Alabama Power is paying less for power generated by third-party energy producers and imposing a cost for those companies to connect to its electricity grid.

The rule was approved by the Alabama Public Service Commission (PSC) in March; took effect in April and applies to companies that can generate at least 100 kilowatts of electricity.

Alabama Power said in an emailed statement the rates are updated each year, based on fuel costs and inflation, to keep prices as affordable as possible.

The company also said in a separate statement that the new integration cost is part of the monthly energy payment that the company pays to energy providers who are not Alabama Power customers.

Critics allege that the maneuvers are meant to stamp out competition in the market for electricity, especially for solar power providers looking to gain a foothold in the central and southern parts of the state and compete with Alabama Power.

“It is 100% about control,” said Steve Cicala, associate professor of economics at Tufts University, whose work focuses on the economics of regulation, particularly with respect to environmental and energy policy. “They are a business — and they don’t want competition.”

Daniel Tait, executive director for Energy Alabama, an advocacy group that hopes to increase renewable energy generation in the state, said Alabama Power was “trying to protect their monopoly, first and foremost.”

“It doesn’t really matter about the energy source,” he said. “Solar is just the one that is the most economical and the one most likely to challenge that monopoly, so that is why you see the fight on solar.”

The Alabama Public Service Commission said in a statement that the rate adjustments are appropriate based on the figures that Alabama Power provided.

“The cost is driven by the magnitude of the intermittency of certain generation, which requires additional operating reserves to maintain reliability on our system,” Alabama Power said in its email.

But some experts say the intermittency argument is overstated.

“We have gotten really good at predicting solar and wind output,” said Brendan Pierpont, director for electricity modeling for Energy Innovation, a nonpartisan energy and environment think tank. “These are large-scale industries in the U.S. and there are many gigawatts of wind and solar being developed each year.”

Both Energy Alabama and the Southern Renewable Energy Association, another group that promotes the responsible use of alternative energy, sought to challenge the PSC’s ruling, but the PSC officially denied their request in a written order on July 22.

Tait said Energy Alabama has decided not to challenge the order in court and will wait until the following year, should Alabama Power request a rate update or rule change with the PSC.

The Southern Renewable Energy Association said it is still considering its options.

Solar charges

The most recent rule changes limit revenues for larger renewable energy companies with power-producing plants. Those are separate from the households and smaller solar-producing companies that also generate electricity.

“The utilities have been lobbying for this for a long time,” said Gilbert Michaud, assistant professor with the School of Environmental Sustainability at Loyola University Chicago. “Utilities are having more competition in their sandbox, and they are saying, ‘We really don’t want more distributed solar generation because folks will buy less power from us. But we still have to maintain all our power plants and the grid infrastructure.’”

Brendan Pierpont, director for electricity modeling for Energy Innovation, a nonpartisan energy and environment think tank. said the ruling would discourage third parties from investing in renewable energy projects.

“While every solar project has different economic requirements, lowering the price a solar project receives or adding additional fees likely means fewer projects will get built, less investment in communities that would host those projects, few jobs in building those projects, etc,” he wrote in an email. “If the price received by a solar project is lower than the cost of operating Alabama Power’s own power plants, that’s also a missed opportunity for the utility’s electric customers to save money.”

The grid

Alabama Power, the largest utility in the state, has nearly 1.5 million customers and provides electricity to 57% of all customers in Alabama, according to a 2020 report published by the Southeast Energy Efficiency Alliance.

In February, Alabama Power filed a document with the PSC, the state’s electricity regulator, that proposed cutting the rates they pay for third-party electrical generation, known as a Contract for Purchased Energy (CPE), by up to 50%. In one category, the price decreased from about 7.33 cents per kilowatt hour to about 3.65 cents per kilowatt hour.

Those figures are formulated through a model and the values are estimated. That can be subjective, according to Pierpont of Energy Innovation.

“What they do is estimate low avoided costs, so they don’t have to pay very much,” Pierpont said. “In the meantime, they’re running coal plants and gas plants that cost quite a bit more than the rate they would be paying under this type of contract.”

