One GHG reduction technologies is carbon capture and sequestration (CCS), a technology that can capture and permanently store CO2 from power plants. 

In practice, exhaust gases from most combustion processes are at atmospheric pressure with relatively low concentrations of CO2. Most post-combustion capture systems use liquid solvents (most commonly amine-based) in a scrubber column to absorb the CO2 from the flue gas. This CO2-rich solvent is then regenerated by heating the solvent to release the captured CO2. The high purity CO2 is then compressed and transported, generally through pipelines, to a site for geologic sequestration.

In its proposed rulemaking, EPA said that process improvements, the availability of better solvents, and other advances have resulted in a decrease in the cost of CCS in recent years. It said the cost of CO2 capture, excluding any tax credits, from coal-fired power generation is projected to fall by 50% by 2025 compared to 2010. 

In addition, policies such as the 2022 Inflation Reduction Act (IRA) support the deployment of CCS technology and are expected to further reduce the cost of implementing CCS by extending and increasing the tax credit for CCS under Internal Revenue Code section 45Q.

EPA pointed to several examples CCS being used at power plants. These include SaskPower’s Boundary Dam Unit 3, a 110 MW lignite-fired unit in Saskatchewan, Canada, which EPA said has achieved CO2 capture rates of 90% using an amine-based post-combustion capture system retrofitted to the existing steam generating unit.

Amine-based carbon capture has also been demonstrated at AES’s Warrior Run (Cumberland, Maryland) and Shady Point (Panama, Oklahoma) coal-fired power plants.

CCS was applied to an existing combined cycle combustion turbine at the Bellingham Energy Center in south central Massachusetts. The 40 MW slipstream capture facility at Bellingham operated from 1991 to 2005 and captured 85% to 95% of the CO2 in the slipstream.

In Scotland, the proposed 900 MW Peterhead Power Station combined cycle power plant with CCS is in the planning stages and could capture 90% of its CO2 emissions.  

An 1,800 MW combined cycle unit in West Virginia is planned to use CCS and could enter service later this decade. EPA said its economic feasibility was partially credited to the expanded IRC section 45Q tax credit for sequestered CO2 provided through the IRA.

Hydrogen co-firing

EPA said that industrial combustion turbines have been burning byproduct fuels containing large percentages of hydrogen for decades. More recently, power sector combustion turbines in the have begun to co-fire hydrogen to generate electricity. 

EPA said that new utility combustion turbine models have demonstrated the ability to co-fire up to 30% hydrogen. It said developers are working toward models that will be ready to combust 100% hydrogen by 2030. It noted that several utilities already are co-firing hydrogen in test burns and some have announced plans to move to combusting 100% hydrogen in the 2035–2045 timeframe.

EPA pointed to the Los Angeles Department of Water and Power’s (LADWP) Scattergood Modernization project that includes plans to have a hydrogen-ready combustion turbine in place when the 346 MW combined cycle plant (potential for up to 830 MW) begins initial operations in 2029. LADWP foresees the plant running on 100% electrolytic hydrogen by 2035. 

In addition, LADWP also has an agreement in place to buy electricity from the Intermountain Power Agency project (IPA) in Utah. IPA is replacing an existing 1.8 GW coal- fired plant with an 840 MW combined cycle turbine that developers expect to initially co-fire 30% electrolytic hydrogen in 2025 and 100% hydrogen by 2045.

In Florida, NextEra Energy announced plans to operate 16 GW of existing natural gas-fired combustion turbines with electrolytic hydrogen as part of the utility’s Zero Carbon Blueprint to be carbon-free by 2045.

Duke Energy Corp., which operates 33 gas-fired plants across the Midwest, the Carolinas, and Florida, has outlined plans for full hydrogen capabilities throughout its future turbine fleet. EPA quoted a utility statement that said, “All natural gas units built after 2030 are assumed to be convertible to full hydrogen capability. After 2040, only peaking units that are fully hydrogen capable are assumed to be built.”

