Climate change solutions
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Canada has a near-term chance to slow climate pollution by cutting methane from oil and gas operations. But, that opportunity depends on whether provincial rules will be held to the same standard as Ottawa’s.
As of today, there are over 600 active forest fires spreading across Canada, destroying millions of hectares of forest and sending billowing smoke into communities. From Newfoundland to Ontario to British Columbia, this year’s destruction has been gargantuan, totaling an area the size of Switzerland.
Climate change, which causes lengthy droughts, dried vegetation and extreme heat events, has made it easier for forest fires to spark and spread. The cheapest and easiest way for Canada to cut back on its climate pollution? Tackling unnecessary and wasteful methane emissions from the oil and gas sector.
Methane is the main chemical found in natural gas. It’s also a super-pollutant that is more than 84 times more powerful than carbon dioxide over the near term. Scientists estimate methane is responsible for 30% of global warming to date. Unlike carbon dioxide, methane breaks down after about a decade in the atmosphere. Cutting these emissions can slow warming faster than many other climate actions.
The majority of Canada’s methane comes from the oil and gas sector in Alberta, Saskatchewan and British Columbia – the country’s largest onshore oil and gas producing provinces. These emissions, which occur both intentionally and accidentally, can be reduced at relatively minimal cost. Capturing methane means capturing natural gas, a valuable economic commodity. A study commissioned by EDF showed that a 75% reduction in these emissions, generated through federal regulations, could conserve enough energy to power nearly 800,000 homes in a year.
In December 2025, the federal government finalized regulations estimated to reduce methane emissions by 72%. Doing so would equate to taking approximately 70 million gas-powered cars off the streets for one year.
However, once new rules are passed at the federal level, provinces have a chance to create their own standards to achieve comparable reductions but designed to suit their unique conditions. British Columbia has already passed regulations targeting a 75% reduction by 2030. In contrast, Alberta has proposed rules that are estimated to be roughly 80% less effective than the federal standard.
The federal government has the power to approve Alberta’s rules only if they are deemed to deliver the same outcome as Ottawa’s recently passed standards. The Carney government now faces a clear choice. Give Alberta special treatment and risk business as usual for climate, or require the province to develop equally robust rules and help Canada pull the emergency brake on methane pollution.
By: Adam Peltz and Meg Coleman
Pennsylvania has been drilling oil and gas wells for more than 160 years. But generations of development have left the Commonwealth with 30,000 documented and potentially as many as 300,000 undocumented orphan wells.
New research sponsored by Environmental Defense Fund and led by Jade Boutot of McGill University shows how emerging technology could help change that.
Multi-technology Detection of Undocumented Orphaned Oil and Gas Wells: A Large-Scale Drone and Ground-Based Survey in Pennsylvania used drones, magnetic sensors, methane detection technology and boots-on-the-ground field investigations to search for undocumented oil and gas wells. The results demonstrate how pairing remote-sensing technologies with targeted field investigations can help find wells that have effectively disappeared from the historical record.
The findings point toward a potentially powerful new approach for addressing one of Pennsylvania’s oldest environmental challenges: before we can assess and plug the wells left behind by generations of oil and gas development, we have to find them. In the meantime, these old, leaky wells can emit oil, gas and other toxic chemicals into the groundwater, soil and air.
Pennsylvania’s long history as an oil and gas producing state means that many wells were drilled decades before modern recordkeeping, permitting and location technologies existed.
Finding undocumented wells there can be challenging, as they can require the piecing together of old records, maps and other evidence, coupled with the verification of their existence in the field.
That can be especially difficult in the state’s rugged and heavily forested landscape. Old wells may be hidden by vegetation, located far from roads or trails, or have little visible infrastructure remaining above ground.
So the team, which also included researchers and experts from the Pennsylvania Department of Environmental Protection (DEP), Lawrence Berkeley National Laboratory, National Energy Technology Laboratory, Los Alamos National Laboratory and Sawback Technologies, looked for them from the air. This work is part of a broader effort at EDF to pilot new methods of finding and remitting orphan and abandoned wells.