Throughout the country, Pierpont said, power distribution companies like Alabama Power have been working to reduce the amount they pay homeowners who contribute electricity back to the grid through rooftop solar panels.

In addition to the lower rate payments, Alabama Power introduced a Variable Integration Cost at $0.00193 per kilowatt hour for third-party companies. That would further reduce the revenue that those firms receive for energy purchased by Alabama Power.

Pierpont found a few examples of utility companies imposing an integration cost to connect to the system. One is PacifiCorp, an energy company that operates in several western states, and the second is Duke, which is in the Carolinas.

“This approach seems fairly rare and limited to regions without competitive electricity markets,” Pierpont wrote in an email.

Significant costs

Energy Alabama published a blog post in June alleging that the charges, which it called a tax, would amount to a $250,000 annual charge for an 80-megawatt solar farm based in Montgomery.

The updated rates, along with the integration cost, are separate from the charges that Alabama Power imposes on individual households who install solar to offset their electricity bill.

In 2012, the PSC approved an Alabama Power request to impose a $5 per kW Capacity Reservation Charge (CRE) on customers with solar panels, often known as a rooftop fee. Typically, households that generate about 5 kW on their solar array will pay about $300 annually, or $9,000 over the 30-year expected lifespan of the system.

That charge has since increased to $5.41.

Power companies in other states have been allowed to impose such charges, including Arizona. Michaud, at Loyola University in Chicago, estimates that residents in almost a third of all the states in the country must pay such a fee. Michaud said the fees are clustered “in more conservative states, like the U.S. South.”

This makes it less economical for households to install solar panels for their homes because they make up the upfront fixed cost of the system from the savings generated from their power bills, and lengthens the time needed to recoup the cost of the system.

“It is basically killing your payback period, or at least increasing it,” Michaud said. “I would do this in my class, and a lot of students find, ‘Hey, this increases the payback period from 10 years to 14 years.’ You are having folks paying for a longer time.”

‘Intermittency of certain generation’

For its part, Alabama Power said the rate adjustments to third-party energy providers, also known as the CPE, and newly imposed integration cost, are necessary for maintaining price stability for customers.

“Rate CPE keeps electricity costs stable for customers by ensuring Alabama Power pays a fair price for energy,” the company said in an emailed statement. “This approach, updated annually, protects customers from unexpected price shocks linked to fluctuating energy production costs.”

The company said that the Variable Integration Cost is not a fee and is factored into the calculation that Alabama Power pays third-party producers who are not customers of Alabama Power and who sell all their output to the company.

“The cost is driven by the magnitude of the intermittency of certain generation, like solar, which requires additional operating reserves to maintain reliability on our system,” the company said.

When electricity is in high demand, electricity third-party providers contribute is highly valuable. The power becomes less valuable very late in the evening or very early in the morning, the times when people are asleep, not very active, and have no need for electricity. Smoothing out the supply when the need is uncertain is a tricky question to answer.

Timothy Charles Lieuwen, a professor of engineering at Georgia Tech University, said that over time, the price power distribution companies have been willing to pay to third parties who generate energy has declined.

“It is a really hard question, what is the value of the power they (third party energy providers) are providing,” he said.

Power distribution companies, including vertically integrated ones such as Alabama Power, are less willing to purchase power from other companies in the face of that mounting uncertainty about when customers will need that energy.

The Public Service Commission deferred to Alabama Power in an emailed statement.

“The adjustments to Rate CPE (Contract for Purchased Energy) were found to be in the public interest because they accurately reflected Alabama Power Company’s most current projected avoided cost,” the statement said. “Alabama Power’s projected avoided costs are updated annually. The variable integration charge was approved because it mitigates the cost incurred with integrating the intermittent output of QFs (Qualifying Facilities) onto the Southern Company System.”

The Public Service Commission said in its statement that allegations that it gave Alabama Power more control over the electricity production market were not valid.

“The matters approved in the Commission’s March 5, 2024 Order in Docket U-5213 were designed to accurately establish the projected avoided cost rates for CPE and to allow for the recovery of the cost incurred by Alabama Power in integrating the intermittent output of QFs onto the Southern Company System,” the statement said.