In addition to those utility announcements, several merchant generators operating in wholesale markets are also signaling their intent to ramp up hydrogen co-firing levels after initial 30% percent co-firing phases. 

The Cricket Valley Energy Center (CVEC) in New York is retrofitting its combined cycle power plant starting in 2022 as a first step toward the conversion to a 100% hydrogen fuel capable plant. 

The Long Ridge Energy Terminal in Ohio, which has co-fired a 5% hydrogen blend at its 485 MW combined cycle plant, said that its technology has the capability to transition to 100% hydrogen over time as its low-GHG fuel supply becomes available.

EPA also said that Constellation Energy also is exploring electrolytic hydrogen co-firing across its fleet. It estimated costs for blend levels in the range of 60-100% at around $100/kW for retrofits and noted that equipment manufacturers are planning 100% hydrogen combustion-ready turbines before 2030.

But hydrogen’s molecular makeup means that it produces nitrogen oxide (NOx) differently than methane-based natural gas.

Researchers have found that a standard method used across the industry to calculate NOx emissions from gas-fueled power plants can result in potentially big errors when applied to hydrogen as an energy source.

The error may complicate the case for introducing more hydrogen into the electric power generating mix.

The error first came to light a year ago in a monograph published by the researchers from Georgia Tech and the Electric Power Research Institute (EPRI). A more detailed paper from the team came out last summer, published by the American Society of Mechanical Engineers. And the results were highlighted in a session at the recently concluded POWERGEN International conference in Orlando.

In a nutshell, the research lays out the case that many studies are calculating NOx emissions incorrectly “by as much as 40% against high-hydrogen systems.”

The error could be a relatively simple one to fix, and likely would require environmental regulators to change how they evaluate hydrogen in comparison to other fuels.

The researchers noted out that subpart KKKK of the U.S. Environmental Protection Agency’s code lays out federal emissions limits for NOx and sulfur dioxide (SO2). They said that the primary source of NOx in most gas-fired systems is the ambient air itself. Air’s dominant parts (nitrogen and oxygen) react together under high-temperature conditions. And while one benefit of hydrogen is that its combustion releases no CO2, combusting H2 does generate NOx, a result of heating air to high temperatures.

For years in the U.S., air quality permits have been used to regulate and limit permissible emissions from power plants. In practice, these permitted levels have been based on what the researchers said is the net mass production of regulated pollutants. 

An overlooked correction

And here’s where a bit of chemistry and math are needed to understand the problem.

The researchers say that in evaluating emissions, the volumetric stack concentrations of pollutants–and not their actual mass production rates–are measured. These measurements are done using continuous NOx analyzers located at individual plants. 

As a result, work needs to be done to convert volumetric measurements (referred to in shorthand as ppmv) to a mass basis (referred to either as lb/MMBtu or lb/hr).

In their July 2022 paper the researchers wrote, “Quantifying such differences is not a difficult task, but the importance of doing so does not seem to be widely appreciated by the combustion community.” Part of the challenge, they said, is that the combustion community has “traditionally focused on relatively standardized fuels that display minimal variability.”

To help explain this, the researchers noted that gas turbine emission codes often define allowable fractions of exhausted NOx based on a standardized method for preparing samples. In this process, combustion products are sampled and the water is removed. The dry sample that results then is mathematically corrected to 15% O2 (for gas turbines) before measuring the NOx levels. 

This correction is done, the researchers said, in order to evenly evaluate systems with varying levels of excess air. In the United States, typical stack exit permits range from 3-30 ppmv at 15% O2. But—and this is a crucial point—the mathematical idea known as “the constant of proportionality” that exists between pollutants’ mass production and this measured ppmv value depends on what fuel is being analyzed.

This point is well known in the environmental community and typically is corrected by what is known in industry jargon as an “F-factor.”

