• LADWP could face losses of up to $350 million if its equipment or operations cause a wildfire. The utility’s mitigation measures take into account vegetation management and designing transmission lines to withstand wind conditions, for example.
• Rising temperatures could lead to decreasing thermal efficiencies, meaning that more fuel will be required to generate the same amount of power. LADWP’s estimated cost of impact is based on the price of additional emissions that will be required to make up for that. The utility addresses this risk by incorporating decreasing thermal efficiencies in its load forecast.
• Energy efficiency, distributed solar and other distributed energy resources could reduce energy sales and thereby, revenues, posing a market-related climate risk, according to the utility. These measures will also lower costs.
• LADWP is aiming to increase distributed solar installation by 4,000 GWh over the next decade. It has a combined budget of roughly $22.2 million for its community solar and utility built solar efforts.

LADWP is aiming to supply 55% renewable energy by 2025, 80% by 2038 and 100% by 2045. As part of that transition, the municipal utility announced plans last year to shift away from coal generation at its Intermountain Power Project, to natural gas and by 2045, hydrogen. The facility will have the ability to run on a 30% hydrogen fuel mix on its first day of operation, before scaling up to 100%.

• More severe heatwaves could increase load as well as lead to possible equipment failure, putting stress on the transmission system. A heatwave in July 2006 cost PG&E an estimated $150 million to $300 million, related to the increased price of electricity and infrastructure repairs. The utility addresses this risk through demand response programs, which cost around $46 million in 2019.
• PG&E is anticipating worsening storms in the area. In 2019, PG&E recorded $205 million in its catastrophic emergency management account due to storms that damaged electric and gas distributed facilities and electric generation facilities, among other impacts.
• Changes in precipitation can impact PG&E’s hydroelectric system — the largest in the nation. PG&E spent $151 million annually to operate and maintain hydro during California’s drought between 2011 through 2014.
• PG&E is conducting a deep dive research project to understand the impacts of inland and coastal flooding, which includes sea level rise, with a budget of $50,000. Preparing for sea level rise could include elevating and replacing equipment; completely moving and rebuilding a substation would cost $100 million at a minimum, according to the utility.
• The financial impact of wildfire risk “is unknown but could be substantial,” according to PG&E, due to California’s law of inverse condemnation, which holds utilities liable for the damages caused by fires sparked by their equipment even if they are not found to be negligent. This year, the utility paid out $25.5 billion to resolve fire liabilities from before 2018, which pushed it into Chapter 11 bankruptcy. PG&E plans to spend $11.7 billion on its wildfire mitigation plan from 2019 through 2022.

PG&E filed for Chapter 11 bankruptcy in early 2019 after facing liabilities from wildfires caused by its power lines, and paid out $25.5 billion to resolve those liabilities and emerge from bankruptcy earlier this year. The utility is assessing potential scenarios to meet California’s policy goal of achieving 100% renewables or zero-carbon electricity by 2045.

• Shifts in hydrological cycles could affect the capacity of hydroelectric generation. According to SMUD, one inch of precipitation leads to 35,000 MWh of generation, meaning that a projected 23% decrease in yearly precipitation could lead to a drop of a little over 149,005 MWh, resulting in a $16.8 million loss for the utility.
• In 2014 and 2015, SMUD spent roughly $5.1 million responding to the King Fire in El Dorado County, California, which the utility uses as a proxy for the cost of future risks. The utility also spent $7.2 million on wildfire mitigation in 2019, which included roughly $5.8 million on wildfire insurance, as well as a mix of grounding projects, inspecting transmission lines, and other strategies.
• The $28.4 million in costs associated with current regulation is an “overestimate” based on the California Air Resources Board’s November greenhouse gas allowance auction, with a price floor of $16.8 per metric ton. However, it doesn’t take into the account the free allowances that SMUD has as well as efforts to reduce emissions. The utility spends between $1.5 million and $2 million on programs to quantify and reduce emissions.

This July, SMUD passed a climate emergency declaration that set the municipal utility on the path to delivering carbon-neutral electricity by 2030 — 15 years ahead of California’s goal of supplying 100% electricity from zero-carbon and renewable resources by 2045. This is a particularly aggressive timeline, given that most utilities that have committed to being carbon-free or net-zero emissions are aiming to do so around 2045 and 2050.