Tait called Alabama Power’s claims about intermittency “absurd.”

“Basically, what Alabama Power is saying when they say something like that is, ‘Our engineers are dumber than everybody else’s engineers and they can’t figure this out,’” Tait said. “Alabama Power’s engineers are just as smart, and just as talented, as everybody else is.”

Alabama Reflector is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Alabama Reflector maintains editorial independence. Contact Editor Brian Lyman for questions: info@alabamareflector.com. Follow Alabama Reflector on Facebook and X.

A major expansion of battery storage may be the most economical and environmentally beneficial way for Illinois to maintain grid reliability as it phases out fossil fuel generation, a new study finds.

The analysis was commissioned by the nonprofit Clean Grid Alliance and solar organizations as state lawmakers consider proposed incentives for private developers to build battery storage.

“The outlook is not great for bringing on major amounts of new capacity to replace the retiring capacity,” said Mark Pruitt, former head of the Illinois Power Agency and author of the study, which suggests batteries will be a more realistic path forward than a massive buildout of new generation and transmission infrastructure. 

The proposed legislation — SB 3959 and HB 5856 — would require the Illinois Power Agency to procure energy storage capacity for deployment by utilities ComEd and Ameren. Payments would be based on the difference between energy market prices and the costs of charging batteries off-peak, to ensure the storage would be profitable. The need for incentives would theoretically ratchet down over time. 

“As market prices for power go up, your incentive goes down,” Pruit said. “The idea is to provide an incentive that bridges the gap between the cost of battery technology and the value in the market. Over time, those will equalize and level out.” 

The bills, introduced in May at the end of the legislature’s spring session, would amend existing energy law to add energy storage incentives to state policy, along with existing incentives for nuclear and renewables. 

The study noted that Illinois will need at least 8,500 new megawatts of capacity and possibly as much as 15,000 new megawatts between 2030 and 2049, with increased demand driven in part by the growth of data centers. Twenty-five data centers being proposed in Illinois would use as much energy as the state’s five nuclear plants generate, according to nuclear plant owner Exelon’s CEO Calvin Butler Jr., quoted by Bloomberg. 

The North American Electric Reliability Corporation (NERC) found in its summer and winter 2024 assessments that within MISO and PJM regional grids, Wisconsin, Michigan, Minnesota, Illinois and Indiana are all at “elevated” risk of insufficient capacity. 

“NERC, PJM, MISO and the Illinois Commerce Commission have all identified the potential for capacity shortfalls,” said Pruitt. “You do have some options for alleviating that. You can build transmission and bring in capacity from outside the state. You can maintain your current domestic generating capacity [without retiring fossil fuel plants]. You could expand your domestic generating capacity. And an independent variable is your growth rate. All these have to work together, there’s no silver bullet. We know there are major challenges on each of those fronts.” 

Gloomy numbers 

The latest PJM capacity auction results showed capacity prices increasing from $28.92/MW-Day for the 2024/25 period to $269.92/MW-Day — a nearly 10-fold increase — for the following year. That “translates into an annual cost increase of about $350 for a typical single-family household served by ComEd,” Pruitt said. “The increase in costs indicates that more capacity supply is required to meet capacity demand in the future.” 

There are many new generation projects in the queue for interconnection by MISO and PJM, but many of them drop out before ever being deployed because of unviable economics, long delays, regulatory challenges and other issues. A recent study by Lawrence Berkeley National Laboratory noted that while interconnection requests for renewables have skyrocketed since the Inflation Reduction Act, only 15% of interconnected capacity was actually completed in PJM and MISO between 2000 and 2018, and experts say similar completion rates persist. 

“This finding indicates that deploying sufficient new capacity resources to offset [fossil fuel] retirements is not likely to occur in the near term,” said Pruitt. “Just because something is planned doesn’t mean it gets built.” 

Meanwhile the state is running out of funds for the purchase of renewable energy credits (RECs) that are crucial to driving wind and solar development. The 2024 long-term renewable resources procurement plan by the IPA shows the state’s fund for renewables reaching a deficit in 2028, so that spending on RECs from renewables will have to be scaled back by as much as 60%. 