First the team used drone-based magnetometer surveys to look for signs of hidden oil and gas wells. The equipment detected magnetic signals that could point to buried metal well casing or other underground infrastructure, rather than relying only on what was visible from the air.
Field checks confirmed that some of the locations identified by the surveys were oil and gas wells, including wells that had not been previously documented.
That finding highlights one of the most promising aspects of the research:. A well doesn’t necessarily stop being a potential environmental concern simply because its infrastructure can no longer be seen from the surface. Technologies capable of identifying buried well infrastructure could help locate wells that sight inspections might miss.
Pennsylvania’s orphaned and abandoned well problem was created more than a century ago. And it’s certainly not the only state facing this challenge. Undocumented orphan wells are problem anywhere in the U.S. that experienced early oil and gas development, especially Appalachia, the southern mid-continent and Southern California.
While solving the challenge will take time, this research shows how better technology can make that work smarter.
The study also demonstrates why locating undocumented wells should remain an important part of the country’s broader orphaned well strategy. Finding additional wells means states can build a more complete picture and make better decisions about which sites warrant further investigation and, ultimately, plugging.
Drone magnetometers won’t eliminate the need for boots on the ground. But this study has demonstrated how these technologies can work together to narrow the search area, identify previously undocumented wells and provide better information about where to focus limited resources.
By Lily Dell, EDF Legal and Regulatory Intern
For many Americans, keeping the lights on and paying the electric bill have become growing concerns. The average U.S. household is expected to pay about $197 a month for electricity this summer, up 6% from last year. At the same time, extreme heat and rising electricity demand are straining parts of the power grid.
Time-of-use electricity rates can help address both challenges. These rates charge customers less for electricity during off-peak hours, when demand is lower, and more when demand is highest. By encouraging customers to shift when they use electricity, well-designed TOU rates can lower bills, reduce strain on the grid and support clean energy.
That said, not everyone can easily change when they use electricity. Customers who rely on 24-hour medical equipment, work fixed schedules conflicting with off-peak hours or otherwise lack flexibility may end up paying more under a TOU rate. As more utilities propose these rates, strong consumer protections are essential to ensure TOU programs deliver benefits without leaving vulnerable customers behind.
TOU programs also differ in how customers enroll. Some jurisdictions allow customers to opt in, while others transition customers to a TOU rate by default. Both approaches should include customer protections, but these safeguards are especially important for default rates so automatically enrolled customers retain meaningful choice.
EDF has championed TOU rates for more than a decade because, when designed well, they can lower electricity costs, reduce peak demand and support a cleaner, more reliable grid. As far back as 2013, EDF advocated for TOU rates while emphasizing the importance of customer choice. As TOU rates become more common, getting the details right is more important than ever.
Early education is essential
Customer education is key to a successful TOU rate. Customers need clear, accessible information about how TOU rates work, how prices vary throughout the day and personalized strategies to lower their bills. This education should begin long before customers transition to a TOU rate, giving them time to learn and adapt and reducing the risk unexpectedly high bills. Effective education helps the rate work as intended and gives customers greater power to lower their bills.
Shadow billing helps customers prepare
Shadow billing can be one of a utility’s most valuable tools for successfully implementing a TOU rate, providing both customer protection and education. A customer receives an alternate “shadow bill” for several months that compares their current bill with what they would pay under a TOU rate. This personalized information helps customers become familiar with the TOU rate, identify opportunities to save money by changing their behavior and better understand utility billing, which can strengthen trust.
In Massachusetts, Groton Electric Municipal Light Plant used shadow billing as part of a TOU rate pilot. A subsequent case study from American Public Power showed that this method contributed meaningfully to reductions in peak electricity usage. In California, utilities must provide shadow bill comparisons for at least a year before transitioning a customer to a TOU rate and continue providing them while the customer remains on the rate. This gives customers advance information on how their bill can change so they can make informed decisions about their electricity use.
