January 2024 Vol. 79 No. 1



California OKs new rules for turning wastewater into drinking water 

When a toilet is flushed in California, the water can end up in a lot of places: An ice skating rink near Disneyland, ski slopes around Lake Tahoe, farmland in the Central Valley. 

And — coming soon — kitchen faucets. 

California regulators approved new rules to let water agencies recycle wastewater and put it right back into the pipes that carry drinking water to homes, schools and businesses. 

It's a big step for a state that has struggled for decades to secure reliable sources of drinking water for its more than 39 million residents. And it signals a shift in public opinion on a subject that as recently as two decades ago prompted backlash that scuttled similar projects. 

Since then, California has been through multiple extreme droughts, including the most recent one that scientists say was the driest three-year period on record and left the state's reservoirs at dangerously low levels. 

"Water is so precious in California. It is important that we use it more than once," said Jennifer West, managing director of WateReuse California, a group advocating for recycled water. 

California has been using recycled wastewater for decades. The Ontario Reign minor league hockey team has used it to make ice for its rink in Southern California. Soda Springs Ski Resort near Lake Tahoe has used it to make snow. And farmers in the Central Valley, where much of the nation's vegetables, fruits and nuts are grown, use it to water their crops. 

But it hasn't been used directly for drinking water. Orange County operates a large water purification system that recycles wastewater and then uses it to refill underground aquifers. The water mingles with the groundwater for months before being pumped up and used for drinking water again. 

California's new rules would let — but not require — water agencies take wastewater, treat it, and then put it right back into the drinking water system. California would be just the second state to allow this, following Colorado. 

It's taken regulators more than 10 years to develop these rules, a process that included multiple reviews by independent panels of scientists. A state law required the California Water Resources Control Board to approve these regulations by Dec. 31 — a deadline met with just days to spare. 

The vote was heralded by some of the state's biggest water agencies, which all have plans to build huge water recycling plants in the coming years. The Metropolitan Water District of Southern California, which serves 19 million people, aims to produce up to 150 million gallons per day of both direct and indirect recycled water. A project in San Diego is aiming to account for nearly half of the city's water by 2035. 

California's new rules require wastewater be treated for all pathogens and viruses, even if the pathogens and viruses aren't in the wastewater. That's different from regular water treatment rules, which only require treatment for known pathogens, said Darrin Polhemus, deputy director of the division of drinking water for the California Water Resources Control Board. 

In fact, the treatment is so stringent it removes all of the minerals that make fresh drinking water taste good — meaning they have to be added back at the end of the process. 

"It's at the same drinking water quality, and probably better in many instances," Polhemus said. 

It's expensive and time-consuming to build these treatment facilities, so Polhemus said it will only be an option for bigger, well-funded cities — at least initially. 

CGA’s DIRT report correlates infrastructure investment with increased excavation damage  

Common Ground Alliance (CGA), the national nonprofit trade association dedicated to protecting underground utility lines, people who dig near them and their communities, recently announced the findings from its 2022 Damage Information Reporting Tool (DIRT). It revealed concerning increases across key damage indicators. 

The report found that damage to underground utilities, which pose severe risks to public safety and interrupt commerce, has trended upward over the last three years. Excavation activity continues to increase, as states work to improve infrastructure, along with a significant influx of funding from the Infrastructure Investment and Jobs Act.  

Three-year modeling from 2020–2022 indicates that damages per construction spending rose 12.35 percent and damages per 1,000 transmissions rose 9.34 percent between 2021 and 2022. A regression analysis of consistent 2020–2022 data, which considered additional variables including weather, population and infrastructure density further confirms that damages were at best flat and likely increasing.  

The annual DIRT provides a comprehensive accounting and analysis of damages to buried infra-structure in the U.S. and Canada to help stakeholders understand the current landscape and the fac-tors contributing to underground facility damages. As excavation activity continues to increase, the report underscores the importance of addressing the ongoing causes of damage to vital facilities to drive these numbers down.  

The report analyzed all 2022 data submitted voluntarily to DIRT by facility operators, utility locating companies, 811 centers, contractors, regulators and others from the U.S. and Canada, and con-textualized the data as part of a three-year trend analysis (2020-2022). Reflecting excavation/construction stakeholders’ increased engagement with damage prevention, that key group was the leading source of damage reports for the first time in 2022.  

The analysis of 2022 data indicates that a few persistent challenges are responsible for nearly 76 percent of damages that occur, including no notification to the 811 centers, failure to pothole and/or maintain sufficient clearance, facilities not marked or marked inaccurately due to locator error, and other improper excavation practices.  

No-notification damages make up more than 25 percent of all damages, with 77 percent of these attributed to professional excavators. Focusing industry efforts and outreach on these top challenges is key to making measurable progress in reducing damage and near-miss incidents.  

