Energy companies have left Colorado with billions of dollars in oil and gas cleanup

As the state tries to reform its relationship to drilling, an expensive task awaits.

Nick BowlinImage credit: Helen H. Richardson/The Denver Post via Getty ImagesMarch 11, 2021From the print edition

When an oil or gas well reaches the end of its lifespan, it must be plugged. If it isn’t, the well might leak toxic chemicals into groundwater and spew methane, carbon dioxide and other pollutants into the atmosphere for years on end.

But plugging a well is no simple task: Cement must be pumped down into it to block the opening, and the tubes connecting it to tanks or pipelines must be removed, along with all the other onsite equipment. Then the top of the well has to be chopped off near the surface and plugged again, and the area around the rig must be cleaned up.

There are nearly 60,000 unplugged wells in Colorado in need of this treatment — each costing $140,000 on average, according to the Carbon Tracker, a climate think tank, in a new report that analyzes oil and gas permitting data. Plugging this many wells will cost a lot —more than $8 billion, the report found.

Companies that drill wells in Colorado are legally required to pay for plugging them. They must also put forward financial assurances in the form of bonds, which the state can call on to pay for the plugging. These bonds are meant to incentivize cleanup and to protect the state, in case a company is unable to pay. But as it stands today, Colorado has only about $185 million in bonds from industry — just 2% of the estimated cleanup bill, according to the new study. The Colorado Oil and Gas Conservation Commission (COGCC) assumes an average cost of $82,500 per well — lower than the Carbon Tracker’s figure, which factors in issues like well depth. But even using the state’s more conservative number, the overall cleanup would cost nearly $5 billion, of which the money currently available from energy companies would cover less than 5%.

This situation is the product of more than 150 years of energy extraction. Now, with the oil and gas industry looking less robust every year and reeling in the wake of the pandemic, the state of Colorado and its people could be on the hook for billions in cleanup costs. Meanwhile, unplugged wells persist as environmental hazards. This spring, Colorado will try to tackle the problem; state energy regulators have been tasked with reforming the policies governing well cleanup and financial commitments from industry.

“The system has put the state at risk, and it needs to change,” said Josh Joswick, an organizer with the environmental group Earthworks. “Now we have a government that wants to do something about it.”

Data not collected for Texas’ clean up funds.Source: Carbon Tracker Initiative Data visualization: Luna Anna Archey/High Country News

THE FIRST WESTERN OIL WELL broke ground in Colorado in 1860. Drilling has been an important part of the state’s economy ever since; as of 2019, Colorado ranked in the sixth and seventh in the nation for oil and natural gas production, respectively.

When it comes to cleanup, Colorado uses a tiered system known as blanket bonding. Small operators can pay ahead with bonds on single wells. Drillers with more than 100 wells statewide pay a fixed reclamation fee of $100,000, regardless of the number of wells. A similar system also applies to wells on federal public land in the state. Large companies pay a single $150,000 bond, which covers unlimited federal public land wells throughout the country. There are about 7,400 public-land wells capable of producing oil or gas in Colorado, according to the Bureau of Land Management.

When a driller walks away or cannot pay for cleanup, the well enters the state’s Orphan Well Program, which works to identify and plug these wells. There are about 200 wells in the program right now, according to the state. But a closer look at state data reveals a large number of wells at risk. Nearly half of the state’s unplugged wells are stripper wells — low-producing operations with small profit margins often at the end of their lifespans. These wells are particularly vulnerable to shifts in oil prices. That means they change hands often. “This is a common tactic in the oil and gas industry: Spinning off liabilities to progressively weaker companies, until the final owner goes bankrupt and none of the previous owners are on the hook for cleanup,” said Clark Williams-Derry, a finance analyst with the Institute for Energy Economics and Financial Analysis.

“This is a common tactic in the oil and gas industry: Spinning off liabilities to progressively weaker companies, until the final owner goes bankrupt and none of the previous owners are on the hook for cleanup.” 