Bill stabilization helps protect customers as they adjust
Bill stabilization helps protect customers from paying more under a TOU rate than they would have on their standard rate plan. During California’s statewide TOU transition beginning in 2019, the state required utilities to stabilize customers’ bills for 12 months. Utilities automatically calculated whether each customer was saving money or paying more under the TOU rate. Customers who paid more received a credit for the difference. This approach gave customers time to adapt their household electricity use while eliminating the financial risk of trying a new rate.
Post-implementation shadow billing can reinforce this protection. By showing customers what they would have paid under the standard rate, utilities give them the information they need to decide whether to remain on the TOU rate or switch back.
Not every customer can shift their electricity use
TOU rates are designed for customers who can shift when they use much of their daily electricity, but that flexibility is not universal. Some states exclude certain customer classes from the default rate. California exempts many vulnerable customer classes, including certain low-income households, customers with medical needs and older adults, from automatic enrollment.
Choice builds trust
Customers should maintain control of their electricity plan. TOU rate programs should provide a clear and guaranteed way to opt out without enrollment fees or cancellation penalties. Customers should be able to opt out online, on paper or by phone.
Research conducted for the Massachusetts Attorney General’s Office reinforced the importance of this “choice builds trust” principle. Customer outreach found that people wanted utilities to preserve agency, choice and control when changing how they are charged for electricity. Meaningful choice is especially important when customers must navigate a new and unfamiliar rate. If customers know they can leave without financial consequences, they have greater freedom to try a TOU rate and determine whether it works for their household.
TOU rates should work for everyone
As states expand TOU rates, they should measure success not only by the impacts on the electric grid and customers’ bills, but also by how well customers understand their rates, whether they believe the rates benefit them and whether they are adequately protected.
The strongest TOU programs recognize the importance of all these factors. EDF advocates for TOU programs that work for all customers and encourages individuals, utilities and other stakeholders to support customer choice and protections.
In the Governor’s updated Regulatory Agenda, published in the July 25, 2026 Pennsylvania Bulletin, the Pennsylvania Department of Environmental Protection proposed two rulemakings to regulate methane emissions from new and existing sources at conventional and unconventional oil and gas well sites.
Then at the August 6, 2026, Air Quality Technical Advisory Committee meeting, DEP outlined their approach and proposed to submit draft rules utilizing their authority under the Air Pollution Control Act to the Environmental Quality Board in 2027.
Governor Shapiro’s administration listened to overwhelming public support for durable methane protections while considering permit updates last summer. They took the important next step for Pennsylvania, directing the Commonwealth to move forward with rules that cut methane pollution from oil and gas, modeled on federal existing source standards known as OOOOc. That is leadership. The significance of these rules should not be overlooked. The nation’s second-largest natural gas producer is now moving forward with comprehensive regulations to reduce methane. As Washington retreats from federal methane protections, Pennsylvania is moving forward, and the Governor deserves our thanks for this leadership.
Now the task remains to get it right, because a methane rule only delivers if it covers every source of the problem.
Pennsylvania has long been at the center of America’s energy economy. What we do here doesn’t just affect our own communities. It shapes markets, jobs, and energy policy across the country. That’s why the conversation around methane emissions matters so much.
Industry groups, policymakers, and advocates all acknowledge that methane is both a valuable energy resource and a pollutant that should be addressed. In an April 21, 2026, House Natural Resources methane hearing, stakeholders agreed that Pennsylvania should do so through a state rulemaking.
That’s an important place to start.
The question facing Pennsylvania is no longer whether to act, but whether the eventual rules will reflect the full environmental, economic and scientific picture – or leave significant sources of pollution unaddressed.
Methane is the primary component of natural gas, and the very product Pennsylvania produces more of than any state except Texas. When methane leaks, it isn’t just pollution. It’s wasted energy.