Flame problem

In their longer ASME paper, the authors said the challenge associated with fuels that have a high percentage of hydrogen comes about in lean, premixed combustion systems. Modern dry low NOx combustors operate in a lean premixed regime. In this regime, the flame temperature can be controlled to minimize NOx production; the flames themselves are stabilized by balancing both flame propagation and flow velocity. 

But H2 flames behave very differently from CH4 flames. For one thing, H2 flames can have up to 10x higher flame speeds at a given equivalence ratio. For another, they can exhibit extreme sensitivity to what the researchers said were flame stretch and thermal-diffusive instability. Such effects cause H2-fueled systems to be more prone to flame flashback than their natural gas counterparts. 

What’s more, the effects also shift parameter regions where combustion instability occurs. That means that operational experience developed for natural gas systems need to be adjusted for fuels containing H2.

However, as work progresses to look at various low NOx combustion technologies, including hydrogen, this correction often is not applied. The researchers said that as a result, technology evaluations are “improperly comparing measured NOx ppmv emissions between one fuel and another.”

In particular, many evaluations directly compare NOx emissions from methane/hydrogen blends based on NOx ppmv concentration values. And while corrections are largely negligible for many fuels (such as between natural gas and diesel), corrections can be “very substantial” for hydrogen.

That’s because at conditions with equal power output, hydrogen/methane fuel blends result in combustion products that have higher proportions of H2O (water) and O2 (oxygen) than pure methane alone. So, even when mass production rates of NOx emissions are the same, systems that use more hydrogen will have higher composition-based value when reported in terms of ppmv at 15% O2.

That can be a problem for plants looking to use a blend of methane and hydrogen. In short, a volume-based (ppmv) measurement can erroneously indicate higher NOx emissions from H2-blended systems for the exact same mass of NOx as a methane-fired plant. The researchers pegged the correction at about 7% for a 50%/50% H2/CH4 blend; 17% for an 80%/20% blend; and 37% at 100% H2.

By comparison, similar corrections for other common fuels are “generally negligible,” the researchers said. A comparison between methane and diesel fuel yielded a correction of only around 2%.

American Electric Power named Stacey Burbure as VP, FERC and RTO strategy and policy. She replaces Amanda Conner, who now serves as chief of staff to Julie Sloat, AEP’s president and CEO. Burbure most recently was senior counsel, transmission policy and rates. Prior to joining AEP in 2019, Burbure served as senior counsel, focusing on transmission issues, for an investor-owned utility. Earlier, she was senior counsel to the North American Electric Reliability Corporation. She earned her bachelor’s degree from Swarthmore College and her law degree from George Washington University Law School.  The utility also named Emily J. Duncan as SVP, federal affairs. Duncan is currently VP of government relations for National Grid. She replaces Tony Kavanagh who will retire after more than 31 years with the company. Before joining National Grid in 2015, Duncan worked for the Solar Energy Industries Association. She is a graduate of the University of Pennsylvania and earned her law degree from Duke University.

Altus Power named Sophia Lee as its chief sustainability officer, in addition to her current role as the company’s chief legal officer. Lee joined the company in 2021 and has a Juris Doctorate from the New York University School of Law and a Bachelors of Science in Mechanical Engineering from the Massachusetts Institute of Technology.

Oglethorpe Power named Jeff Swartz as SVP, plant operations, reporting to EVP and COO David Sorrick. Swartz succeeds Jim Messersmith who retired after more than 31 years of service. Swartz previously was with New Fortress Energy. He has also held executive operations and management positions with Duke Energy. Swartz holds a Bachelor of Science in mechanical engineering from the U.S. Naval Academy and is a veteran of the U.S. Navy with engineering experience in nuclear power.

The Business Council for Sustainable Energy said that Allison Hull, director of federal government affairs at Sempra was elected chair of its board of directors. She succeeds National Grid US VP of government relations Emily Duncan. Hull has served as vice chair since 2016 and has more than 20 years of experience in the energy industry as a government relations professional and attorney. 