There are also inactive wells: Nearly 10% of the state’s wells have not produced oil or gas in at least two years, according to a Carbon Tracker analysis of state permitting data. Unlike some of the neighboring oil states, Colorado requires that companies pay a single bond on each inactive well of this sort. This costs either $10,000 or $20,000, depending on the depth of the well. In theory, these payments protect the state, in case the well owner goes bankrupt. But in Colorado, it’s still far cheaper for energy companies to pay the cost of that single, unused well — and the small annual premium payments on the bond — than to actually plug it. “Colorado clearly makes it cheaper to idle a well than to clean it up,” Williams-Derry said. 

In Colorado, just two companies are responsible for nearly 70% of the bonds for currently inactive wells. One is Noble Energy Inc., which was purchased by the global oil giant Chevron in October 2020. The other is Kerr-McGee, a subsidiary of Occidental Petroleum. Kerr-McGee was responsible for the 2017 home explosion in Firestone, Colorado, that killed two people. Last year, the COGCC fined the company more than $18 million for the accident, by far the largest fine in state history. Both companies still own large numbers of wells in the Denver-Julesburg Basin, the prolific oil and gas formation beneath central and eastern Colorado. And the mass desertion of wells is not hypothetical: In fall of 2019, a small company called Petroshare Corporation went bankrupt and left about 90 wells for the state to cleanup. That alone will cost Colorado millions of dollars. Last summer, when California’s largest oil driller filed for Chapter 11 bankruptcy protection, it left billions in debt and more than 17,000 unplugged wells.

The oil and gas industry is already mired in a years-long decline that raises doubts about its ability to meet cleanup costs. In six out of the past seven years, energy has been either the worst- or second-worst-performing sector on the S&P 500. And the economic fallout from COVID-19 has only accelerated the decline. Oil prices hit record lows in 2020. The industry’s debt approached record levels, and thousands of oilfield workers lost their jobs, Colorado Public Radio reported. Many companies went bankrupt, including 12 drilling companies and six oilfield service companies in Colorado, according to Haynes and Boone LLP, a law firm that tracks industry trends.

Oil and gas development on the Roan Plateau near Grand Junction, Colorado.Helen H. Richardson/The Denver Post via Getty Images

IN 2019, A NEW LAW completely overhauled the state’s relationship to oil and gas. This spring, Colorado oil and gas regulators are tasked with reforming the financial requirements for well plugging. It’s a big deal, especially in an oil state like Colorado: The law gives local governments more control over oil and gas development, and it rewrote the mission of the COGCC, the state’s energy regulator. The COGCC has subsequently banned the burning off or releasing of natural gas, a routine drilling practice, and instituted a broad range of wildlife and public health protection policies. Recently, it voted for the nation’s largest setback rule, which requires oil and gas operations to stay at least 2,000 feet from homes and schools.

The deep divide between the true cost of cleanup and what industry has so far ponied up is not news to Colorado regulators. In a 2017 letter to lawmakers, the COGCC estimated that the average costs of plugging wells and cleaning up the drilling site “exceed available financial assurance by a factor of fourteen.” With this new rulemaking process, Colorado has a chance to make up this gap.

How to handle this looming liability remains an open question, said John Messner, a COGCC Commissioner. The rulemaking process is still in its early stages and will take months. The commission is asking stakeholders of all kinds — industry, local governments, environmental groups and more — to submit suggestions and opinions to the commission. There are several different methods for how best to reform the process, Messner said. That might involve leaving the current structure in place, while increasing the bond amounts, including on individual well bonds. It might mean a revamped tiered system, where more prolific producers pay more, or a different fee structure based on the number of drilled wells. Messner mentioned the option of a bond pool, where companies pay into a communal cleanup fund and, at least in theory, provide industry-wide insurance to guard against companies defaulting on cleanup obligations. Messner stressed that no formal decisions have been made and that the final rule could involve some combination of these and other tools.

“Regulatory changes in the past two years alone are costing oil and gas businesses an extra $200 million a year.”

I asked Messner about balancing the pressing need to increase cleanup requirements with the possibility of companies walking away from their wells if the cost to operate in Colorado spikes. “It’s a real risk,” Messner said. The Colorado Oil and Gas Association expressed a similar concern in an email to HCN.