In 2023 alone, Pennsylvania’s oil and gas sector emitted:
If market incentives alone were enough to prevent methane loss, we would not be wasting this much product every year. The scale of that waste makes one thing clear: voluntary efforts, while valuable, are not enough on their own.
There’s a competitive dimension, too. Buyers are demanding cleaner sources of energy, and the European Union’s new import rules will require measurement and verification of the emissions tied to the gas it buys by 2029. Importers will need to meet a set methane intensity (or methane loss rate) standard by 2030.
Producers that can document low-emission output will have the advantage. Those that cannot may face growing commercial and regulatory risk. Clear, statewide standards give Pennsylvania operators the certainty and the credentials to compete, turning strong methane performance into a market asset rather than a liability.
As demand for Pennsylvania gas grows – from LNG exports to manufacturing and new data center development – the question is not simply how much energy the Commonwealth will produce. The question is whether that production will be managed responsibly and competitively.
The Appalachian Basin has among the lowest methane intensity or loss rates in the country. That broad statement leaves out important differences among operators and well types.
A recent study by the Appalachian Methane Initiative (AMI) offers a fuller picture of methane emissions in the Appalachian Basin based on real-world measurement data.
Here are a few key findings:
This tracks with earlier work by EDF scientists on the outsized role of low-producing well sites. EDF estimates that about half of all emissions in Pennsylvania are from low-producing well sites that contribute just 1% of total production.
Some operations perform extremely well, while others do not. Top-performing operators have already shown that low-emissions production is possible. However, the basin’s overall methane performance is undermined by approximately 175,000 low-producing well sites – including more than 73,500 in Pennsylvania—that contribute disproportionately to methane pollution. Ignoring that reality would risk designing policy around the industry’s best performers while leaving a significant share of emissions unaddressed.
This is why the details of the Pennsylvania rules will matter so much. To deliver real, meaningful reductions, they need to cover all sources, including low-producing, conventional well sites.
That runs against a familiar argument: that regulation will put small, independent “mom and pop” operators out of business. Legitimate operational realities deserve a real answer, and flexibility can and should be built in to protect truly small operators. Nearly $1 billion in Methane Emission Reduction Program grants, much of which target low-producing well sites, are moving forward that can offer assistance.
Flexibility should be targeted since most Pennsylvania’s low-producing well sites are owned by larger oil and gas corporations.
Here in Pennsylvania, just 11 oil and gas corporations owned nearly half, 49%, of all low-producing well sites in Pennsylvania with portfolios of more than 1,000 low-producing well sites and generated $2.7 million to $298 million in revenue.
Just over 100 oil and gas corporations owned nearly 90% of all low-producing well sites with portfolios of 100 low-producing well sites or more. Operators with portfolios of 100-200 low-producing well sites generated an average of $2.7 million of revenue.
Just 3.6% of sites are owned by operators with 30 or fewer well sites with an average revenue of $472,000.
Pennsylvania should address the genuine challenges facing a discreet subset of operators without allowing those challenges to become a shield against action across the entire sector.
The industry has the capacity to address this problem and cut a substantial share of emissions.
The 2024 U.S. EPA methane rule built in flexibility such as allowing well sites near the end of their useful life to forgo equipment upgrades.
Emissions-reduction requirements should focus on the sources responsible for the greatest pollution. Flexibility can and should be built into the rule to minimize costs for truly small operators.
There is also a smarter path for the lowest-producing well sites, where emissions are disproportionately high, production is minimal, and the economics often do not support long-term operation. Rather than allowing pollution in perpetuity, the state should prioritize these well sites for plugging and remediation, cutting emissions at the source while preventing future orphaned well sites and taxpayer liability.
The data points toward a clear, workable approach. A smart methane policy should:
Often, stakeholders do not begin with a shared premise, but here we do. We agree on three things: methane emissions must be reduced, solutions exist and policy should be practical.
Governor Shapiro has taken the first step, and both he and DEP Secretary Jessica Shirley have our thanks for it.