The report also provides recommendations to enhance reporting and analysis of damages to better understand and address trends, including the implementation of standardized data collection fields and creation of damage prevention indices to gauge progress over time. Stakeholders are also encouraged to participate in the Damage Prevention Institute’s (DPI) accreditation and peer review processes to help develop the next generation of industry performance metrics. 

EIA forecasts 20 Bcf/d boost for U.S. LNG export terminals with new pipelines 

More than 20.0 billion cubic feet per day (Bcf/d) of natural gas pipeline capacity is under construction, partly completed, or approved to deliver natural gas to five U.S. liquefied natural gas (LNG) export terminals that are currently under construction, according to U.S. Energy Information Administration’s Natural Gas Pipeline Project Tracker. 

Some of the new pipeline capacity is under the jurisdiction of the Federal Energy Regulatory Commission, and some is under the jurisdiction of the Railroad Commission of Texas. About 13.5 Bcf/d of pipeline capacity is currently under construction, and each new LNG terminal—Plaquemines in Louisiana and Golden Pass, Port Arthur, Corpus Christi Stage III, and Rio Grande in Texas—has one or more pipelines being developed. 

Golden Pass Pipeline: Golden Pass Pipeline, LLC, is expanding the existing 69-mile pipeline that originates northeast of Starks, Louisiana, to enable deliveries of 2.5 Bcf/d of natural gas to the Golden Pass LNG terminal in Jefferson County, Texas. The pipeline was originally built in 2010 to transport imported natural gas to interconnected interstate pipelines and northern U.S. markets. Golden Pass Pipeline is changing the primary flow of the pipeline to flow south and adding connections to nearby natural gas supply sources. 

Louisiana Connector Project and Texas Connector Project: Port Arthur Pipeline Company plans to construct two pipelines, each with a capacity of 2.0 Bcf/d, to deliver natural gas to the Port Arthur LNG export terminal in Jefferson County, Texas. When completed, the 72-mile Louisiana Connector Project will deliver natural gas through pipeline interconnections in Louisiana and Texas, and the 34-mile Texas Connector Project will extend from interconnections in Texas to the export terminal. 

Gator Express Pipeline: Venture Global Gator Express is constructing two pipelines, each with approximately 2.0 Bcf/d capacity, to deliver natural gas from pipeline interconnections to the Plaquemines LNG export terminal located about 20 miles south of New Orleans, Louisiana. Phase 1 of the project includes a 15-mile pipeline, and Phase 2 includes a 12-mile pipeline. 

Evangeline Pass Expansion Project: Tennessee Gas Pipeline Company plans to construct this 13-mile pipeline with capacity of 1.1 Bcf/d. The pipeline is designed to deliver natural gas to the Plaquemines LNG export terminal from a Southern Natural Gas Company interconnection in Mississippi to a new interconnection with the Gator Express Pipeline in Louisiana. 

Venice Extension Project: Texas Eastern Transmission is constructing this three-mile pipeline with 1.3 Bcf/d capacity, which will replace an existing segment of its pipeline system, to accommodate natural gas deliveries to the Plaquemines LNG export terminal. 

ADCC Pipeline: WhiteWater Midstream is constructing this 39-mile pipeline with capacity of 1.7 Bcf/d. The pipeline is slated to deliver natural gas to the Corpus Christi Stage III project. This pipeline originates at the end of the Whistler Pipeline near the Agua Dulce hub in Nueces County, Texas, in the Eagle Ford production region. 

Corpus Christi Stage III Pipeline: Cheniere Corpus Christi Pipeline is constructing this 21-mile pipeline with 1.5 Bcf/d capacity. The pipeline is co-located with the existing 2.8 Bcf/d pipeline and is slated to deliver natural gas from pipeline interconnections to the Corpus Christi Stage III project. 

Rio Bravo Pipeline: Rio Bravo Pipeline Company is constructing two 138-mile pipelines with a combined capacity of 4.5 Bcf/d to deliver natural gas from the Agua Dulce supply area to the Rio Grande LNG terminal in Brownsville, Texas. 

California approves Delta Conveyance Project to modernize water infrastructure 

California’s Department of Water Resources (DWR) recently approved the Delta Conveyance Project, a modernization of the infrastructure system that delivers water to millions. According to a news release, DWR has certified the Environmental Impact Report (EIR) and completed an extensive environmental review. DWR selected the “Bethany Reservoir Alignment” for further engineering, design and permitting.   

According to DWR, California is expected to lose 10 percent of its water supply by 2040 due to extreme weather conditions. Extreme weather will result in more intense swings between droughts and floods, intensely straining California’s 60-year-old water infrastructure. 