• Sempra Energy’s analysis covers all its subsidiaries, which include San Diego Gas & Electric (SDG&E), Southern California Gas Company (SoCalGas), Oncor Electric Delivery Company, Infraestructura Energetica Nova and Sempra LNG.
• Since 2007, SDG&E has invested roughly $2 billion in wildfire mitigation measures in its service territories. Wildfire risk could also lead to downgrades of Sempra Energy’s credit ratings. In September, for instance, S&P Global Ratings revised its outlook on SDG&E from stable to negative due to wildfire activity, which could make it more expensive for Sempra and its subsidiaries to borrow money, raise capital and issue debt securities. Sempra also lists its wildfire-related investments as a mitigation measure against the risk of changing precipitation patterns, which could both affect its power generation facilities in the southwest and increase the risk of regional wildfires.
• SDG&E expects that two aspects of changing customer behavior — shifting to rooftop solar due to utility bill increases, and switching to other load-serving entities — could impact it in the future. The city of San Diego, for instance, is considering implementing a community choice aggregator, which would leave SDG&E procuring resources for less than half of its bundled load, posing as a market-related climate risk for the utility.
• “[A] substantial reduction or the elimination of natural gas as an energy source in California could have a material adverse effect on SDG&E’s, SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations,” Sempra noted.

California’s Senate Bill 100, which was signed in 2018, laid out a goal for the stat to achieve 60% renewable energy by 2030 and 100% renewable or zero-carbon energy by 2045. In 2019, SDG&E delivered 45% of power from renewable sources.

• NRG Energy uses Hurricane Harvey from 2017 as an illustrative example to show the potential financial impacts of extreme weather. The financial impact includes $20 million cost to its operations business from damage to the Cottonwood Generating Facility and $20 million “in lost revenue to the retail business due to transmission disruptions.”
• For extreme weather and other risks, NRG says, “the cost of management is integrated into operational costs, not an additional cost.”
• For emerging regulations, NRG considers a carbon price and says, “the potential financial impact figure is based on the expense of hiring an additional full time employee to manage the carbon trading program.”
• Regarding potential changes in customer behavior, NRG says, “by using less of what we sell, this could impact our profitability.” But it has no financial impact figure, saying that such information is “not available due to competitive information.”

NRG Energy said in October it has “partnered with developers to offtake more than 1.9 GW of new solar, with more on the horizon,” to meet its customers’ “growing preference for renewable energy.” The company further said, “that expanding competitive energy markets and improving access to retail energy choice is an important way to meet sustainability goals,” adding that it has “also advocated for the adoption of a Forward Clean Energy Market as a way to achieve clean energy outcomes in a way that’s efficient and inclusive.” The company last year said it expects to reduce emissions 50% below 2014 levels by 2025 and achieve net zero emissions by 2050.

• Changes in precipitation or prolonged droughts could require Pinnacle West’s principal subsidiary, Arizona Public Service, to drill deeper wells at its Sundance and Yucca power plants, at a cost of $2 million to $3 million each. The utility has a Water Resource Department — with a $1.4 million annual budget — that oversees water supplies.
• Drought could also create a higher risk of wildfires in APS’ service territory, and the utility is looking at investing into technologies that would help it detect and prevent wildfires — such a potential capital project could require investments of up to $2 million. The utility also incurs an approximate yearly cost of $17 million for its forestry business unit, which focuses on hardening assets and managing rights-of-way.
• A carbon tax — that Pinnacle calls “one of the most likely but unpredictable outcomes” — could cost APS $1.2 billion, an estimate based on the cost of carbon dioxide in California’s cap-and-trade market and the utility’s projected carbon emissions between 2019 through 2032. APS estimates that it spends $500,000 a year tied to “monitoring the regulatory landscape,” half of which goes to personnel costs.

Early this year, APS announced plans to deliver 45% renewables by 2030 and 100% carbon-free energy by 2050, as well as ending its coal-fired generation by 2031. That plan would require it to retire two units of the Four Corners coal plant as well as the Cholla Power Plant — which it plans to shutter by 2025 — a move that Sierra Club estimates could save customers around $500 million if the plants are replaced with solar-plus-storage projects.

• Ameren finds that changes in precipitation, including potential floods or droughts, are considered a short-term, low-magnitude risk. Flooding or an unexpected drought could harm plant operations by limiting the water supply and endanger distribution operations.
• The utility’s mitigation response is a plan to invest $3.2 billion in transmission upgrades over the next five years to ensure it can maintain reliability on its system. It also anticipates a loss of load due to changes in customer behavior, including greater energy efficiency and greater use of distributed energy resources.
• Its estimated costs of transitioning to low-emissions tech are likely to rise as its $1.2 billion estimate covers just its wind investment costs, and the utility has since upped its renewable energy goals. Ameren in September announced it would spend $4.5 billion over the next decade to add 3.1 GW of new wind and solar to its system.