The work ahead is to carry that commitment through a lengthy rulemaking process and ensure the final standards reflect reality. That means covering the major sources of pollution, supporting DEP in designing solutions that match the problem and avoiding broad exemptions that would leave significant emissions unaddressed.
Pennsylvania has the tools, the data, and now the momentum to lead.
As the nation’s second-largest natural gas producer, Pennsylvania now has an opportunity to demonstrate that energy leadership and methane accountability can go hand in hand. Governor Shapiro and Secretary Shirley should continue to carry this process forward with strong and commonsense rules that reduce waste, protect communities, and strengthen the Commonwealth’s energy economy.
The work has just begun. Now we roll up our sleeves to get the job done.
July announcements included new heavy-duty pilot projects around the Tesla Semi, progress on electric corridor between Texas and Mexico and additional cold-climate buses being put into service in Minnesota.
Medium- and heavy-duty electric vehicles are hitting the road in 2026, and we’ve collected last month’s most exciting news. In 2025, EDF delivered monthly deployment updates on the biggest zero-emission transportation stories. By the end of 2025, it was clear that momentum was sustained throughout a challenging year. This year will undoubtably see more big announcements, and we’ll be here to showcase the biggest orders and deployments of zero-emission trucks happening around the country.
DSV deploys 10 Windrose electric Class 8 trucks, in step towards cross-border electric freight between the U.S. and Mexico
DSV, a global transportation firm, is set to deploy 10 new Windrose Class 8 electric trucks in collaboration with Allogic and Greenspace E-Mobility. The trucks will operate between distribution centers in Loredo and Dallas, Texas. Greenspace E-Mobility, acting as Windrose’s strategic infrastructure partner across South Texas and Mexico, is building a network of dedicated charging hubs along the route.
Paper Transport begins Tesla Semi pilot
Paper Transport announced they are evaluating a Tesla Semi for daily freight operations in the Chicago area. The company is testing the long-range truck within their dedicated operating model, with predictable routes and consistent mileage to evaluate performance compared to diesel models. The Tesla Semi has seen an uptick in adoption and new pilot projects since it entered mass production earlier in 2026, with many fleets testing the vehicle in their operations.
Duluth Transit Authority expands electric bus fleet with two GILLIG vehicles
The Duluth Transit Authority in Duluth, Minnesota has deployed two new electric buses, manufactured by GILLIG, for passenger service. The transit authority first started introducing electric buses into their operations in 2018 and continues to build on the zero-emission fleet. The buses were purchased with remaining funds from a previous Federal Transit Authority grant awarded to the city.
Now is a critical time for fleets to invest in medium- and heavy-duty electric trucks. These vehicles improve public health and help combat the climate crisis by reducing greenhouse gas emissions and air pollution. Unlike traditional diesel-powered trucks, electric trucks produce no tailpipe emissions, which significantly cuts down on health-harming pollution. Adoption represents a key step toward a more sustainable and resilient transportation industry.
Check back here next month to see a collection of the most exciting zero-emission vehicle announcements from August. In the meantime, check out EDF’s Electric Fleet Deployment & Commitment List to track announcements as they happen in real time, and view all July announcements.
Check out last month’s announcements here.
Louisiana families and businesses deserve an electric system that is reliable, affordable and prepared for a rapidly changing future. They also deserve confidence that when utilities ask customers to pay billions of dollars for new power plants, those investments truly represent the best available option.
That is the central issue before the Louisiana Public Service Commission as it considers Entergy Louisiana’s request to build two new gas-fired power plants, Waterford 6 and Westlake, at an estimated cost of $4.1 billion. If approved, the projects could add nearly $15 a month to the average residential customer’s electric bill, with those costs ultimately recovered through customer rates.
In testimony filed on behalf of Environmental Defense Fund with the Louisiana Public Service Commission, energy planning expert Dr. Maria Roumpani concludes that Entergy has not demonstrated these plants are the lowest-cost, lowest-risk option for customers and that regulators should require a more rigorous evaluation before committing ratepayers to decades of costs.