The Delta Conveyance Project will modernize the state’s water infrastructure to capture and move more water during wet seasons to better endure dry seasons. The project will also minimize future losses from climate-driven weather extremes and protect against earthquakes disrupting water supplies while continuing to meet regulatory water quality and fishery requirements. 

The project will also include a Community Benefits Program to ensure local communities get the means and resources to achieve tangible and lasting benefits. 

There are 17 public water agencies from the Bay Area, Central Valley, Central Coast, and Southern California participating in the project. Their customers are among the 27 million people and 750,000 acres of farmland that rely on the SWP to provide an affordable source of high quality, clean and safe water. 

In certifying the EIR and approving the project, DWR has determined the environmental review complies with the California Environmental Quality Act (CEQA). DWR has also identified feasible mitigation measures that must be included in the project approval to address potential environmental impacts. 

PG&E hits milestone with 600 miles of undergrounding powerlines 

Pacific Gas and Electric Company (PG&E) has constructed and energized more than 600 miles of underground powerlines since its ambitious 10,000-mile undergrounding program started in mid-2021, the company said on Dec. 20. 

And the 350 miles completed in 2023 represents the most ever in a single year by PG&E and nearly twice as many miles as were completed in 2022. 

"Our customers in high fire-risk locations where we have undergrounded powerlines not only benefit from wildfire mitigation, but also improved reliability at the lowest cost over the asset lifecycle," said Peter Kenny, PG&E's senior vice president of Major Infrastructure Delivery, which includes the 10,000-mile Undergrounding program. "That progress will continue in the years ahead." 

From $4 million per mile when the program first started, PG&E targeted cost reductions to $3.3 million per mile by this year. In fact, the unit cost has now fallen below $3 million per mile. 

Undergrounding eliminates nearly 98 percent of the risk of wildfire ignition from electrical equipment. And it's one of many layers of wildfire protection from PG&E, ranging from 600-plus weather stations and high-def cameras with AI capability for early fire detection to safety shutoff programs that prevent ignitions that could lead to catastrophic wildfires. 

The Undergrounding program was launched in June 2021 by PG&E CEO Patti Poppe. PG&E and contract crews completed 73 miles that year, 180 miles in 2022 and 350 miles this year. 

The California Public Utilities Commission recently approved PG&E's 2023-2026 General Rate Case, which authorized 1,230 miles of undergrounding during those four years. PG&E is evaluating the GRC decision and creating specific work plans for 2024 and beyond. Also, by mid-year, PG&E will file its 10-Year Undergrounding Plan, which was enabled by the passage of SB 884. 

Investing in undergrounding in the highest fire-risk areas benefits all PG&E customers in several ways—from improved air and water quality resulting from fewer fires; protection of wildlands; and over the long run, lower costs to customers due to reduced maintenance and vegetation management costs. 

Expanding PG&E's electric system underground in High Fire-Risk Areas (HFRAs) will not only help reduce wildfires caused by utility equipment, but also will improve reliability and reduce the need for safety-related power outages. 

Williams acquires Gulf Coast natural gas storage, pipeline assets for $1.95 billion 

Williams reached an agreement to acquire a portfolio of natural gas storage assets from an affiliate of Hartree Partners LP for $1.95 billion. The transaction includes six underground natural gas storage facilities located in Louisiana and Mississippi with total capacity of 115 billion cubic feet (Bcf), as well as 230 miles of gas transmission pipeline and 30 pipeline interconnects to attractive markets, including LNG markets, and connections to Transco, the nation’s largest natural gas transmission pipeline. The acquisition price represents an approximate 10x estimated 2024 EBITDA multiple. 

The six natural gas storage facilities include four salt domes with combined capacity of 92 Bcf and two depleted reservoirs with combined capacity of 23 Bcf. The facilities have injection capacity of 5 Bcf/d and withdrawal capacity of 7.9 Bcf/d, among the highest of any natural gas storage platform in the United States. Two of the facilities, Pine Prairie and Southern Pines, are directly connected with Transco and are well positioned for expansions. 

“This premier natural gas storage platform on the Gulf Coast fits squarely within our strategy to own and operate the best assets connected to the best markets to serve growing demand driven by LNG exports and power generation,” said Williams President and Chief Executive Officer Alan Armstrong. “These assets better position Williams’ natural gas storage operations to serve Gulf Coast LNG demand and growing electrification loads from data centers along the Transco corridor. Importantly, this storage will also allow us to provide value to customers in markets with growing renewables adoption as daily peaks for natural gas increases the need for storage. Since 2010, U.S. demand for natural gas has grown by 56% while gas storage capacity has only increased 12%. We expect the increasing demand for high deliverability storage to drive significant earnings growth across these assets.” 

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