Ameren announced plans to increase its emissions reductions this year, aiming for net-zero carbon emissions by mid-century. Much of its plan seems to be driven by investor and customer preferences, rather than regulatory pressure, according to the utility and other stakeholders.

As part of its plan, the utility would add 5.4 GW of renewable energy by 2040, though its plan also keeps coal-fired plants online into the 2040s. Advocates in the state hope securitization legislation could change its coal plant retirement plans.

• Ice storms, severe thunderstorms and tornadoes present medium-magnitude, short-term risks to DTE Energy, especially if some of the largest damages cannot be recovered through the rate base. The utility is investing $5 billion over the next five years in distribution infrastructure to improve resiliency, though the utility isn’t yet able to say how much long-term storm patterns may change its normal annual storm planning.
• DTE considers the transition to low-emissions technology a high-magnitude, short-term risk that will see the utility investing almost $4 billion over the next five years in natural gas and renewable energy.
• To mitigate the impacts of price volatility, the utility’s home state of Michigan has a Power Supply Cost Recovery mechanism that allows DTE to recover fuel costs, including unexpected changes in fuel prices. Investing in wind and solar energy is another way the utility says it mitigates the risk of natural gas’s price volatility.
• Warmer weather conditions may reduce the need for heating in the winter, but could increase peak demand in the summer. The utility considers this risk medium-magnitude.
• A potential change in Great Lakes water levels due to precipitation changes could negatively impact power plant facilities’ operations, specifically their cooling requirements. It could also impact the supply chain as the Great Lakes are a major transport corridor for raw materials.

DTE is aiming to achieve net-zero carbon emissions by 2050, and reduce emissions 80% below 2005 levels by 2040. Michigan, where the utility exclusively operates, is under an executive order to achieve net-zero emissions by 2050, and the governor’s plan includes a provision that will give the state’s environmental regulators greater oversight over the utility’s integrated resource plan.

DTE filed an updated resource plan with regulators this year after regulators found its initial plan “fundamentally flawed” and directed the utility to reexamine its plan with a more realistic look at wind and solar options.

• Exelon says extreme weather could stress its transmission and distribution systems, communications system and technology leading to increased maintenance and capital costs and limiting its ability to meet peak demand. It could also affect the availability of generation and “the ability to source or send power to where it is sold.”
• The cost of impact for extreme weather reflects the range of increased storm costs from 2018 to 2019, with Exelon utilities Pepco, Delmarva Power and Light and Atlantic City Electric on the low end of the range and Commonwealth Edison on the high end.
• The $500 million mitigation cost is for an initiative in parts of Washington, DC, to reduce storm damage from overhead lines by putting select feeders underground. More broadly, Exelon says it invested $5.5 billion across its regulated utilities in 2019 and plans to invest about $26 billion in its utilities from 2020 through 2023, including actions to address the physical risks from climate change and support storm recovery.
• Exelon says the failure to enact a carbon price could lead to “decreased asset value or asset useful life leading to write-offs, asset impairment or early retirement of existing assets.” The company supports both comprehensive federal GHG legislation and state clean energy initiatives.
• Exelon says that challenges in communicating the success of its GHG reduction impacts pose a risk to its reputation. Acknowledging that the “economic value of reputation is difficult to quantify with precision, Exelon nevertheless says that if 1% of its $45-50 billion in market value could be attributed to climate change-related reputation, the potential financial impact could range from $450 million to $500 million.

With over 19.6 GW of nuclear capacity and over 2 GW of wind and solar, Exelon claims to be “the largest generator of zero-carbon electricity in the nation.” However, Exelon says that due to various factors, including low wholesale power prices and the absence of federal or state policies that value the clean attributes of nuclear power, it has closed some of its nuclear plants. Additional plants could be at risk for early retirement if programs in New York and Illinois that do reward the zero emission attributes of nuclear “do not operate as expected over their full terms.” The company has pushed for alternatives to current wholesale market constructs to better achieve state clean energy policies. The company does not have an external emissions reduction goal, but notes that due to its “already very clean fleet, Exelon is not always perceived as achieving marginal reductions; Exelon’s fleet’s carbon intensity is already 90% lower than the industry average.” It further notes that through the combined efforts of all its companies, it “reduced, displaced or avoided nearly 100 million metric tons of U.S. electric sector emission each year from 2005 to 2020.”