“When it comes to financial assurance for current or future wells, we need to ensure that the potential solution doesn’t create an even bigger problem by raising the cost of doing business in Colorado for small businesses,” said COGA President Dan Haley in a statement. “Regulatory changes in the past two years alone are costing oil and gas businesses an extra $200 million a year. For our state to stay competitive, regulators and lawmakers need to be cognizant of that growing tally and the rising cost of doing business.”

But as it stands today, oil and gas companies aren’t realistically paying anywhere near the true cost of cleaning up their drilling sites. And with the industry’s murky financial future, experts predict more and more sales of risky wells to less-wealthy operators, until the state could end stuck with the final cost.

“It’s like a game of hot potato,” Williams-Derry said, “except that when the potato goes off, it’s the public who loses.”

Note: This story has been updated to clarify that bonds are not the only way that oil and gas companies pay for reclamation.

Nick Bowlin is a contributing editor at High Country News. Email him at


Oil and gas companies are making old pipelines the landowner’s problem

In the US, private residents end up footing the bill to prevent further eyesores and pollution.Kate Wheeling/Nexus MediaMarch 10, 2021

A gas pipeline under construction in a clear-cut strip of forest
A new gas pipeline undergoes construction in Pennsylvania.Max Phillips (Jeremy Buckingham MLC)

Kate Wheeling writes for Nexus Media. You can follow her @KateWheeling. This article originally featured on Nexus Media, a nonprofit climate change news service.

Some years ago, David Howell got a call from a landowner in Central Texas who had 300 feet of an old oil pipeline buried under his property. It was clearly no longer in use. The area around the pipeline was overgrown and the signage had faded or fallen away. The landowner wanted to build there now, and was wondering if Howell could come remove it.

Howell, who owns a pipeline salvage business, thought he could do the work for as little as $1,000. There was no clause in the landowner’s agreement with the pipeline company regarding abandonment, so the company had no responsibility to remove the pipeline. But the landowner nevertheless needed the pipeline company’s permission, as the company still owned the line. The company acquiesced, but it insisted that the landowner use a contractor of its choosing, who was quoting the work at $50,000. The landowner ultimately sold the property rather than deal with the pipeline.

“I get a call a week from some landowner who says, ‘I got an abandoned pipeline, can you come take it out?’” Howell said. “Basically [pipeline workers] are putting a pipeline on some schmuck’s property and leaving it there, and that’s happening all over the United States. Hundreds of thousands of miles of pipeline have been just abandoned on peoples’ property.”

It’s a familiar story for Howell, who has been salvaging and recycling abandoned pipelines for more than 20 years, and it’s one that could become increasingly common as renewables outcompete oil and—in particular—natural gas pipelines age out of service.

There are some 3 million miles of natural gas pipelines buried in the US, shuttling the fuel between drilling sites, storage facilities, power plants, and homes. More than half of all gas transmission lines in the country were installed before 1970, according to data from the Pipeline and Hazardous Material Safety Administration. Those pipelines have an average lifespan of 50 years.

And it’s not just old pipelines that are set to go out of service. Younger pipelines are also at risk of falling into disuse as the power sector comes to rely less on natural gas in favor of wind, solar and batteries. Not so long ago, natural gas was heralded as a bridge from fossil fuels to renewables. No clearer sign exists that that bridge has been crossed than the cancellation of several high profile natural gas pipeline projects in the last year, including the Atlantic Coast Pipeline and the Constitution Pipeline. What does that mean for the millions of miles of gas pipelines that are already in the ground?

Protesters in New York holding up signs that say protect NY water and stop Constitution Pipeline
Environmental groups rallied in New York against the Constitution Pipeline.Erik McGregor/ND

The most comprehensive data on abandoned pipelines comes from Canada. In the 1980s, the Canadian government began an extensive study of abandoned pipelines, which identified a slew of serious risks to leaving them in place. Sinkholes could form as pipelines corroded and collapsed. Leftover fossil fuels, or the cleaning agents used to clear out lines, could leak out into the surrounding soil or water. Aging lines under lakes or rivers could carry water where it’s not wanted.

