The Permian Is Drowning in Its Own Wastewater

By Irina Slav - Dec 29, 2025

• The Permian basin's massive oil production from hydraulic fracturing generates huge amounts of wastewater, and the industry is running out of safe places to dispose of it.
• 
  
• The Texas Railroad Commission has restricted new disposal wells due to widespread increases in reservoir pressure, leading to drilling hazards, ground deformation, and seismic activity.
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• Potential solutions, such as treating the water for release into rivers, face regulatory hurdles and would add significant, unwelcome costs to producers operating below $60 per barrel West Texas Intermediate.

The Permian Basin is the largest contributor to U.S. oil production, accounting for nearly half of total production in both 2024 and 2025. But success comes at a price, and in the Permian’s case, the price is huge amounts of wastewater—and the industry is running out of places to store it.

Hydraulic fracturing, which is the dominant way of extracting oil in the Permian, is a water-intensive process. Fracking involves injecting chemicals and sand into the horizontal well to open up the oil-bearing rock and keep it open. The longer the laterals got, the more water needed to be injected. This water, which is mixed with chemicals, then gets disposed of in special wells. But there are too many of those, and they are overflowing, according to reports.

The first signs of serious trouble emerged earlier this year, when the Texas Railroad Commission sent out notices to companies applying for licenses for wastewater disposal wells in the basin, stating that there were ground pressure issues caused by wastewater disposal. The number of new ones was to be restricted.

Wastewater disposal, the Railroad Commission wrote in the letters sent out in May, “has resulted in widespread increases in reservoir pressure that may not be in the public interest and may harm mineral and freshwater resources in Texas.” The RRC added that “Drilling hazards, hydrocarbon production losses, uncontrolled flows, ground surface deformation, and seismic activity have been observed.”

It is difficult to find a solution to this problem without compromising oil production, and while local communities may not have a big problem with that, the industry will. So decision-makers in relevant positions are considering options. One of these, per a recent Bloomberg report, is releasing the water—after treating it—into local rivers. 

The report cited regulatory filings concerning the issue of permits to energy companies to treat their wastewater and then release it into the Pecos River near New Mexico. Texas Pacific Land Corp. and NGL Energy Partners were two of the companies named as potential receivers of such a permit. At least one of these could be awarded by the end of March 2026, the Bloomberg report also said, citing Texas Pacific Land Corp.

If the wastewater problem is to be solved, however, more such permits would be needed—unless opposition to them emerges and spreads. There is also the issue of additional costs, Bloomberg noted. Treating the water to make it of suitable quality to be poured into a river would add to oil producers’ costs, and this is not the time to have more costs pile up for most producers, with West Texas Intermediate firmly below $60 per barrel. What’s more, Bloomberg reports that the safety of the whole procedure of releasing treated water into rivers has not yet been confirmed.

The Texas Commission on Environmental Quality has already signaled it will not be handing out wastewater-to-river permits like candy. The watchdog told Bloomberg it was monitoring the water quality at four locations along the Pecos River and two locations in its Red Bluff Reservoir—while considering the first of those permits.

The Wall Street Journal, meanwhile, reported that while regulators are looking for solutions to the wastewater problem, pressure is building in the rock, suggesting it may come to affect production. There is so much wastewater across the Permian that it is moving into old wellbores, causing geysers that cost a lot to clean up, the publication said, adding that pressure in injection reservoirs in some parts of the Permian has reached 0.7 pounds per square inch per foot. This is 0.2 pounds higher than the threshold over which liquid can flow up to the surface and potentially affect drinking water.

The Wall Street Journal noted that drillers in the Delaware Basin are pumping between 5 and 6 barrels of fluid for every barrel of oil they recover. That, it appears, is a lot, and the practice, as suggested by these reports, is unsustainable. The current solutions also appear to be falling short, mostly consisting of switching from deep disposal wells to shallower ones to avoid changes in seismic activity, as reported by the U.S. Geological Survey.

The shallow disposal wells have fixed the seismic problem and are currently receiving three-quarters of all wastewater produced in the Permian, the WSJ reported, noting, like Bloomberg, the unwanted water geysers that the migrating water is causing. One of these costs $2.5 million to plug, with the Texas Railroad Commission also shutting the injection wells that it suspected were leading to leaks, the Wall Street Journal wrote.