Vistra named Julie Lagacy as independent director to its board of directors. She will serve on the board’s Sustainability & Risk Committee and the Social Responsibility & Compensation Committee. Lagacy most recently served as Caterpillar’s first chief sustainability and strategy officer. 

The funding is part of the ARPA-E Seeding Critical Advances for Leading Energy technologies with Untapped Potential (SCALEUP) program, which provides further funding to previous ARPA-E teams that have been determined to be feasible for widespread deployment and commercialization domestically. SCALEUP selectees demonstrate a viable path to commercial deployment and the ability to attract private sector investments.

Quidnet Energy was launched to build energy technology to accelerate the energy transition. Quidnet Energy’s Geomechanical Pumped Storage (GPS) technology uses existing natural resources to store renewable energy over long durations and in large quantities. The company uses existing drilling and hydropower machinery supply chains, according to a release.

The main idea is to use excess renewable energy to pump water into the ground, between rock layers where the water would be kept under pressure. The natural elasticity of certain rock formations act like a spring and keep the water under pressure. When renewable energy is not available, the valve is opened and the water is released through a hydroelectric turbine to generate electricity. Quidnet said its technology is an adaptation of centuries-old gravity-powered pumped storage, but without the massive land requirements and reliance on elevated terrain.

The ARPA-E funding will support Quidnet Energy’s project with San Antonio-based CPS Energy. Quidnet Energy will scale its GPS to a 1 MW/10 MWh commercial system that will provide CPS Energy with 10-plus-hour long-duration energy storage. The project will support CPS Energy’s “Flexible Path” Resource Plan to reduce net emissions by 80% by 2040 while allowing Quidnet Energy to advance GPS from its current pilot scale to MW-scale commercial systems.

“We’re honored that ARPA-E has selected Quidnet Energy as an awardee of the SCALEUP program,” said Joe Zhou, chief executive officer of Quidnet Energy. “This funding will support continued work on our GPS project with CPS Energy, which will demonstrate the benefits of using proven pumped hydro technology to create a long-duration energy storage resource that doesn’t require mountainous terrain.”

U.S. Solar Photovoltaic System and Energy Storage Cost Benchmarks, With Minimum Sustainable Price Analysis: Q1 2022 details installed costs for PV and storage systems as of the first quarter (Q1) of 2022.

The report said that prices soared throughout the U.S. between Q1 2021 and Q1 2022 for the PV and energy storage markets in particular. The ongoing COVID-19 pandemic caused or complicated supply chain constraints, and industry-specific events and trade policies drove up PV and battery prices.

Such volatility poses a challenge for capturing representative PV and storage costs. NREL’s benchmark report, published annually since 2010, is meant to help the U.S. Department of Energy’s Solar Energy Technologies Office track long-term technology and soft cost trends. For this reason, NREL said the Q1 2022 report is the first to use two types of benchmarks to help distinguish the impacts of short-term market distortions from the impacts of longer-term technology trends.

Two benchmarks

The two types of benchmarks in the new report are the minimum sustainable price (MSP) and the modeled market price (MMP).

MSP is a theoretical national-average cash price under long-term market conditions. NREL said that for this report, MSP excluded short-term cost distortions impacting the market in Q1 2022. In contrast, the report’s MMP is an estimate of the national-average cash sales price under market conditions occurring in Q1 2022, consistent with NREL’s previous benchmarks.

The chart below provides an example comparing MSP and MMP for a residential PV system. Differences between the two benchmarks stem from different input parameters.

Taking each of the component costs in turn: For the PV module, MSP is based on an NREL MSP model and excludes tariffs and short-term supply/demand dynamics, whereas the module MMP, based on third-party analyst data, includes costs from tariffs and supply/demand market dynamics. The inverter MSP is based on an average cost trend (excluding distorted 2022 costs) and no tariff impacts, whereas the inverter MMP is based on 2022 costs with tariff impacts. Similarly, the balance of system (BOS) MSP is based on an average cost trend that excludes 2022 costs, and the BOS MMP is based on 2022 costs. Soft cost input parameters are the same for MSP and MMP.