“A 36-inch abandoned pipeline could drain an entire lake in relatively short order and send it someplace else, and the downhill folks probably wouldn’t appreciate having a lake dumped into their backyard,” says Paul Blackburn, a staff attorney for the nonprofit Honor the Earth, who has also represented rural landowners in the fight against the Keystone XL pipeline.

Empty pipelines could also become slightly buoyant, relative to soil, and rise to the surface, where landscaping and signage marking a pipeline’s path is rarely maintained after it has been retired.

“Let’s say a pipeline goes into the ground 60 years ago, and the land was passed down through generations, and by the time it gets to somebody’s great grandkid the story of the pipeline getting put in the ground is lost,” says Jane Kleeb, the founder of Bold Nebraska, a citizen’s group that fought against the Keystone XL pipeline. “Then the soil starts to erode, as it does everywhere, and then you ruin a tractor because you hit a big piece of pipeline.”

In Howell’s experience, this is how many old lines are discovered. Workers operating a tractor or an excavator while installing a drainage tile, a house foundation, or a new pipeline, perhaps, come upon an abandoned line. Sometimes, abandoned lines contain hidden surprises.

“You don’t always know what’s in them and what’s not,” Howell says. “The previous owner might have said it’s empty, and then we tap into it and find out that there’s still gas pressure, or liquified gas spews out. So we learned how to be very careful.”

In 2017, gas leaking from an abandoned gas pipeline ignited, causing an explosion in a Colorado home that left two dead and one seriously injured. Investigators later discovered the line was still connected to a nearby gas well.

Faced with such risks, the Canadian government set up a system that requires pipeline companies to estimate the cost of removing pipelines that are no longer in use, or cleaning up sites where pipelines have been left in place, and set aside money to do it. In the US, companies need to show that abandoning a pipeline won’t leave an area without the fuel it needs, but they don’t have to prepare for its retirement or removal.

Gas pipeline worker in a white hard hat in tall grasses
Workers prepare to dismantle an abandoned pipeline near Lubbock, Texas.David Howell

The Federal Energy Regulatory Commission (FERC) can order a pipeline company to remove a line that’s not in use, says Carolyn Elefant, an energy and eminent domain attorney, but it doesn’t always do so.

“But just because they have the authority, doesn’t mean they have to exercise it,” she says.

According to FERC, decisions about pipeline removal are “made on a case-by-case basis.”

There are few federal or state rules governing pipeline abandonment. Companies do not even have to notify landowners when a pipeline beneath their land is abandoned. In an informational pamphlet for landowners on FERC’s website, the commission states only that landowners will “probably” be notified by pipeline companies if a line is abandoned.

Whether a pipeline is removed or abandoned may come down to the terms of the easement—the agreement between a landowner and a pipeline company. But Howell estimates that in 95 percent of the easements he’s seen, the agreements don’t lay out what happens when the pipeline is no longer in use.

Pipeline companies have ample incentive to leave pipelines in the ground. Removal is expensive and requires heavy equipment, permits and environmental reviews. And pipelines laid before 1980 often have the added feature of an asbestos coating that must be dealt with.

“It costs almost as much to get a pipeline out of the ground as it costs to put it in the ground,” Blackburn says.

Kleeb believes that, like Canadian regulators, US regulators should require pipeline companies to have plans to decommission pipelines and have bonds in place to pay for their removal, so that if companies go bankrupt, landowners aren’t stuck with the costs of removal. The Interstate Natural Gas Association of America, a pipeline company trade group, declined to comment on this proposal.

For now, many landowners are facing the risks of abandoned pipelines on their own.

When TransCanada, now TC Energy, first approached Julia Trigg Crawford about building part of the Keystone pipeline under her land in East Texas, she was thinking about her creek. The proposed route ran underneath the waterway, which she uses to irrigate her 500 acres of corn and soybeans. The pipeline would pose a threat to her farm both while in use and at the end of its life.

“I was so new to this whole pipeline thing,” she said. “I was thinking, how do I protect my land? How do I protect my water?”

She was reluctant to sell, though, ultimately, she didn’t have a say in the matter. The company took her land using eminent domain, and the condemnation paperwork she received was silent on abandonment.