Meanwhile, the industry is trying to fortify its wells against wastewater seeping from injection wells, which also leads to additional costs. “Bit by bit, it adds cost, it adds complexity, it adds mechanical challenges,” one Chevron executive told the WSJ. On top of this, the wastewater is seeping into the oil and gas reservoirs, and there seems little that anyone can do about it except spend more to remove it. The issue with excess wastewater in Texas remains a challenge to an industry that is pumping almost half of the nation’s oil.

By Irina Slav for Oilprice.com 

Geothermal Power Emerges as Trump’s Favorite Clean Energy

FRACKING BY ANY OTHER NAME

By Felicity Bradstock - Oct 12, 2025

• Geothermal energy remains one of the few renewable sources still supported by the Trump administration, benefiting from Biden-era incentives and bipartisan backing.
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• Innovative firms like Fervo Energy and Sage Geothermal are pioneering advanced extraction methods that boost efficiency and expand geothermal access beyond traditional hotspots.
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• Major collaborations and endorsements - from Ormat and Baker Hughes to Bill Gates - are propelling geothermal toward large-scale commercialization across the U.S.
• 
  

One of the few renewable energy sources that the Trump administration has not yet criticised is geothermal power, as companies across the United States continue to develop innovative geothermal projects with financial support from Biden-era policies. The sweeping budget legislation that President Trump signed in July preserved most key tax credits for geothermal power. Bipartisan support has encouraged several energy companies and startups to invest heavily in research and development into advanced geothermal operations in recent years, with promising results, giving hope for future clean energy production.

People have been tapping into geothermal energy from natural heat sources worldwide for centuries. Over the last fifty years, energy companies have tapped into geothermal sources using machinery to access harder-to-reach reserves. To achieve this, companies drill a borehole up to several kilometres deep, where the rocks are around 200°C, and inject water and sand at high pressure. This creates fractures in the rocks, which increases their permeability and produces a reservoir of hot water that can be extracted via a second borehole for the water to be used to generate electricity.

Geothermal energy contributes just 0.4 percent of the U.S. energy mix, largely due to technological and geographical constraints to accessing geothermal reservoirs. Existing plants depend on naturally occurring reservoirs of hot water and steam, in regions such as Northern California and Nevada, to power turbines and generate power. However, companies are now exploring new ways to access geothermal resources using techniques developed for oil fracking and innovative new methods to reach harder-to-access reservoirs in unconventional regions.

Sage Geothermal is now using heat and pressure to generate more power than conventional extraction methods through its cycle-based heat recovery approach. The company’s CEO, Cindy Taff, told Forbes, “By using the natural elasticity of the rock, we can bring hot water to the surface without pumps. Unlike traditional approaches, we maintain pressure in the system rather than venting it at the surface, and we hold open fractures with pressure instead of adding bridging materials like sand or proppant. These innovations reduce friction and energy losses, boosting net power output by 25 to 50 percent compared to other next-generation geothermal technologies.”

In August, Sage announced it was partnering with the international geothermal energy developer Ormat Technologies to roll out its next-generation technology at an Ormat facility in either Nevada or Utah. This is expected to help Sage speed up the development of its first commercial power-generation facility by around two years. Taff said, “For us, the ability to scale faster with Ormat is huge… But it’s also a great opportunity for Ormat to reach a deeper [geothermal] resource than what they’re targeting now.”

Related: Don’t Mess with Texas: Organized Oilfield Theft Triggers Statewide Response

In September, Sage signed an agreement with the geothermal startup Fervo Energy to advance their geothermal activities. The two companies have both invested heavily in research and development into alternative geothermal extraction methods and could work together to advance this work. Fervo recently signed a deal with tech giant Google to provide it with clean power, while Sage has completed an agreement with Meta.

Houston-headquartered Fervo Energy was approved to deploy 2 GW of geothermal power in Beaver County, Utah, by the Department of the Interior last year, with its facility set to begin generating power in 2026. The company uses an Enhanced Geothermal Systems (ESG) proprietary technology to drill horizontally into geothermal reservoirs, allowing it to access multiple wells from a single location and showing promise for greater unconventional geothermal energy generation.