• WEC did not provide potential financial impact figures for any of the eight risks it listed in its 2020 CDP report. For the extreme weather risk, it said that “any of the described events could lead to substantial financial losses.” For all the risks listed, it said, “a quantitative estimate of the inherent financial impacts of the risk is not currently available.”
• WEC similarly did not provide information on the cost of mitigation. For extreme weather, it said, “We assess and adjust for weather-related risks in our daily operations in order to improve reliability and resilience, safety, and customer satisfaction. We have not calculated the cost of management.”
• Although it singles out EPA’s Affordable Clean Energy rule as a potential risk, it said, “the rule is not expected to result in significant additional compliance costs, including capital expenditures, but may impact how we operate our existing fossil-fueled power plants and biomass facility.”
• In terms of its response to extreme weather risks, WEC subsidiary Wisconsin Public Service is engaged in a multi-year system modernization and reliability project “focused on modernizing parts of its electricity distribution system by burying or upgrading lines.” At the same time, subsidiary We Energies “is upgrading its infrastructure and plans to rebuild hundreds of miles of electric distribution lines and replace thousands of poles and transformers.”

In 2019, WEC Energy Group exceeded its 2030 goal of reducing carbon dioxide emissions 40% below 2005 levels. The company is now aiming to reduce CO2 emissions from its electricity generation 70% below 2005 levels by 2030 and have a net carbon neutral electric generation fleet by 2050. Early retirement of more than 1,800 MW of coal power helped WEC achieve its 2030 target early, the company said in August. In addition, it plans to invest $900 million over the next four years on more renewables to help achieve its emission reduction goals.

• A single severe weather event such as a windy thunderstorm, cyclone or hail, would at a maximum cost Xcel $40 million, the company estimates, if restoration costs were not fully recoverable from its rate base. The utility’s assets located on the Great Plains are especially susceptible to this kind of weather event, which represents a medium-magnitude risk.
• Mitigating the risk of such weather events comes through water management and infrastructure upgrades, among other things, and utilities are able to get rate recovery from storm damages based on evidence that the company acted in “good preventative faith.”
• Droughts and water shortages also present risks to the utility’s power plants that rely on water for cooling purposes as part of their operations. Though its Midwest territory is fairly humid, the utility’s assets stretch down to the more arid West and Southwest, where water scarcity is becoming a greater concern.
• Alternative energy suppliers and residential-sited resources also present risks to the utility’s load, along with energy efficiency, all of which are behavioral responses to rising climate concerns. Cost of managing this risk is calculated based on the manpower used to implement demand-side management and energy efficiency programs.

Xcel became the first major multi-state utility to commit to 100% carbon-free energy by mid-century at the end of 2018. In January of this year, it decided to shutter one of its coal-fired plants a decade early, in part because of water scarcity concerns. The utility has since said it doesn’t expect water constraints to lead to the early retirement of any of its other plants, but Xcel is considered one of the highest-risk utilities when it comes to water shortages, according to a January Moody’s report. During the company’s Q4 earnings call, CEO Ben Fowke said seasonal operations of some of its coal plants could also help the utility mitigate some of its risks in more arid regions.

• Dominion Energy said extreme weather events could put all of its generation at risk, including solar and wind. A change in sea levels or sea temperatures would particularly impact utility operations along coastlines, such as the Cove Point LNG Terminal in Maryland.
• The utility calculated the cost for the first phase of its Grid Transformation Plan, filed in 2018, by adding the approximate capital investment for the plan for 2019-2021 ($816.3 million) and the proposed operations and maintenance expenses ($101.5 million), totaling $917.8 million.
• The utility plans to bury 4,000 miles of distribution lines by 2028, as part of a four-part Strategic Underground Program, that will cost $1.417 billion. The initiative will increase the ability of its distribution system in Virginia to withstand hurricanes and other extreme weather events.

Dominion responded with a slew of long-term planning models to represent policy changes in Virginia, which would guide utility decarbonization efforts. The company had established goals to add offshore wind off the coast of the state and to increase renewable generation.

Dominion committed to adding 3 GW of renewable energy online or under development in Virginia within the next four years.