Some Fracking Companies Are Admitting Shale Was a Bad Bet — Others Are Not

Read time: 10 mins

By Justin Mikulka • Friday, March 5, 2021 – 09:00

Permian basin pumpjack

Energy companies are increasingly having to face the unprofitable reality of fracking, and some executives are now starting to admit that publicly. But the question is whether the industry will listen — or continue to gamble with shale gas and oil.

In February, Equinor CEO Anders Opedal had a brutally honest assessment of the Norwegian energy company’s foray into U.S. shale. “We should not have made these investments,” Opedal told Bloomberg. After losing billions of dollars, Equinor announced last month that it’s cutting its losses and walking away from its major shale investments in the Bakken region of North Dakota.

Meanwhile, at CERAweek, the oil and gas industry’s top annual gathering held the first week of March, the CEO of Occidental Petroleum (OXY), Vicki Hollub, told attendees: “Shale will not get back to where it was in the U.S.”

“The profitability of shale,” she said, “is much more difficult than people ever realized.”

Admissions of questionable profits and the end of growth from a top CEO charts new territory for the shale industry. These comments come after a decade of fracking which has resulted in losses of hundreds of billions of dollars.

But despite the unsuccessful investments and fresh warnings, some companies continue to promise investors that the industry has finally figured out how to make profits from fracking for oil and gas. While not a new argument, these companies are offering new framing — a “fracking 4.0” if you will — focused on new innovations, future restraint, and real profits.

In February, for instance, as fracking pioneer Chesapeake Energy emerged from bankruptcy the company’s CEO Doug Lawler told Bloomberg: “What we see going forward is a new era for shale.”

Meanwhile, Enron Oil and Gas (EOG) — considered one of the best fracking companies — lost over $600 million in 2020. Despite this, the company is now touting “innovations” it has made to help create future profits along with promises of new profitable wells — part of an industry annual ritual promising new technologies and new acreage that will finally deliver profits to their investors.

This Time Will Be Different

In May 2019, Hollub oversaw one of the biggest oil and gas acquisitions in industry history when Occidental purchased Permian-based fracking company Anadarko for $57 billion. The deal was backed with $10 billion from investor Warren Buffet. The deal was a huge bet on the profitability of fracking for oil and gas in the Permian Basin’s shale.

At the same time, Houston-based energy investment group Tudor, Pickering, and Holt released an investment note begging the industry to stop producing so much oil while losing money. The firm implored the industry to not follow through on plans to increase production, saying, “Please, for the love of God, don’t do it.”

But the industry did it. And lost more money.

Following the acquisition, I wrote: “Despite the U.S. fracking industry’s history of ‘capital destruction,’ one of the top investors in the world has bet big that Occidental holds the secret to Permian profits. But perhaps this time really will be different, or perhaps Occidental will follow in the footsteps of Halcón and others who bet it all on the Permian and lost.”

And later that year, DeSmog asked: “Will the Fracking Revolution Peak Before Ever Making Money?”

All of this came a little over a year after investors had begged the industry to stop taking on debt to produce oil that it sold for a loss. This resulted in promises from the industry to do just that and an analyst telling the Wall Street Journal, “Is this time going to be different? I think yes, a little bit.”

It wasn’t different, however, and the industry borrowed more money to produce more oil and gas — and lost more money doing it.

A 2020 report by Friends of the Earth, Public Citizen, and BailoutWatch estimates that the U.S. oil and gas business borrowed another $100 billion in 2020 while Bloomberg estimates over $62 billion in new losses for U.S. shale producers last year. These losses occurred despite U.S. oil production decreasing by approximately one million barrels per day in 2020 compared to 2019. Despite the pandemic, and prices for natural gas being the lowest in decades, U.S. natural gas production only declined 1 percent in 2020.

The Stark Reality

Occidental CEO Hollub has admitted that it’s hard to make money in shale but is promising the company will do just that.

In comments in February, Hollub touted a “new model for shale development” for Occidental which is based on the idea of the company focusing on technological advances and using carbon capture to help it make profits in shale. Hollub described this new strategy as an “opportunity to mitigate what people have so much concern about with shale.”