In September, the energy technology company Baker Hughes was contracted by Fervo Energy to supply equipment for five of its power plants in the Cape Station project in Utah. The plants are expected to produce 300 MW of electricity once fully operational, enough to power about 180,000 homes. Baker Hughes will supply engineering and manufacturing equipment as well as turboexpanders and the BRUSH Power Generation generator.

The firm’s CEO, Lorenzo Simonelli, said, “Geothermal power is one of several renewable energy sources expanding globally and proving to be a vital contributor to advancing sustainable energy development. “By working with a leader like Fervo Energy and leveraging our comprehensive portfolio of technology solutions, we are supporting the scaling of lower-carbon power solutions that are integral to meet growing global energy demand.”

In September, Bill Gates visited Fervo Energy’s Cape Station project alongside Senator John Curtis. He described the company’s horizontal drilling method as a “truly innovative approach” and discussed the role companies like Fervo will play in maintaining America’s energy independence. The founder of tech giant Microsoft said, “Geothermal is one of the most promising ways to deliver clean energy that’s reliable and affordable.”

As the outlook for renewable energy in the United States becomes more uncertain, following the Trump administration's attacks on solar and wind power, the geothermal energy sector appears to have maintained the backing of the government as several companies continue to expand operations. Investments in innovative geothermal extraction technologies show great promise for the commercial rollout of new operations across the country. 

By Felicity Bradstock for Oilprice.com

 MONOPOLY CAPITALI$M

Chevron Completes Hess Acquisition, Including Offshore Guyana Stake

The Exxon-operated FPSO One Guyana (Exxon file image)

Published Jul 20, 2025 3:02 PM by The Maritime Executive

 \

Despite objections from ExxonMobil, Chevron has completed its planned acquisition of privately-held rival Hess, including a 30 percent stake in Exxon's lucrative Stabroek Block developments off Guyana. 

Exxon attempted to block the Hess acquisition by filing an arbitration case through the International Chamber of Commerce. Hess's contract for the ownership of the Stabroek Block lease included a clause providing right of first refusal to Exxon in the event of a sale of Hess' stake; Exxon insisted that this clause applied in the event of the sale of Hess itself. Chevron disagreed, and acrgued

On Friday morning, Exxon lost its arbitral case, and Chevron completed the process of closing on the acquisition of Hess within four hours of the arbitration panel's announcement. Chevron CEO Mike Wirth celebrated the win, thanking the arbitral panel for recognizing the "longstanding practice and understanding that asset-level rights of first refusal do not apply in parent company merger and acquisition transactions."

Exxon has accepted the reality that - despite its objections - Chevron is its new business partner in the Stabroek Block project. "We disagree with the ICC panel’s interpretation but respect the arbitration and dispute resolution process," Exxon said in a statement. "We welcome Chevron to the venture and look forward to continued industry-leading performance and value creation in Guyana."

The Stabroek Block is one of the world's most promising offshore finds, and is a powerhouse behind Exxon's profit margins. The IEA predicts that it will singlehandedly produce one percent of the world's oil in future years. Even with the high cost of offshore operations, the first four Stabroek FPSOs will produce oil at a breakeven cost of less than $35 per barrel, according to independent estimates - meaning that even in an era of low oil prices, the projects will still be profitable. 

Chevron Completes Hess Megadeal After Winning Guyana Arbitration

By Michael Kern - Jul 18, 2025

Chevron Corporation said on Friday it had completed the $53-billion acquisition of Hess Corporation after winning an arbitration case against Exxon over the Guyana assets of Hess.  

In 2023, Chevron proposed a $53-billion deal to buy Hess Corp and thus take Hess’s assets in the Bakken in North Dakota and the 30% stake in Guyana’s Stabroek offshore oil field—a top-performing asset with the potential to yield even more barrels and billions of U.S. dollars for the project’s partners. 

Exxon is the operator of the Stabroek block with a 45% stake. Hess held 30%, and China’s state firm CNOOC has the remaining 25% stake. 

