New Mexico’s Community Solar Program
Originally published on ILSR.org.
Governor Michelle Lujan Grisham signed the Energy Transition Act (SB 489) in 2019, which introduced the idea of a community solar program, and also mandated that New Mexico move to 50% renewable energy by 2030. However, New Mexico’s community solar program was truly born in 2021, when the Community Solar Act (SB 84) established New Mexico’s official program.
After a three-hour filibuster, the Community Solar Act (SB 84) passed on April 5, 2021. The act authorized community solar projects in the state and requires that 30 percent of each community solar facility serves low-income households. The first three years of the program are capped at 200 megawatts of total generating capacity. This total does not include native community solar projects or rural electric distribution cooperatives. The bill defines “native community solar projects’ ‘ as facilities located on native land that is owned or operated by “an Indian nation, tribe, or pueblo or a tribal entity or in partnership with a third-party entity.” This addresses ILSR’s third principle: that any community solar policy must be additive, rather than detract from any existing renewable energy policy. Subscriptions can supply up to 100% of subscribers’ average annual electricity consumption.
Watch the top state community solar programs progress in our National Community Solar Programs Tracker and click here to find more state program pages.
New Mexico is the second sunniest state in the United States, with an average of 300 days per year of sunshine. This climate makes the state a prime candidate for solar power. Early estimates suggest that New Mexico’s community solar program should be up and running by Spring 2022. The Community Solar Act requires that the Public Regulation Commission finalize the rules process by April 1, 2022.
In addition to investor-owned utilities, third parties can own community solar facilities ( fulfilling the Institute for Local Self Reliance’s second principle of successful community renewable energy, flexibility). The system is regulated through renewable energy certificates. In the case of community solar facilities, these certificates are actually owned by the electric utility to which the facility is interconnected. These certificates may be traded or sold, and serve as proof of compliance with New Mexico’s renewable portfolio standard. The community solar program will help to fulfill New Mexico’s requirement that investor-owned utilities are carbon-free by 2045 and 2050, respectively.
Tangible Benefits
A study by the University of New Mexico’s Bureau of Business and Economic Research predicts that the community solar project will be a massive boost to New Mexico’s economy. For a small state, the numbers are staggering: 3,760 jobs over the next five years, $517 million in economic benefits, $147 million in labor income, and $2.9 million yearly in tax revenue. Community Solar also offers excellent benefits to small and medium sized landowners, like local farms, many of whom do not possess the amount of property necessary to host a full-scale solar plant. Additionally, projects can partner with local farms and offer landowners revenue for leasing space to solar gardens.
In addition to the boons to New Mexico’s economy as a whole, individual subscribers will receive meaningful benefits. Utilities must provide credits to subscribers for at least twenty-five years after interconnection. The credit rate is proportional to the kilowatt-hour production of their share of the facility, and is “derived from the qualifying utility’s aggregate retail rate on a per customer-class basis”. That amount is then credited to the subscriber’s bill from the provider. If a subscriber uses less than their allotted credit’s worth of electricity in a given month, the surplus amount is applied to their next month.
The program has yet to start, but based on these factors and predictions, New Mexico’s plan passes the Institute for Local Self Reliance’s first principle for successful community renewable energy, tangible benefits.
Promoting Indigenous Power
Tribal lands cover 10% of New Mexico, the third highest of any state. There are already multiple small-scale tribal owned solar facilities, including a 115 KW system for the Santo Domingo Tribe. Native community solar gardens are exempted from the overall cap and the individual 100% of average annual consumption limits. The Act states further that “nothing in the Community Solar Act shall preclude an Indian nation, tribe, or pueblo from using financial mechanisms other than subscription models, including virtual and aggregate net-metering, for native community solar projects.