Two ways to look at PV system price in 2022

The next chart shows NREL’s MSP and MMP PV benchmarks across the residential, commercial, and utility-scale sectors. Discrepancies between benchmark types are similar for all sectors, at 13%–15%, representing the impact of either excluding (MSP) or including (MMP) inflationary market and policy distortions. Although not shown in the chart, NREL said the differences between MSP and MMP are similar for standalone storage and PV-plus-storage systems.

MSP vs MMP for standalone PV systems in Q1 2022

Because the methods used to develop the 2022 MMP benchmarks are similar to the methods used to develop NREL’s benchmarks in 2021, many of those results can be compared across years. The Q1 2022 MMP PV, storage, and PV-plus-storage benchmarks are 2%–12% higher than comparable Q1 2021 benchmarks in real dollars. These differences, NREL said, could be considered estimates of the increase in national-average system sales prices between Q1 2021 and Q1 2022.

Industry data

The MSP and MMP benchmarks are both based on NREL’s ongoing collection of industry data and its bottom-up cost modeling. The data include representative PV and storage system specifications based on industry trends as well as feedback from stakeholders. This year, the report’s authors interviewed 21 stakeholders, including third-party research organizations; PV installers and integrators; engineering, procurement, and construction (EPC) developers; advocacy groups; intergovernmental organizations; and government agencies.

Bottom-up modeling accounts for all system and project development costs incurred during installation, including typical installation techniques and business operations. Hardware costs reflect the purchase price of components as well as the sales price paid to the installer, including profits. The results are broken down by cost category to illustrate which system components may be driving prices and to identify opportunities for price reductions.

From these same data and modeling approaches, the MSP and MMP benchmarks are differentiated by identifying cost distortions from short-term market and policy conditions and then including or excluding distorted cost inputs, as described above.

According to a new market report from the Solar Energy Industries Association (SEIA), commercial solar deployment totaled 1.7 GW between 2020 and 2021 with off-site projects accounting for more than three-quarters of that total.

But the combination of business factors, along with higher prices and tight supplies of labor and materials has led to project delays, particularly for off-site solar.

As a result, off-site installations through June were “far off the pace set in 2021,” SEIA said, with “many 2022 projects pushing operational dates to 2023 or later.”

Through the first half, less than 1.5 GW of new commercial solar capacity was added. For the full year of 2021, more than 5 GW of capacity was installed.

The slowdown is significant as SEIA said that of the 19 GW of corporate solar installed to date, more than half has been installed since 2020.

The industry trade group said that continued declines in the cost of solar have been a primary driver of commercial solar installations over the last decade. For on-site projects in its dataset, the price to install a commercial system has dropped by 51% since 2012. 

Pricing for off-site systems has also fallen, with PPA prices for all utility-scale projects in the $16 – $35/MWh range in recent years.

But, in a shift from those trends, commercial solar prices in two of the three size categories SEIA tracks have risen over the last year. It said that pricing for <100 kW and >1 MW systems are at their highest levels since 2019 and 2018, respectively.

It said that installers are seeing increased module pricing stemming primarily from regulatory trade actions that have reduced the availability of module imports and increased module pricing.

In addition, hardware costs have increased due to widespread inflation. Meanwhile labor costs have risen “significantly” due to higher demand and in line with what SEIA said are “structural changes in the U.S. labor force” brought on by the Covid-19 pandemic.

The report’s findings were based on system-level data from around 48,000 commercial solar systems, which it made up around 70% of the total installed capacity through June.

Growth in ground mounts

The report said that a majority of systems use roof mounting systems, but that ground mounts are becoming more common as system sizes increase. It said that around 23% of systems use ground mounting equipment, up from 16% at the end of 2018.

It also said that more than 94% of off-site corporate capacity uses single-axis trackers, in line with a decade-long trend away from fixed-tilt systems. Fixed-tilt systems are now used primarily in smaller off-site systems that lack the economies of scale to justify the additional expense of adding trackers.

