the Products Pipelines business segment were down compared with the second quarter of 2022, saying this was largely due to the impact in the prior-year period of sharply rising commodity prices.

“The crude and condensate business was also impacted by lower re-contracting rates in the Eagle Ford. Total refined products volumes were relatively flat compared to the second quarter of 2022,” Dang said.

The US government forecasts liquefied natural gas exports will increase by 14 percent in 2023 and as a result of less-than-expected natural gas consumption the nation will close the withdrawal season at the end of March with very high inventories.

US natural gas storage design capacity was down in 2021, primarily driven by reductions in the Pacific region of almost 12 percent as energy market changes including LNG exports signalled a greater need for capacity, especially flexible, high-deliverability storage.

The US government expects liquefied natural gas exports to average 10.5 billion cubic feet per day during the second half of 2022, a 6 percent decline compared with the first half of the year.

Southern California Gas Co. (SoCalGas), based in Los Angeles and owned by the Louisiana Cameron LNG plant operator, Sempra Energy, has agreed to pay around $1.1 billion in three settlement agreements stemming from the methane leak in 2015 at the SoCalGas Aliso Canyon natural gas storage facility.

Natural gas storage in the United States has remained essentially unchanged in more than a year with underground working gas capacity in the Lower 48 states showing a small increase in design capacity and peak capacity having a small decrease.

Design capacity by state showed the largest is in Texas at 526 billion cubic feet followed by Louisiana at 451 Bcf then Pennsylvania in third place with 418 Bcf and California is in fourth with 374 Bcf. Illinois came fifth with 301 Bcf and sixth place was filled by Ohio with 253 Bcf.

“Design capacity, sometimes referred to as nameplate capacity, is based on the physical characteristics of the reservoir, installed equipment, and operating procedures on the site, which often must be certified by federal or state regulators,” explained a report on underground natural gas storage just published by the Energy Information Administration.

“We calculated design capacity as the sum of the reported working natural gas capacities of the 387 active storage fields in the Lower 48 states,” said the EIA.

“We excluded the 25 inactive fields in the Lower 48 states from the total. The design capacity metric is a theoretical limit on the total amount of natural gas that can be stored underground and withdrawn for use,” it added.

Demonstrated peak capacity, or total demonstrated maximum working natural gas capacity, represents the sum of the largest volume of working natural gas reported for each individual storage field during the most recent five-year period, regardless of when the individual peaks occurred.

Estimates

Natural gas design capacity was essentially unchanged in 2020. However, some operators revised earlier estimates, increasing working gas capacity.

Design capacity of underground natural gas storage facilities in the Lower 48 states increased by 4 Bcf, or 0.1 percent, in the November 2020 report period compared with the November 2019 period.

A couple of notable revisions increased working gas capacity reported for 2019 in the Mountain and Pacific regions, which reflects the operators’ reassessments of the operational characteristics of the affected fields.

Increasing exports of natural gas also could increase natural gas storage capacity in the Gulf Coast region to support pipeline exports of natural gas to Mexico and LNG exports.

“Working gas stocks ended the November 2020 report period at its highest level since 2016, despite decreased natural gas production and continued high demand for natural gas in electricity generation and for export,” said the US report.

“The higher natural gas storage level was partly because working gas entered the refill season, in April, at 2,006 Bcf, ts highest level since 2017, following a relatively mild winter.

In the Mountain region, Spire Storage West revised the working gas capacity at the Belle Butte field (formerly Ryckman Creek) up by 16 Bcf to 35 Bcf.

South Central

Working natural gas design capacity increased by 5 Bcf in the South Central region. The most notable increase in the region was the 4.2 Bcf gain reported for the Egan Storage Dome by Egan Hub Partners.

Dewatering the salt cavern raised the capacity of this field.

In the Pacific region, the Northwest Natural Gas Company revised the working gas capacity for the Mist field in Oregon, increasing capacity by 1.5 Bcf to 4 Bcf for 2019.

The North Mist capacity expansion came online in May 2019.

Northwest Natural revised its early estimates of the design capacity of the Mist field, the only new natural gas storage reservoir to come online in 2019, based on the observed operational characteristics of the facility. Working gas capacity remained unchanged at the facility in 2020.

Demonstrated peak capacity decreased in 2020 as the decline in the Pacific region more than offset gains reported in other regions.

Overall, demonstrated peak capacity declined by 8 Bcf, despite reported increases in five of six regions in the Lower 48 states as of the November 2020 report period compared with the November 2019.

“Despite the net decline in demonstrated peak capacity for the Lower 48 states, the overall trend was toward increased usage of natural gas storage and higher working natural gas storage levels for the second year in a row,” said the report.

Peak capacity

Demonstrated peak capacity declined by 34 Bcf in the Pacific region because previous peak levels, predating the 2015 natural gas leak at the Aliso Canyon natural gas storage facility in California, are no longer included in the five-year range (December 2015-November 2020).

The Aliso Canyon field has operated at reduced levels since coming back online following the leak. Despite the decline in demonstrated peak capacity for the region, natural storage facilities in the Pacific region also saw increased usage during 2020 as in the other regions.

The South Central region reported the biggest increase in demonstrated peak capacity in 2020, increasing 10 Bcf (0.7 percent) over the previous year.

Salt facilities accounted for 8 Bcf of this year-over year increase. The Midwest had the next largest increase at 7 Bcf, followed by the Mountain region at 7 Bcf and the East region at 3 Bcf.

In recent years, several offsetting trends have affected the industry’s decisions about changes to underground storage capacity levels. Several recent trends may have reduced the need for investment in additional underground storage.

Although natural gas production declined in 2020, overall higher levels of natural gas production compared with a few years ago may have reduced some customers’ need to withdraw from storage to meet their natural gas needs.

The EIA stated that increased output in the Appalachian Basin, the Permian Basin and the Haynesville shale formation had driven production growth.

“In recent years, natural gas prices have fallen and become less volatile,” it also noted.

The seasonal spread between summer and winter natural gas prices has become increasingly smaller, reducing economic incentives to inject natural gas into reservoir and aquifer storage.

New plans

Among new storage plans on the Gulf Coast Sempra Energy’s storage unit in February 2021 gave more details of plans to construct and operate a “high-deliverability” salt-dome natural gas storage facility in Louisiana for existing and proposed LNG export plants with interconnections to key pipelines.

The applicant-prepared environmental assessment for the Hackberry Storage Project submitted to the Federal Energy Regulatory Commission gives full details of the storage facilities in Cameron Parish capable of providing 20.03 Bcf of working gas capacity and 1.5 Bcf per day of LNG feed gas.

LA Storage is leading the project and is a wholly-owned subsidiary of Liberty Gas Storage, ultimately held by Sempra LNG, operator of the Cameron LNG export plant, and parent Sempra Energy.

The storage facility would interconnect with infrastructure operated by Cameron Interstate Pipeline and the certificated Port Arthur Pipeline Louisiana Connector to be operated by Port Arthur Pipeline in Cameron and Calcasieu Parishes in Louisiana.

The interconnection of the Hackberry Storage Project with these pipelines would in turn provide customer access among interstate pipelines serving the Gulf Coast market and natural gas markets along the Southeast and East Coasts.

LA Storage proposes to construct a new natural gas storage facility by converting three existing salt-dome caverns to natural gas storage service and developing one new salt-dome cavern for additional natural gas storage service.

Worldwide liquefied natural gas export plants increased their overall liftings, apart from in the US where the markets were affected locally for natural gas and globally for oil by freezing weather causing power outages that hit US output, while North Asia spot LNG prices rose on firm demand.