Access To All
Beyond the Indigenous-focused pieces, the program contains further components designed to ensure access for a wide variety of subscribers, fulfilling ILSR’s fourth principle. All subscriber material must be printed in English, Spanish, and, if applicable, native or Indigenous languages. New Mexico’s Public Regulation Commission vows to seek input from a variety of stakeholders, which the Act notes includes “low-income stakeholders … disproportionately impacted communities … (and) Indian nations, tribes, and pueblos.” The program’s 30 percent capacity carveout for low-income subscribers compares favorably with other programs.
For more on solar in New Mexico, check out these ILSR resources:
Learn more about community solar in one of these ILSR reports:
For podcasts, videos, and more, see ILSR’s community renewable energy archive.
This article was originally posted at ilsr.org. For timely updates, follow John Farrell on Twitter or get the Energy Democracy weekly update.
Featured photo credit: formulanone via Flickr (CC BY-SA 2.0)
HAWESVILLE, KY – May 10
Plant workers drive along an aluminum potline at Century Aluminum Company’s Hawesville plant in Hawesville, Ky. on Wednesday, May 10, 2017. (Photo by Luke Sharrett /For The Washington Post via Getty Images)
Aluminum
The Washington Post | The Washington Post | Getty Images
Sweeping tariffs on imported aluminum imposed by U.S. President Donald Trump are succeeding in reshaping global trade flows and inflating costs for American consumers, but are falling short of their primary goal: to revive domestic aluminum production.
Instead, rising costs, particularly skyrocketing electricity prices in the U.S. relative to global competitors, are leading to smelter closures rather than restarts.
The impact of aluminum tariffs at 25% is starkly visible in the physical aluminum market. While benchmark aluminum prices on the London Metal Exchange provide a global reference, the actual cost of acquiring the metal involves regional delivery premiums.
This premium now largely reflects the tariff cost itself.
In stark contrast, European premiums were noted by JPMorgan analysts as being over 30% lower year-to-date, creating a significant divergence driven directly by U.S. trade policy.
This cost will ultimately be borne by downstream users, according to Trond Olaf Christophersen, the chief financial officer of Norway-based Hydro, one of the world’s largest aluminum producers. The company was formerly known as Norsk Hydro.
“It’s very likely that this will end up as higher prices for U.S. consumers,” Christophersen told CNBC, noting the tariff cost is a “pass-through.” Shares of Hydro have collapsed by around 17% since tariffs were imposed.
The downstream impact of the tariffs is already being felt by Thule Group, a Hydro customer that makes cargo boxes fitted atop cars. The company said it’ll raise prices by about 10% even though it manufactures the majority of the goods sold in the U.S locally, as prices of raw materials, such as steel and aluminum, have shot up.
But while tariffs are effectively leading to prices rise in the U.S., they haven’t spurred a revival in domestic smelting, the energy-intensive process of producing primary aluminum.
The primary barrier remains the lack of access to competitively priced, long-term power, according to the industry.
“Energy costs are a significant factor in the overall production cost of a smelter,” said Ami Shivkar, principal analyst of aluminum markets at analytics firm Wood Mackenzie. “High energy costs plague the US aluminium industry, forcing cutbacks and closures.”
“Canadian, Norwegian, and Middle Eastern aluminium smelters typically secure long-term energy contracts or operate captive power generation facilities. US smelter capacity, however, largely relies on short-term power contracts, placing it at a disadvantage,” Shivkar added, noting that energy costs for U.S. aluminum smelters were about $550 per tonne compared to $290 per tonne for Canadian smelters.
Recent events involving major U.S. producers underscore this power vulnerability.
In March 2023, Alcoa Corp announced the permanent closure of its 279,000 metric ton Intalco smelter, which had been idle since 2020. Alcoa said that the facility “cannot be competitive for the long-term,” partly because it “lacks access to competitively priced power.”
Similarly, in June 2022, Century Aluminum, the largest U.S. primary aluminum producer, was forced to temporarily idle its massive Hawesville, Kentucky smelter – North America’s largest producer of military-grade aluminum – citing a “direct result of skyrocketing energy costs.”