While certainly a new approach to shale as it involves the use of direct air carbon capture — something it has been touting it would do since 2019 — it doesn’t directly address the challenge of making shale profitable. Occidental currently plans to begin construction on its carbon capture project in 2022 so it is likely to be business as usual over the next few years before it can begin to evaluate if the new model might improve the economics of fracking shale for oil. And as a January 2021 Bloomberg article noted, this approach would require “support from tax credits and outside investors to be financially viable.”

Unlike Occidental, though, others are getting out based on a similar assessment about the economics of U.S. shale production. As Equinor’s Opedal said: “The Bakken does not compete [with other available investments]… We have chosen to sell the Bakken.”

In May 2020, the Pittsburgh Post-Gazette also reported on how Shell and Chevron were selling their shale assets in Appalachia. The article stated that while oil companies had all piled into Appalachian shale in the early days, “one by one, many have left or are trying to.”

Meanwhile, some assets have no value and are just being written off as losses. In 2020, Exxon wrote off $20 billion of its assets acquired in its purchase of shale gas company XTO — the largest write down the company had ever made.

Many of those companies that have the option to get out of the U.S. shale business are choosing to do so. They know what is all too clear at this point: This time isn’t different.

‘A New Era of Shale’

One company that’s taking a different approach in order to stay in the game is Chesapeake. It’s a company built on fracking.

Unlike Equinor, which has other assets and investments, if Chesapeake chooses to get out of the fracking business, the company would be sold off and the CEO would no longer get paid. And if there is one thing shale CEOs are good at, it is getting paid huge sums while losing investor money.

It should be no surprise that Lawler, Chesapeake’s CEO, is promising a new era for shale — that this time will be different. Admitting otherwise would jeopardize his salary. Lawler even got a bonus for overseeing the company he drove into bankruptcy in 2020.

So what is different this time for Chesapeake? Lawler is claiming that the days of losing money producing oil and gas are done. “They’re absolutely over,” Lawler told Bloomberg.

Lawler’s new strategy to finally achieve profits is to focus on just fracking for gas and no longer pursuingfracking foroil. Fracking for gas is the exact business Shell left and according to Bloomberg, “many have left or are trying to.”

Yet, just a few years ago in 2019, prior to filing for bankruptcy, it was a different “new era” for Chesapeake as the company promised investors a new strategy: pivoting from gas and betting big on oil. That bet didn’t work and bankruptcy followed.

Chesapeake now wants investors to believe it will make money fracking for gas, which it admitted it couldn’t do in 2019 and was the reason for switchingto a focuson oil.

Same Story, Different Marketing

In the case of EOG, the company is pinning its hopes on technological innovation and promises of new and better performing wells. The company said it benefited from “countless innovations across the company in 2020.” Technology, however, isn’t enough to save the finances of the fracking industry and many of its past promises of technological salvation (e.g. cube development, drilling longer wells) have proven to be financial disasters.   

EOG is also promising that now it will focus on drilling and fracking “double premium” wells. These wells will be money makers, the company saysclaiming it has 10 years’ worth of these assets. In an earnings call at the end of 2020, EOG CEO Bill Thomas explained to investors that “these double-premium wells are much, much more productive.”

Image: Slide promoting EOG’s New Double Premium  Source: EOG Investor Presentation

Why Double Premium? In 2016, EOG promised investors it had premium wells that would deliver results. So this time around, it’s making bigger and better promises.

Looking Ahead

Looking ahead, 2021 may appear to be business as usual for the shale industry: Promises of restraint by some companies while others chase new production with increased drilling. New marketing pitches with new marketing language with the same promises of profits and a bright future.

In January 2021, a Reuters headline said: “OPEC crude output cuts should help U.S. shale profits in 2021.” This echoes headlines from January 2018 when the Wall Street Journal wrote: “Frackers Could Make More Money Than Ever in 2018, If They Don’t Blow It.”

The implication is that the industry was already a profitable one and that good days lie ahead. The industry, however, has always struggled and as Occidental CEO Hollub notes, U.S. shale production is likely past its peak.