Proceeds for the consortium, which is already pumping more than 660,000 barrels per day (bpd) from several projects in the block, are rising with growing production, even at relatively lower oil prices, because the Guyana block is estimated to have a breakeven oil price of about $30 per barrel.  

Chevron’s bid to buy Hess’s stake in the Guyana projects was challenged by Exxon and CNOOC, who claim they have a right of first refusal for Hess’s stake under the terms of a joint operating agreement (JOA) for the Stabroek block. Hess and Chevron claimed the JOA doesn’t apply to a case of a proposed full corporate merger.   

The dispute went to arbitration, which ruled in favor of Chevron, the company said today, announcing the completion of the Hess acquisition, “following the satisfaction of all necessary closing conditions, including a favorable arbitration outcome regarding Hess’ offshore Guyana asset.” 

Chevron now owns a 30% position in the Guyana Stabroek Block, which has more than 11 billion barrels of oil equivalent discovered recoverable resource. 

In addition, the Federal Trade Commission (FTC) on Friday lifted its earlier restriction, clearing the way for John Hess to join Chevron’s Board of Directors, subject to Board approval. 

“The combination enhances and extends our growth profile well into the next decade, which we believe will drive greater long-term value to shareholders,” said Mike Wirth, Chevron chairman and CEO.  

By Michael Kern for Oilprice.com 

Do Upstream Mergers Really Deliver Value for Shareholders?

By David Messler - Jul 17, 2025

• The article questions whether large M&A transactions in the E&P sector consistently translate into tangible shareholder value, despite initial promises of immediate accretion and synergies.
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• The ExxonMobil acquisition of Pioneer Natural Resources is examined as a case study, highlighting the industrial logic behind the deal but also pointing out the lack of immediate financial benefits for ExxonMobil shareholders, such as increased stock price or EPS accretion.
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• The author suggests that while M&A may offer long-term benefits in terms of scale and sustainability for companies, the short-term impact on shareholder returns often appears negligible or even negative, describing it as a "shell game" for investors.
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I've been noodling around with an idea for a while now. The thing on my mind is when do investors actually gain from the big gobs of money E&P companies spend on M&A? A lot of promises are made in the early days. But as time wears on, I rarely see any effort made to reconcile results with these promises. So bear with me as I go through this little exercise. 

Now I am not saying that M&A isn't necessary as strong companies buy out smaller, weaker companies to get their premium assets. That part of the transaction is easily understood, and I will review that thought in the ExxonMobil/Pioneer Natural Resources case as we go through this exercise. My point here is investors are still waiting for these results to show up in their mail box. In fairness, not a lot time has elapsed, but I think trends are instructive. Let's dive in.

Upstream M&A: Shell game?

The upstream industry has been on a buying binge the last several years with hundreds of billions worth of transactions on the books. One of the most notable thus far has been ExxonMobil’s (NYSE:XOM) acquisition of Pioneer Natural Resources, for approximately $253 per share or a substantial $64.5 billion, including debt, in an all-stock transaction. As noted in the deal slide from the announcement, this was an 18% premium to recent pricing for Pioneer. In exchange for XOM diluting current holders of its stock by about 255 mm shares or ~6%, the company made some firm promises in regard to the future upside for the combined company. Among other things XOM holders were told the transaction would be “immediately accretive to EPS.” Hold that thought.

Some time has gone by since the deal closed in May of 2024 and it seemed appropriate to peek under the hood to see how the company was delivering on these commitments. It’s also worth reviewing just what drove Exxon’s interest in paying a premium to Pioneer to obtain their Midland acreage.

The Industrial Logic of ExxonMobil and Pioneer

Industrial logic is the term applied to these mega deals. It’s one of the terms, along with synergy and accretive, that are bandied about on announcement day. As you can see below, Pioneer’s Midland basin acreage was like a missing puzzle piece to Exxon’s prior footprint in the play. Exxon is a technology company with a track record of pushing the envelope to drive down costs and increase production, but to fully deploy their technical expertise, they needed more room.