Corporate leaders

Commercial solar now accounts for 14% of all installed solar capacity in the United States, according to the Solar Means Business 2022 report. It named Meta, Amazon, Apple, Walmart and Microsoft as the top five corporate solar users in America.

Meta increased its installed solar capacity from 177 MW in early 2019 to 3.6 GW. Target remained as the top onsite corporate solar user, while Microsoft joined the top 10 by installing 479 MW of new capacity since 2019.

The report said that Walmart’s set of on-site and off-site solar has kept the retailer in the top 5 for the last decade. Around 46% of its global electricity needs were supplied by renewable energy as of 2021.

The report said that companies like Intel, Google, Switch and Digital Realty are using solar energy at data center facilities. In addition, food and beverage companies like Ab Inbev and Starbucks, health care companies like Kaiser Permanente and DaVita, and other top brands like Home Depot and T-Mobile were named as top 25 corporate solar users.

The report also said that fully 2 GW of the 10 GW of off-site commercial solar is installed in Virginia, where demand by tech companies and data centers is driving much of the demand. The state’s leading commercial solar users included Meta, Amazon, Apple, Microsoft, and Digital Realty.

The report said that 23 U.S. companies have installed at least 100 MW of solar capacity, up from 11 companies in 2019. Eighteen of the top 25 companies ranked in the report are pursuing 100% renewable energy or carbon neutral goals.

Back to growth?

SEIA said that total commercial solar installations are expected to double again over the next three years with nearly 27 GW of off-site corporate solar projects scheduled to come online by 2025. This represents nearly a third of the total contracted solar pipeline.

The report said that third-party ownership remains popular despite lending practices that have improved in recent years. It said that increased underwriting costs often make commercial loan offerings less attractive than in the residential sector. It also said that many companies prefer to account for their electricity expense as an operating cost and not as a capital cost.

Even so, customer-owned systems have grown in market share from 52% in 2019 to 68% through the first half of 2022. It said that financiers have become more comfortable with the commercial solar space and that declining system costs have reduced the amount of capital expense associated with system ownership.

Siemens Energy said its overall fiscal year 2022 performance was held back by its Siemens Gamesa Renewable Energy (SGRE) unit. 

Christian Bruch, president and CEO of Siemens Energy, said that while the company’s gas and power business delivered “solid results,” Siemens Gamesa “did not meet expectations.”

New management has been put in place in the renewable business unit in an effort to rectify problems. And last spring, Siemens Energy announced a voluntary cash tender offer to acquire the roughly 33% of outstanding shares in Siemens Gamesa Renewable Energy which Siemens Energy does not already own. 

Starting on November 8, minority shareholders were given the option to tender their shares for €18.05 ($18.66) per share in cash until December 13. If the offer proves successful,  Siemens Energy would delist the business unit from the Spanish stock exchanges, where it currently trades as a member of the IBEX 35 index. 

Bruch said November 16 that the energy transition would fail unless the industry addressed issues currently facing the wind power sector.

In an interview with CNBC’s “Squawk Box Europe,” Bruch was quoted as saying, “Never forget, renewables like wind roughly, roughly, need 10 times the material [compared to] … what conventional technologies need.” 

He said supply chain problems can hit wind “extremely hard, and this is what we see.” Challenges facing the wind business “leads to the situation [where] … it impacts the overall group results substantially.”

The poor performance mirrored similar results reported by chief rival General Electric. In late October the industrial reported a bumpy third quarter across its renewable energy and power business segments. GE’s onshore wind turbine revenues came in at $2.445 billion for the quarter, which ended September 30. That was down from $3.047 billion for the same quarter a year earlier. For the first nine months of the year, onshore wind turbine revenue was $6.403 billion, down from $8.048 billion a year earlier. The GE business unit also plans to cut its global workforce by around 20% over the next several years.

Siemens Energy said that for its full fiscal year, revenues at its renewable business unit totaled €9.8 billion ($10.13 billion), down 7.5% from the €10.2 billion reported in 2021.