The reality, however, is that it likely is a new era for U.S. shale. Companies like Equinor are getting out. Everyone knows profits are “difficult” to come by. Production is unlikely to ever return to the levels of 2019. And investigations into fraudulent claims over shale assets raise doubts as to how much oil is really in the shale.

But something else is happening too. As Hollub discussed Occidental’s future as a shale producer during CERAWeek, she said: “We do not expect to be an oil company only in the next 10 to 20 years. We expect to become a carbon management company.”

In other words,thecompany that made the biggest bet ever on the future of shale has aspirations of no longer being an oil company in the future.

A new era for U.S. shale is beginning and those who can are leaving the business to those who have no choice but to stick it out, double down, and promise that, once again, this time will be different.


A systems approach to electrifying existing buildings

By Marsha Willard

March 11, 2021

Incandescent light bulb with blue sky in background
Photo by  Luliia Tarabanova on Shutterstock.

This is surely the decade for real climate action. The Intergovernmental Panel on Climate Change (IPCC) warned that unless we achieve certain targets by 2030, we may pass the point of no return on many climate-related trends.

California has always been a leader in the United States for climate action in wide ranging sectors, including residential energy efficiencies. Building codes have grown more stringent over time, requiring new homes to be energy efficient and ready for renewable energy generation. However, that still leaves millions of existing buildings that fail to meet these new standards. Existing buildings haven’t been ignored, but multiple efforts around the state to encourage retrofitting and electrifying existing homes have been disparate and have made only incremental changes. The efforts have been laudable, but insufficient to the California goal of increasing existing buildings’ energy efficiency by 50 percent by 2030.

An urgent call for systems mapping

Late in 2020, San Mateo County’s Office of Sustainability convened dozens of Bay Area organizations to determine how best to electrify existing single-family homes, as part of the nine-county Bay Area’s transition to an energy system free of greenhouse gas emissions. The county chose Presidio Graduate School’s PGS Consults team to facilitate a systems-thinking approach to the challenge of electrifying single-family homes in the region. PGS Consults, under my direction, championed a systems-mapping methodology deploying a series of workshops and focus groups with key players.

The Bay Area Regional Energy Network (BayREN) sponsored this multi-stakeholder process to understand the context in which electrification efforts are taking place and to identify new strategies that would have the highest impact on progress with the proper coordination and attention. Stakeholder workshops included representatives from public agencies, nonprofits and private companies, and we held focus groups for contractors and homeowners. Sessions examined what is happening in the system that either supports or poses barriers to transitioning from natural gas (methane) to all-electric homes.

As Susan Wright, senior sustainability specialist at the San Mateo County Office of Sustainability, put it: “The topic of electrifying existing homes is getting a lot of attention right now, and great work is being done by a variety of organizations. We were eager to take a step back to look at the whole system to identify areas where coordinating efforts regionally could move things along faster.”

Diagram shows Home Electrification Causal Loop
Systems diagram

This causal loop diagram illustrates the cause and effect relationships among the key variables impacting the goal of electrifying home appliances and heating/cooling systems. Red arrows represent an inverse relationship (when one variable increases, the variable it affects decreases and vice versa) while blue arrows indicate a direct causal relationship (the variables both increase or decrease together). The diagram helps reveal the most impactful points of intervention. The “busiest” nodes suggest that moving the system would involve affecting costs, motivating consumers and preparing contractors. Using these results, our stakeholder group focused on the overcoming challenges in three areas: technical challenges; structural issues; and mental models.

Technical challenges to electrifying homes

We have the technology we need to solve our climate crisis; it’s just that implementing that technology poses technical challenges. While not insurmountable, these barriers are daunting enough to dramatically slow the process of switching from gas to electric in existing homes. Many older homes, for example, are insufficiently wired to handle additional, higher power (think amps and volts) mechanical systems. Even switching from a gas water heater to an electric one can trip the need for expanded electrical panels for homeowners. (Author’s note: I’m in the process of doing so in my home.)

In other cases, the costs of purchasing electric appliances such as heat pump space heaters and the wiring and venting changes needed to install them lead to more extended remodeling than initially anticipated. Homeowners we talked with were also frustrated because few contractors in the area had the combined knowledge of plumbing and electrical systems required and tended to give high bids. 