When you snap the two pieces together, you get a blocky, connected plot of land that runs for 50-75 miles east and west, and the better part of a couple of hundred miles north and south. 1.4 million acres is a sizeable chunk of dirt. That’s significant and opens the door to huge numbers of 4-5 mile laterals, with centralized logistics, sand, water, the stuff of fracking, and helping lock-in low cost of supply. The easy stuff put in place, XOM engineers are free to work their magic wringing maximum barrels out of each foot of completed interval. That’s all great for the company, but does this add to the value of the company in a way that benefits shareholders? Something real, and tangible that they can spend. Today. Like the stock price going up. Or special dividends. It seems like it should, and that’s where we will look next for any sign the company is about to embark on an enhanced shareholder rewards package. 

Capitalization is one metric by which we might judge the impact of a transaction. Suppose company A, worth X, buys company Z, worth Y. In that case, logic suggests that company AZ should match the value of the two merger partners, or X + Y. Referring back to our ExxonMobil example, on May 2nd, the day before the merger closed the share price of XOM was $116.21 per share. With 3,998,000,000 shares outstanding that works out to a capitalization of $462 bn. At the agreed price of $253 per share for Pioneer their capitalization was $59.5 bn. The two together should have created an entity worth $521 bn, a point from which the merger driven success of the company should have been a  value accretion launching pad. By the end of 2024 XOM stock was trading at $107.27. With 4,424 bn shares outstanding the company’s capitalization stood at $474 bn. In about six months, some $47 bn in capitalization had vanished into thin air.

Investors were promised the transaction would be immediately accretive to earnings per share. In June, 2024 reporting for the second quarter showed EPS to be $2.14 per share. For the fourth quarter EPS was $1.67 per share. So no immediate accretion. Perhaps patience will pay off. For the first quarter of 2025 EPS was $1.76 per share and the forecast for Q-2 is $1.55 share. One step forward and another back. What matters is that, thus far the combined company has not equaled its standalone performance. This is a sobering thought in light of the dilution visited upon shareholders, and the expense the company is going to repurchase shares.

Related: Goldman: The Boom Years of U.S. Oil Output Growth Are Over

I may be piling on a bit here as the time elapsed since the merger is minimal. ROCE or Return on Capital Employed, shows little sign of being moved significantly higher in the merger. For a Twelve-Trailing Month-TTM period, Exxon’s ROCE was 0.10882, a slight improvement from Full Year-2024’s 0.1082. Moving in the right direction, but after spending $64.5 bn in stock dilution, one might hope for a teensy bit more. Like I said, perhaps not enough time has gone by to attach much weight to the change in ROCE.

Summing up

So, where does that leave us as we eagerly anticipate another mega merger? I refer, of course, to the one that now hangs in the balance for Chevron (NYSE:CVX) and Hess (NYSE:HES), with an arbitrator set to rule on XOM’s claim of primacy in the pre-emptive right to buy HESS’ share in the Stabroek field, offshore Guyana. If we buy into CVX today it will cost us $150 per share. If the arbitrator rules in their favor and the assets of Hess are merged into CVX, will the price of CVX then become X+Y-dilution? Or the CVX price plus the Hess price of $171 per share, less the amount of stock CVX will print~$351 mm shares to meet the deal price of $60 bn? Will the combined company have a capitalization of $327 bn? If history is any guide this outcome is unlikely.

It is certainly food for thought as another serial acquirer comes to mind. I refer here to Occidental Petroleum, (NYSE: OXY), which after the Anadarko deal of 2019 for $57 bn, and then the CrownRock deal of 2024 for $12 bn- a combined cash and stock outlay of $69 bn for a company with a present day capitalization of $42 bn. Warren Buffett with a 26.92% stake in OXY, for which he’s paid an average of $51.92 per share, is down 21% on his investment. I wonder what his response would be today if the OXY plane landed in Omaha with a deal in management’s pocket. I have a pretty good idea actually.

I will reiterate-the Industrial logic of upstream M&A is abundantly clear. As an industry matures size and scale matter, and perhaps (likely) this is where value shows up for shareholders who remain long for an extended period. The company can continue to develop oil and gas deposits long after the standalone company would have drilled itself out of existence. But over the short run, it looks like a shell game to me.