Fourth quarter revenue from the renewable energy segment rose 13.4% from the same period a year earlier. Revenue totaled nearly €3.4 billion ($3.52 billion), compared to nearly €2.9 billion a year earlier.

The U.S. Department of Justice and the Environmental Protection Agency reached settlement agreements with four separate solar farm owners in three states to resolve alleged Clean Water Act violations.

The alleged violations involved construction permit violations and stormwater mismanagement at large-scale solar generating facilities: a site near LaFayette, Alabama, owned by AL Solar A LLC; a site near American Falls, Idaho, owned by American Falls Solar LLC; a site in Perry County, Illinois, owned by Prairie State Solar LLC; and a site in White County, Illinois, owned by Big River Solar LLC. 

The states of Alabama and Illinois joined in the Alabama and Illinois settlements.

The four solar farm owners used a common construction contractor for the development of their solar farms, according to the settlement. Together, the four settlements secured a total of $1.34 million in civil penalties and are expected to ensure that remaining construction will take place in compliance with Clean Water Act stormwater permits. 

A search by Renewable Energy World of the D.E. Shaw Renewable Investments web site found details about the Illinois projects, and the consent decrees were distributed to that company’s general counsel. The company did not immediately respond to a request for comment.

The consent decree for AL Solar A was signed by the chief legal officer for Montreal-based Boralex whose web site also includes a solar project in Lafayette.

The settlement agreement with American Falls Solar named an asset management executive and the general counsel with Arizona-based renewable energy developer Arevon. The company’s web site includes two solar projects at American Falls, Idaho. Renewable Energy World asked for comment on the settlement but had not heard back prior to publication.

And a search showed that Swinerton/SOLV Energy provided engineering services for projects bearing the same names as those listed in the settlement agreement. A spokesperson for SOLV Energy did not immediately respond to a request for comment.

An EPA enforcement official said in a statement that the settlements “send an important message to the site owners of solar farm projects that these facilities must be planned and built in compliance with all environmental laws, including those that prevent the discharge of sediment into local waters during construction.”

Solar farm construction involves clearing and grading large sections of land, which EPA and DOJ said “can lead to significant erosion and major runoff of sediment” into waterways if site stormwater controls are inadequate. The agencies said that increased sediment in waterways can injure, suffocate or kill aquatic life; damage aquatic ecosystems; and harm drinking water treatment systems. 

Solar farm developers and contractors are required to get construction stormwater permits under the Clean Water Act and comply with the terms of those permits. 

Each of the complaints alleged that the owners of these four sites violated their construction stormwater permits in similar ways: failing to design, install, and maintain proper stormwater controls; failing to conduct regular site inspections; failing to employ qualified personnel to conduct inspections; and failing to accurately report and address stormwater issues at the site. 

The complaints filed against AL Solar and American Falls Solar also allege unauthorized discharges of excess sediment from their construction sites to nearby waterways.

Construction at the Idaho and Alabama sites is now complete and permit coverage has been terminated. As a result, the settlements only include civil penalties. 

The United States and the Alabama Department of Environmental Management (ADEM) filed a stipulation of settlement with AL Solar in the U.S. District Court for the Middle District of Alabama along with its complaint. Under that settlement, AL Solar will pay a $250,000 civil penalty to the United States and a $250,000 civil penalty to ADEM.

A second stipulation of settlement involving American Falls was filed in the U.S. District Court for the District of Idaho. Under that settlement, American Falls will pay a civil penalty of $416,500 to the United States. 

In addition, consent decrees with Prairie State and Big River were filed by the United States and the State of Illinois. Because both Illinois sites remain subject to Clean Water Act permits, these two settlements require the owners to ensure compliance with those permits until construction at the sites is complete and the United States and state agree that permit coverage can be terminated. 

In addition, Prairie State will pay a civil penalty of $157,500 to the United States and $67,500 to the state of Illinois, and Big River will pay a civil penalty of $122,500 to the United States and $52,500 to the state of Illinois. 