Century stated the power cost required to run the facility had “more than tripled the historical average in a very short period,” necessitating a curtailment expected to last nine to twelve months until prices normalized.
The industry has also not had a respite as demand for electricity from non-industrial sources has risen in recent years.
Hydro’s Christophersen pointed to the artificial intelligence boom and the proliferation of data centers as new competitors for power. He suggested that new energy production capacity in the U.S., from nuclear, wind or solar, is being rapidly consumed by the tech sector.
“The tech sector, they have a much higher ability to pay than the aluminium industry,” he said, noting the high double-digit margins of the tech sector compared to the often low single-digit margins at aluminum producers. Hydro reported an 8.3% profit margin in the first quarter of 2025, an increase from the 3.5% it reported for the previous quarter, according to Factset data.
“Our view, and for us to build a smelter [in the U.S.], we would need cheap power. We don’t see the possibility in the current market to get that,” the CFO added. “The lack of competitive power is the reason why we don’t think that would be interesting for us.”
While failing to ignite domestic primary production, the tariffs are undeniably causing what Christophersen termed a “reshuffling of trade flows.”
When U.S. market access becomes more costly or restricted, metal flows to other destinations.
Christophersen described a brief period when exceptionally high U.S. tariffs on Canadian aluminum — 25% additional tariffs on top of the aluminum-specific tariffs — made exporting to Europe temporarily more attractive for Canadian producers. Consequently, more European metals would have made their way into the U.S. market to make up for the demand gap vacated by Canadian aluminum.
The price impact has even extended to domestic scrap metal prices, which have adjusted upwards in line with the tariff-inflated Midwest premium.
Hydro, also the world’s largest aluminum extruder, utilizes both domestic scrap and imported Canadian primary metal in its U.S. operations. The company makes products such as window frames and facades in the country through extrusion, which is the process of pushing aluminum through a die to create a specific shape.
“We are buying U.S. scrap [aluminium]. A local raw material. But still, the scrap prices now include, indirectly, the tariff cost,” Christophersen explained. “We pay the tariff cost in reality, because the scrap price adjusts to the Midwest premium.”
“We are paying the tariff cost, but we quickly pass it on, so it’s exactly the same [for us],” he added.
RBC Capital Markets analysts confirmed this pass-through mechanism for Hydro’s extrusions business, saying “typically higher LME prices and premiums will be passed onto the customer.”
This pass-through has occurred amid broader market headwinds, particularly downstream among Hydro’s customers.
RBC highlighted the “weak spot remains the extrusion divisions” in Hydro’s recent results and noted a guidance downgrade, reflecting sluggish demand in sectors like building and construction.
— CNBC’s Greg Kennedy contributed reporting.
Danish energy giant Ørsted has canceled plans for the Hornsea 4 offshore wind farm, dealing a major blow to the UK’s renewable energy ambitions.
Hornsea 4, at a massive 2.4 gigawatts (GW), would have become one of the largest offshore wind farms in the world, generating enough clean electricity to power over 1 million UK homes. But Ørsted announced that it’s abandoning the project “in its current form.”
“The adverse macroeconomic developments, continued supply chain challenges, and increased execution, market, and operational risks have eroded the value creation,” said Rasmus Errboe, group president and CEO of Ørsted.
Reuters reported that Ørsted’s cancellation of Hornsea 4 would result in a projected loss of up to 5.5 billion Danish crowns ($837.85 million) in breakaway fees and asset write-downs. The company’s market value has declined by 80% since its peak in 2021.
The cancellation highlights significant challenges currently facing offshore wind development in Europe, particularly in the UK. The combination of higher material costs, inflation, and global financial instability has made large-scale renewable projects increasingly difficult to finance and complete.