Dominion spun off some gas assets this summer, and canceled a major construction project it was leading with Duke Energy: the Atlantic Coast Pipeline.

• Duke Energy calculates the possibility of flooding and cyclones as a high-magnitude short-term risk. The total impact over the next decade was determined as up to ten times the damage caused by Hurricane Michael and Florence.
• Duke’s inhouse Drought Mitigation Team monitors water levels and implements changes at impacted nuclear and coal-fired power plants to reduce drought-related risks. The cost of impact is calculated based on the idea that a nuclear plant, like the McGuire facility in North Carolina, might lose power for a week, and necessitate greater output from gas plants.
• Duke represents the cost of managing many climate-related risks as the capital cost of new resources for planned investments, which was lowered between the 2019 and 2020 CDP disclosure from $5.1 billion to $4.6 billion.

Duke announced a net-zero by 2050 goal in the fall of 2019, spurred by a number of stakeholders, including environmental organizations. Several substantial long-term shareowners asked Duke in 2019 to set a net-zero by 2050 carbon emissions target and to publish transition plans.

Duke announced plans to triple its renewable energy output by 2030 and to retire 862 MW of coal by 2024. Duke’s gas operations are expected to reach net-zero methane emissions by 2030 by replacing pipelines and increasing the monitoring of infrastructure.

• Entergy’s average proactive hardening costs annually are $450 million, investing in transmission hardening and elevating substations to mitigate flooding, preparing drills and business continuity practices for the 25 GW of generation it owns or leases. The utility also prioritizes investments in distribution assets by zones of aging or decay to restore, replace or treat equipment.
• Water availability is necessary to operations and revenues, and Entergy reduces the likelihood of the risks of changes to precipitation patterns through facility hardening, property insurance, water resource planning and other initiatives to build greater resilience for its operating companies and other assets, including its hydroelectric facilities.
• Entergy doesn’t include in its direct costs the investments made in restoration projects for Louisiana’s barrier islands and coastal wetlands, to promote greater resiliency in their service territory. Entergy’s service area is susceptible to storm impacts “potentially made worse” by rising sea levels and the loss of coastal wetlands.
• 2020 was Entergy’s first CDP disclosure and did not provide financial impact figures or explanations for the full risks identified.

In 2019, Entergy set a commitment to reduce carbon emissions 50% below levels in 2000 by 2030. The company made voluntary greenhouse gas reports for over a decade and continues to invest in emissions verification annually.

The company says it has reduced carbon dioxide emissions by 41% compared to 2000 so far. The utility plans to continue retiring older, less efficient resources and add about 1 GW of solar generation and over 6 GW of combined cycle gas turbine generation.

• Southern is wary of regulatory lag for rate adjustments if its subsidiaries, including Southern Company Gas, are required to invest in conservation measures which could result in reduced sales.
• The company does not identify the costs of any acute physical risks tied to climate change in its latest filing, while recognizing weather related impacts on its generation, transmission and distribution systems, and is investing in smart grid technologies and energy storage systems to mitigate impacts. In 2019, its gas business addressed record low temperatures in its northern Illinois distribution area by planning proactive service appointment scheduling ahead of the storm.
• While Southern doesn’t disclose estimates for mitigation and recovery from extreme weather events, it conducts trainings for several programs to prepare employees for hurricane recovery, or to respond to tornadoes and ice storms.
• Southern assumes that if all existing residential homes served by the utility reduce energy use with the best technologies available, total revenue for the company would be about $3 billion, as opposed to $7 billion (the scenario under which energy efficiency is not implemented widely). The difference is what Southern has deemed as the high-level estimate impact of energy efficiency: $4 billion.

The company committed to transitioning to net zero emissions by 2050.

Southern’s regulated utilities work in states with different incentives for climate transitions, and has developed some clean energy resources in spite of not having a state-based mandate for it, as in Georgia.

• Avangrid is looking at a mix of regulatory, physical and market-based risks, related to climate change, but says the “actual financial impact is unpredictable.” Weather events can have a significant impact but much depends on which facilities are affected. The costs to restore service and repair damaged facilities, obtain replacement power and access available financing sources, may not be recoverable from customers “and could adversely affect our cash flows, results of operations and financial position,” it says in its 2020 CDP filing.
• The utility sees climate risks in the energy markets, in the form of potential decreased revenues that would accompany any policy changes that support coal or nuclear plants. “This potential change in the energy market to support uneconomical facilities may distort the market prices,” the utility said.
• Avangrid owns 7.4 GW of wind and solar, of which approximately 30% of the electricity generated is sold into wholesale markets. The utility says a $1/MWh decrease in the wholesale prices in the markets where Avangrid Renewables participates could have a negative impact on earnings of approximately $3 million in 2020. The company’s strategy calls for increasing long-term contracts with commercial and industrial customers and reducing merchant exposure.