By David Messler for Oilprice.com 

Oilfield service group says relief from counter-tariffs on U.S. sand ‘fantastic news’

By The Canadian Press
July 17, 2025 

A sand dune is backdropped by Atlas Energy plant at the beginning of a 68-kilometre conveyor belt that carries sand needed for hydraulic fracturing Wednesday, Feb. 26, 2025, in Kermit, Texas. (AP Photo/Julio Cortez)

CALGARY — The federal government is offering Canadian oil and gas drillers counter-tariff reprieve on the vast amounts of sand they import from the United States.

The sand is used in the hydraulic fracturing — or fracking — process to help free resources trapped in hard-to-access shale formations deep underground

It’s among the imported U.S. goods on which Canada has imposed a surcharge in retaliation for President Donald Trump’s flurry of tariffs.

Sand from Wisconsin meets the specs needed by Canadian drillers, and the lion’s share of what they use is brought in from the Midwestern state.

A federal order published in the Canada Gazette newsletter this week says relief is available for companies that import silica and quartz sand, among other products.


Gurpreet Lail, the chief executive of industry group Enserva, says it’s fantastic news, as the counter-tariffs on sand alone would have cost industry $275 million a year.

---

Lauren Krugel, The Canadian Press

This report by The Canadian Press was first published July 17, 2025.

BURN BABY BURN

Burning Trash For Energy, People And Planet – OpEd

 June 30, 2025  

By Paul Driessen

Waste-to-Energy reduces landfilling, increases recycling, powers society and avoids blackouts

After years of opposing them, but facing constituents increasingly angry about rising electricity prices, New York Governor Kathy Hochul recently gave grudging support for two new Williams Companies natural gas pipelines.

Assuming they clear new hurdles, the Constitution Pipeline will transport gas 100+ miles from northeastern Pennsylvania fracking fields toward Albany. The 23-mile Northeast Supply Enhancement Pipeline will connect New York to the New Jersey segment of the Transco Pipeline, America’s largest-volume natural gas pipeline system, and carry enough gas to heat 2.3 million homes.

Hochul, other state Democrats and environmental activists have long stymied the projects, using exaggerated and fabricated water quality and climate change arguments – and fanciful expectations that heavily subsidized solar panels and onshore and offshore wind turbines can provide enough affordable electricity, enough of the time, to meet steadily increasing New York City and State power demands.

In exchange, the Trump Administration will let them continue installing gigantic offshore wind turbines that will generate 9,000 MW of electricity (less than one-third of what the state needs on hot summer days) perhaps 30-40% of the year … and be supported by fire-prone grid-scale batteries that would provide statewide backup power for about 45 minutes.

New gas turbines would help avoid blackouts, ensure that poor families freeze less often in winter and swelter less in summer, and help the state meet power needs that are soaring because of data centers, artificial intelligence, and legislatively mandated conversions from gasoline and gas to electric vehicles, stoves, and home and water heating.

They could also help reduce the need to import electricity from Canada and other states: some 36,000 gigawatt-hours (11% of statewide electricity) annually.

But legislators want to put another hurdle in the way. New legislation would force homes and businesses to pay $10,000 or more to connect to natural gas lines. If Gov. Hochul signs the bill, or the legislature overrides a veto, few or no new customers would take advantage of the new gas.

It’s a kill switch, reflecting the state’s determination to impose “climate leadership” and “protect communities” from alleged dangers from fossil fuels.

It’s also hypocritical and irresponsible. New York doesn’t just import electricity; it also exports garbage.

New York City generates nearly eight million tons of waste annually. Its last municipal incinerator closed in 1990; its last municipal landfill in 2001. City trash is now mostly sent on barges, trucks and trains to landfills (80%) and incinerators (20%) in New Jersey, Upstate New York, Pennsylvania, and even Virginia, Ohio and South Carolina! NY State exports 30% of its garbage.

The city and state could address both garbage and electricity challenges by using natural gas to power waste-to-energy (WTE) generating plants that burn trash, thereby reducing the need to landfill or export garbage, while increasing recycling, producing reliable, affordable, much-needed electricity, and reducing blackout risks that are climbing every year.