Ørsted’s decision is a significant setback to the UK’s energy transition goals. The UK currently has around 15 GW of offshore wind, and Hornsea 4’s size would have provided almost 7% of the additional capacity needed for the UK’s 50 GW by 2030 target, according to The Times. Losing this immense project off the Yorkshire coast could hamper the UK’s pace of reducing dependency on fossil fuels, especially amid volatile global energy markets.
The UK government reiterated its commitment to renewable energy, promising to work closely with industry leaders to overcome financial and logistical hurdles. Energy Secretary Ed Miliband told reporters in Norway that the UK is “still committed to working with Orsted to seek to make Hornsea 4 happen by 2030.”
Ørsted says it remains committed to its other UK-based projects, including the Hornsea 3 wind farm, which is expected to generate around 2.9 GW once completed at the end of 2027. Despite the challenges, the company emphasized its ongoing commitment to the British renewable market, pointing to the critical need for policy support and economic stability to ensure future developments.
Yet, the cancellation of Hornsea 4 demonstrates that even flagship renewable projects are vulnerable in the face of economic pressures and global uncertainties, which have been heightened under the Trump administration in the US.
Read more: The world’s single-largest wind farm gets the green light
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The Tesla Roadster appears to be quietly disappearing after years of delay. is it ever going to be made?
I may have jinxed it with Betteridge’s Law of Headlines, which suggests any headline ending in a question mark can be answered with “no.”
The prototype for the next-generation Tesla Roadster was first unveiled in 2017, and it was supposed to come into production in 2020, but it has been delayed every year since then.
It was supposed to get 620 miles (1,000 km) of range and accelerate from 0 to 60 mph in 1.9 seconds.
It has become a sort of running joke, and there are doubts that it will ever come to market despite Tesla’s promise of dozens of free new Roadsters to Tesla owners who participated in its referral program years ago.
Tesla uses the promise of free Roadsters to help generate billions of dollars worth of sales, which Tesla owners delivered, but the automaker never delivered on its part of the agreement.
Furthermore, many people placed deposits ranging from $50,000 to $250,000 to reserve the vehicle, which was supposed to hit the market 5 years ago.
The official timelines from Tesla are pretty useless at this point since they haven’t stuck to any of them, but the latest official one dates back to July 2024 when CEO Elon Musk said this:
“With respect to Roadster, we’ve completed most of the engineering. And I think there’s still some upgrades we want to make to it, but we expect to be in production with Roadster next year. It will be something special.”
He said that Tesla had completed “most of the engineering”, but he initially said the engineering would be done in 2021 and that was already 3 years after the prototype was unveiled and a year after it was supposed to be in production:
Musk commented on the Roadster again in October 2024, but he didn’t reiterate the 2025 timeline. Instead, he called the new Roadster “the cherry on the icing on the cake.”
Tesla’s leadership has been virtually silent about the new Roadster since. Two Tesla executives even had to be reminded about the Roadster by Jay Leno after they “forgot” about it when listing upcoming new Tesla vehicles with tri-motor powertrain.
There was one small update about the Roadster in Tesla’s financial results last month.
The automaker has a table of all its vehicle production, and the Roadster was updated from “in development” to “design development” in the table:
It’s not clear if that’s progress or Tesla is just rephrasing it. Either way, it is not “construction”, which makes it unlikely that the Roadster is going into production this year.
If ever…
Electrek’s Take
It looks like Tesla owes about 80 Tesla Roadsters for free to Tesla owners who referred purchases, and it owes significant discounts on hundreds of units.
It’s hard for me to believe that Tesla is not delivering the new Roadster because the vehicle program would start about $100 million in the red, but at this point, I have no idea. It very well might be the reason.
However, I think it’s more likely that Tesla is just terrible at bringing multiple vehicle programs to market simultaneously. Case in point: it launched a single new vehicle in the last five years.
At this point, I think it’s more likely that the Roadster will never happen. It will join other Tesla products like the Cybertruck Range Extender.
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