In October, Avangrid made a cash offer for PNM Resources in a merger it says will create “one of the biggest clean energy companies” in the United States. Avangrid Networks currently includes eight electric and natural gas utilities, serving 3.3 million customers in New York and New England.

Avangrid owns 1,900 MW of renewable energy and has a pipeline of 1,400 MW of renewables assets in New Mexico and Texas. PNM Resources owns approximately 2.8 GW of generation capacity and provides electricity in New Mexico and Texas. The merger with PNM could lead to the development of more renewables in New Mexico, say experts.

Avangrid says it is “continuously evaluating the regulatory risks and regulatory uncertainty presented by climate change,” as such concerns “could potentially lead to additional rules and regulations that impact how we operate our business.” The utility points to New York, where regulators’ Reforming the Energy Vision proceeding has for years been reimagining the state’s energy system.

While the end result of the REV process “remains unclear,” Avangrid said in its 2020 CDP filing, the proceeding “could alter the utility model in New York in a manner that could create material adverse impacts on our businesses and operations in New York.”

Avangrid has pledged to be carbon neutral by 2035.

• Liberty Utilities sees the potential for high financial impacts from physical climate risks, but its 2020 CDP filing says “we currently do not have a financial impact figure assessed.”
• Related to wildfires, Liberty sees the potential for increased insurance premiums and reduced availability of insurance on assets in ‘high risk’ locations. In addition, increased air temperatures could result in decreased efficiencies over time of both generation and transmission facilities. Extreme weather events create a risk of asset damage, and the increased frequency and severity of weather events “increases the likelihood that the duration of power outages and fuel supply disruptions could increase.”
• Liberty also sees a risk that climate change impacts the output of its renewable generation facilities. Expected returns from both solar and wind assets “are based off current weather patterns,” which climate change can modify.

Algonquin Power & Utilities describes itself as “a growing renewable energy and utility company with assets across North America,” operating through subsidiaries Liberty Power and Liberty Utilities to deliver electricity and gas to customers in the United States and Canada. The company delivers electricity to 267,000 customers and owns related generation assets in California, New Hampshire, Missouri, Kansas, Oklahoma and Arkansas.

Algonquin has a portfolio of long-term contracted wind, solar and hydroelectric generating facilities representing over 2 GW of installed capacity and more than 1.6 GW of incremental renewable energy capacity under construction. The company wants to reach 75% renewable generation capacity by 2023.

The utility has been taking steps to reduce its carbon footprint and add more emissions-free resources. Last year, it developed a storage program for utility-owned behind-the-meter capacity in its New Hampshire territory. And this summer, Liberty dropped plans to construct the proposed Granite Bridge natural gas pipeline after concluding it could meet demand with existing infrastructure.

• Headquartered in London, National Grid reports CDP risk and mitigation measures in Great British Pounds. These estimates have been converted to U.S. dollars using a conversion rate of £1 to $1.30.
• National Grid expects its largest climate mitigation cost will be to address increased severity and frequency of extreme weather events such as cyclones and floods. The utility says there is a risk it may either fail to mitigate adequately or to deal with the consequences of flooding, which could include loss of supply in both its gas and electricity networks leading to disruption to large numbers of energy users. Flood mitigation is primarily associated with its U.K. service territory.
• In Massachusetts, the utility sees a significant gap between the fines associated with exceeding methane leak targets on its gas network and the cost to prevent leaks from occurring. The utility has a plan to remove or replace leak prone pipes and in 2019 removed 65 miles from service in Massachusetts.

National Grid is based in the in U.K. but serves more than 20 million customers in New York, Rhode Island and Massachusetts. The utility is aiming for net zero greenhouse gas emissions by 2050 and recently said it supports overhauling the Northeast’s wholesale electricity market design, transmission planning process and the governance of its grid operator to advance decarbonization efforts.

The utility’s Net Zero by 2050 plan involves cutting emissions from the fuels and electricity it provides 20% by 2030. The utility is targeting 80% cuts to emissions from direct operations and power purchases by 2030.