Structural issues caused by market trends and policy implementation

Addressing only the technical challenges, however, still leaves us in the place of nibbling around the edges of a problem. Systems thinkers know to look at the structure of the system in which the problem exists to understand the larger forces at play that keep the system operating as it is. As participants examined some of these forces, they realized that market forces, public policies and even regulations were presenting larger barriers to the changes they were seeking. Homeowners are rightfully nervous about switching from natural gas to electricity given the price difference in the two energy sources and the decreasing reliability of the electrical grid in California over the last decade. It’s challenging to convince the public to switch from gas to electric when power outages are becoming more frequent.

While California leads the nation in climate policies, we learned that those policies are not always consistently implemented from jurisdiction to jurisdiction, creating confusion among homeowners and contractors. Additionally, the implementation of some policies created ripple effects in terms of more complicated approval processes, additional paperwork and added inspection requirements that discourage the very projects the regulation was intended to foster. The same was found to be true even with the many financial assistance mechanisms created to support the change. While rebates and incentives are available for various home electrification projects, they are inconsistently applied, inadequate to cover the incremental cost of an electric appliance and time-consuming to apply for. Contractors mentioned that the labor required to complete rebate paperwork often outweighs the incentive value itself. Finally, how can equity issues be addressed, so that all homeowners can participate in the climate transition?A systems-mapping approach can reveal recommendations for many sustainability and social justice problems, which are by definition multi-stakeholder.

Mental models held by homeowners

Systems are also driven by the attitudes and beliefs of the people that create and operate within them. The groups uncovered a host of mental models that discourage the home electrification effort. Foremost among them is the concept of initial cost. Many changes suggested by energy experts require the purchase of equipment that is more expensive than traditional gas appliances, but that return greater value over time when paired with renewable energy sources and storage. 

Many consumers either can’t afford the upfront cost or don’t understand the long-term benefit. The upfront costs also drive consumers to wait until existing appliances have reached their end of life before replacing. While not illogical, if they wait until equipment fails, they usually miss the opportunity to convert to an electric appliance, as the conversion can take several days to implement. When someone suddenly has no hot water, they’re not inclined to wait four days to make the switch. 

Next, the homeowner is easily baffled as to what to do or not to do, because they have no whole-house electrification plan to help them avoid pitfalls as they more affordably electrify their homes one mechanical system at a time. Finally, the real estate market has been slow to value energy efficiency, so investments in energy conservation may not be adequately factored into a home’s valuation, often making granite countertops a better selling point than wall insulation or air sealing.

Reconvening and recommendations

To overcome the cost barrier and the “wait until it breaks” attitude, the group is recommending three financial incentives programs: 

  1. “Cash for clunkers”-style incremental incentive that would reward people for proactively converting to electric appliances, rather than waiting until their old one breaks 
  2. Instant rebates that reduce the cost of electric appliances when they’re purchased, rather than requiring rebate paperwork to be filed after the fact 
  3. Scaling up financing mechanisms through public/private partnerships to enable homeowners to more easily access low-interest loans and avoid upfront payments.

The group also recognized the need to simplify permitting processes and requirements and make them consistent across jurisdictions. That led the group to consider whether a statewide policy would be more effective than a regional strategy implemented unevenly at the city level. Based on these conclusions, this effort identified key stakeholders to convene to discuss how to move the ideas forward.

Applying systems mapping to multi-stakeholder issues for new solutions

As a culture, we rush to converge on actions in which lots of people are busy doing lots of things. But the existential problems require more synergistic efforts. A systems-mapping approach identifies the system’s greatest leverage for change. Often, the technology, the will and great thinking are there, but change — such as transitioning homes from electric and gas to electric only— runs against a system with inertia. 

A systems-mapping approach can reveal recommendations for many sustainability and social justice problems, which are by definition multi-stakeholder. All you need is a convening of insightful participants, skilled facilitation and forward thinkers such as the San Mateo County Office of Sustainability, BayREN and the other collaborators for such projects.