Why this matters
Louisiana is experiencing one of the fastest periods of projected electricity demand growth in its history, driven by major industrial development. Meeting that demand will require significant investment, but regulators must ensure utilities invest in resources that are the lowest-cost, lowest-risk option and continue to deliver value for customers if conditions change, including load forecasts, commodity prices or policy constraints. The Commission must also evaluate these proposed plants in the context of Louisiana’s broader electricity system and the additional infrastructure and generation being planned to support future industrial growth, including data centers.
No one disputes that Louisiana needs reliable electricity to support a growing economy. The question is whether building two large gas plants now is the smartest way to deliver it. Once customers begin paying for these facilities, they could be responsible for their costs for decades, making today’s decisions critical for the future of customer bills, fuel reliance and grid reliability.
Main reasons for concern
First, Entergy has not demonstrated that Louisiana needs two new gas plants of this size. The testimony finds that the company’s demand forecasts rely heavily on projected large industrial customers without adequately accounting for uncertainty, changing customer plans or the possibility that some projects never materialize. For example, if one or more of the largest proposed industrial projects are delayed, reduced in scope or never built, one of the proposed generators may no longer be needed, yet customers could still be on the hook for its costs. The company also has not committed to retirement dates for aging power plants or completed analyses showing these new facilities are the best replacement option.
Second, Entergy did not adequately evaluate whether more incremental, cost-effective solutions could meet Louisiana’s growing electricity needs. Rather than asking which combination of resources would best meet future demand, Entergy largely compared different gas plant proposals with one another. That means alternatives like energy efficiency, demand response, solar power, battery storage, transmission upgrades and customer-owned energy resources were never fully evaluated alongside the new proposed fossil fuel plants.
Third, the economic case is weaker than it appears. Entergy’s economic analysis relies on assumptions that have not been sufficiently supported. The testimony finds that the projected benefits depend on assumptions about costs and future demand that may not hold. A modest increase in project costs or a likely shortfall in projected load growth could erase the projected savings altogether, leaving customers to bear the costs without receiving the promised benefits.
Finally, the proposal shifts substantial risk onto customers. If construction costs increase, fuel prices rise, or anticipated industrial demand fails to materialize, Louisiana ratepayers could remain responsible for paying for infrastructure they may not need. They would also face decades of exposure to natural gas price volatility because fuel costs are passed directly through on electric bills. Louisianans have already seen what those price swings can mean. Between October 2025 and February 2026, higher natural gas prices added about $16 to the monthly bill of a household using 1,000 kilowatt-hours of electricity.
A smarter path to affordable growth
As Louisiana plans for future electricity demand, EDF recommends evaluating more incremental, cost-effective solutions before committing customers to major new gas generation. That broader portfolio includes energy efficiency, demand response, customer-owned resources like rooftop solar and battery storage, transmission improvements, grid-enhancing technologies, and incremental utility-scale solar and battery storage. Together, these resources can improve reliability, meet growing demand and reduce the need for costly new power plants.
Together, these resources can improve reliability, meet growing demand and reduce the need for costly, customer-funded gas investments. With important regional transmission studies already underway, it’s worth waiting for more information and evaluating additional technologies that could improve reliability while reducing costs before committing customers to major new generating facilities.
What we recommend
EDF recommends that the Commission deny certification of both plants at this time. Before reconsidering the proposal, the Commission should require Entergy to:
Building the right grid for Louisianans
Louisiana’s economy is changing rapidly, and the electric grid must evolve with it. But planning for growth should not mean assuming that expensive investments automatically deliver better outcomes. Before asking customers to pay billions of dollars for new infrastructure, regulators should require utilities to demonstrate that those investments are the most cost-effective way to meet the state’s growing energy needs.
The Commission has an opportunity to require utilities to compare competing solutions, evaluate customer risks and pursue the most cost-effective path forward. With billions of customer dollars at stake, regulators should insist on a thorough evaluation of all viable alternatives before asking Louisianans to pay for decades to come.