The consent decrees were lodged with the U.S. District Court for the Southern District of Illinois and are subject to a 30-day public comment period and final court approval. More information is available here.

This article was updated on November 18. Origis Energy was an early-stage developer of the Alabama project, but sold it prior to construction and was not a party to the federal complaint.

Data source: California Independent System Operator

Data analyzed by the Energy Department’s Energy Information Administration (EIA) show that California’s grid relied heavily on natural gas-fired generating resources during an early September heat wave. The share of electric power generated by nuclear, solar, wind, batteries, and other sources actually fell.

An extreme heat wave affected California the week of September 4, driving record-breaking demand for electricity to meet increased air-conditioning use. On September 6, a new record was set in the California Independent System Operator’s (CAISO) territory.

CAISO, the grid operator for most of the state, issued appeals for consumer energy conservation throughout the week, as well as Energy Emergency Alerts each day, to help reduce electricity demand and prevent rolling power outages.

Data from CAISO that was analyzed by EIA show that the grid predominately used natural gas, electricity imports, and hydroelectric sources during the highest demand hours to meet the record-breaking demand. That was a change from the typical mix.

EIA said that for “brief periods” during the week of September 4, CAISO used natural gas for as much as 60%—and never less than 30%—of the generation mix to meet electricity demand. The California grid typically uses a mix of solar, wind, imports, hydroelectric, and natural gas sources for electricity generation. The exact mix depends on the time of day, the availability of sources, and the price that power plants set to sell electricity to the grid.

This year, up to the record-setting demand week in September, CAISO’s generation mix included:

• 40% from solar, wind, nuclear, batteries, and other sources
• 32% from natural gas
• 20% from imports
• 7% from hydroelectric

The mix relies slightly more on natural gas during the evening hours from 6:00 p.m. to 9:00 p.m., when electricity demand peaks and solar generation wanes.

EIA said that during the week of September 4, however, natural gas contributed nearly one-half of the resource mix in CAISO; nuclear, solar, wind, batteries, and other resources decreased to a 24% share.

EIA said that natural gas units in California are often the last resource turned on to meet demand because they can be turned on after the sun sets in the evening when cooling demand remains high. When demand reaches record highs, seldom-used (less efficient, more expensive) natural gas units are needed to meet demand.

Data source: California Independent System Operator

\The U.S. Department of Energy announced $40 million in funding to advance the development and deployment of clean hydrogen technologies. In a related move, DOE also launched a $20 million university research consortium to help states and Tribal communities implement grid resilience programs and achieve decarbonization goals.

This funding opportunity is intended to advance DOE’s Hydrogen Shot goal of reducing the cost of clean hydrogen to $1 per 1 kilogram in a decade (the so-called “1 1 1” goal), while supporting DOE’s H2@Scale initiative, which aims to advance the affordable production, transport, storage, and use of clean hydrogen.

Topic areas include projects that will develop technologies for solar fuels created by harvesting sunlight, improve hydrogen-emissions detection and monitoring, demonstrate higher-density and lower-pressure hydrogen storage technologies, and lower the costs and enhance the durability of hydrogen fuel cells for medium- and heavy-duty transportation applications.

DOE said it envisions multiple financial assistance awards in the form of cooperative agreements, with the period of performance being roughly two to four years. DOE said it encourages applicant teams that include academia, industry, and national laboratories across multiple technical disciplines.

The Hydrogen Shot and University Research Consortium Grid Resilience FOA also provides three-year funding for a university consortium focused on developing a decarbonized and more resilient electrical power system in coordination with universities in Mexico and Canada. DOE said this approach would be “critical to addressing cross-border grid dependencies” and electrical interconnections throughout region.

The application process for both the clean hydrogen FOA and University Consortium funding is expected to include two phases: a concept paper and a full application. Concept papers are due on September 23. Full applications are due on December 1. More information is available here.