In Fairfax County, Virginia, a WTE or resource recovery facility operated by Reworld Waste burns home, business, industrial and other garbage that doesn’t go straight into recycling programs and would typically be landfilled, including myriad extraneous plastics. The trash is dumped in a receiving area, sorted for unacceptable materials like rocks, mixed thoroughly, and burned with natural gas in a chamber at 2000 degrees F for up to two hours, until it’s totally combusted to ash. 

The heat converts water to steam, which is super-heated in tubes to drive turbines that generate electricity: 80 megawatts 24/7, enough for about 52,000 homes. Depending on its composition, a ton of waste generates 550-700 kilowatt-hours of electricity.

Since opening in 1990, the plant’s trash has replaced the equivalent of burning 2,000,000 barrels of oil for electricity every year.

Glass from lightbulbs and other nonrecyclable sources becomes part of the ash stream, from which ferrous and nonferrous metals are recovered. Most of the remaining ash is used as a substitute for sand and aggregates in road and building construction, cement and cinder block production, and manufacturing other building materials.

Unsold ash is landfilled but, by the time the metals are removed, only about 10% of the original trash bulk and 25% of its original weight is left.

Even staples, paper clips, bottle caps, metal light bulb bases, aluminum foil, and wires from spiral notebooks and furnace filters can be “recycled” this way. In fact, enough iron, steel, aluminum, copper and other metals are recovered from the resultant ash at the Fairfax facility to build 20,000 automobiles annually.

However, plastic-metal-glass waste (computers, monitors, keyboards, printers, microwaves), broken pots and pans, household appliances and other larger refuse should go to special “white goods” and metal recycling centers.

Lime neutralizes acids in the airstream, activated carbon controls heavy metals, and fabric filter bags remove particulates, keeping air emissions below EPA standards. The scrubber waste (fly ash) is then dewatered and chemically stabilized, before being landfilled or used in construction materials. 

Process steam condenses back into water and is reused. Water from the wastes and scrubbers is recovered, treated and used to cool the facility and equipment.

Two other trash-to-energy facilities serve the Washington, DC area; 75 across the USA generate over 2,500 MW of electricity. However, more WTE plants could help solve garbage, energy, landfill and pollution problems in metropolitan areas across the country (and worldwide), including:

* Philadelphia, PA – 1,300,000 tons per year of municipal solid waste (MSW), but only one WTE; 
* Chicago, IL – 3,100,000 tpy, but just one WTE plant (other proposed facilities were rejected);
* Houston, TX – 4,200,000 tpy, with one WTE facility;
* Phoenix, AZ – 1,000,000 tpy, and one WTE facility;
* Los Angeles, CA – 4,000,000 tpy, but again only one WTE facility.  

New York and other jurisdictions that have rejected natural gas and waste-to-energy/resource-recovery facilities are missing enormous opportunities to address challenges that will only become worse. They’re also dumping their own local responsibilities into their neighbors’ backyards.

These facilities ensure secure, affordable electricity generation close by, without the need for expensive backup power and multi-hundred-mile transmission lines to part-time wind and solar power.

They utilize fuels that America still has in abundance: gas and trash. And they reduce the need for resources that are in increasingly short supply: landfill space, cropland and wildlife habitats impacted, and bird, bat and other wildlife lost due to wind, solar and transmission installations.

From my perch, these clear and significant benefits clearly offset the cost and subsidyconcerns that some have raised about WTE facilities.

Metro areas and states should apply pragmatism, reality and these benefits when reconsidering climate and “renewable” energy ideologies that have dominated public policies for far too long.

Paul Driessen

Paul Driessen is a senior fellow with the Committee For A Constructive Tomorrow and Center for the Defense of Free Enterprise, nonprofit public policy institutes that focus on energy, the environment, economic development and international affairs. During a 25-year career that included staff tenures with the United States Senate, Department of the Interior and an energy trade association, he has spoken and written frequently on energy and environmental policy, global climate change, corporate social responsibility and other topics. He’s also written articles and professional papers on marine life associated with oil platforms off the coasts of California and Louisiana – and produced a video documentary on the subject.