Long-distance transmission lines could bring wind energy or other electricity from out of state. But planned transmission lines have faced hurdles. The Grain Belt Express transmission line, in the works for a decade, was in August denied needed approval from an Illinois appellate court. The transmission line, proposed by Invenergy, would have brought wind power from Kansas to load centers to the east. 

“That sets it back years,” Pruitt said. “Transmission is a very long-term solution. I’m sure people are working diligently on it, but it’s five to 10 years before you get something approved and built.” 

Value proposition, solar benefits 

Pruitt’s study found that if 8,500 MW of energy storage were deployed between 2030 and 2049, Illinois customers could see up to $3 billion in savings compared to if they had to foot the bill for increased capacity without new storage. The savings would come because of lower market prices in capacity auctions, as well as investment in new transmission and generation that would be avoided. 

Pruitt found that $11 billion to $28 billion in macro-level economic benefits could also result, with blackouts avoided, reduced fossil fuel emissions and jobs and economic stimulus created. 

Pruitt’s analysis indicates that the incentives proposed in the legislation would cost $6.4 billion to customers. But the storage would result in $9.4 billion in savings compared to the status quo, hence a $3 billion overall savings between 2030 and 2049. 

“Solar is great, but solar is an intermittent resource; battery storage when paired with solar allows it to be far more reliable,” said Andrew Linhares, Central Region senior manager for the Solar Energy Industry Association. “Battery storage is not as cheap as solar, but its reliability is its hallmark. Combining the resources gives you a cheap and reliable resource.” 

“Solar and storage is this powerful tool that can help reduce costs for consumers and create new jobs and economic activity,” he continued. “I don’t believe that same picture is there for building out new natural gas resources. Anything that helps storage, helps solar and vice versa. CEJA sees these two technologies as being joined at the hip for the future, they are being seen more and more as a single resource.”

This article first appeared on Energy News Network and is republished here under a Creative Commons license.

Data centers being rapidly built in the West are becoming an “emerging risk” to electrical grid reliability in the region, according to regional transmission experts. 

New data centers, which can be built in as little as 18 months, are far outpacing the growth in new electrical energy supply and transmission, according to members of the Western Electricity Coordinating Council, a nonprofit organization based in Salt Lake City that ensures grid connection and reliability between utilities in 14 western states and parts of Canada and Mexico. Members of the council discussed challenges to grid reliability at a recent webinar first reported by the trade publication RTO Insider. 

In it, council members said new energy demand from data centers has emerged as a more prescient challenge than meeting energy demand for transportation, also becoming rapidly electrified. The energy and transmission buildout needed to meet these demands is lagging, they said. By the end of 2023, just about half of the new energy buildout anticipated for the West had been completed. This is due in large part to supply chain issues, prices and skilled labor shortages, according to Branden Sudduth, the commission’s vice president of reliability planning. 

There are more than 700 data centers within those 14 states, including 109 in Oregon, according to the company Data Center Map, and there are more than 5,000 data centers throughout the U.S. according to Statista – the most for any single country in the world. 

Oregon’s data center market is the fifth largest in the nation, according to Chicago-based commercial real estate group Cushman & Wakefield. Amazon, Apple, Facebook, Google and X, formerly named Twitter, have massive data centers in eastern Oregon as well as in The Dalles, Hillsboro and Prineville that require enormous amounts of energy to operate. Amazon is planning to build at least 10 more data centers in eastern Oregon, according to reporting by The Oregonian/OregonLive.

“We’re going to see an industry that wants to come online quickly with very large loads, and how are we going to address that?” Sudduth said.

The council in 2023 projected that demand for electricity in the West would increase about 17% by 2033 – that’s about twice what it had predicted just the year before. That leap in projected energy use is due largely to the number of large data centers being built, they said. Data centers run on large amounts of energy needed for processing and for cooling servers.

The Portland-based industry trade group Pacific Northwest Utilities Conference Committee has projected electricity demand to grow 30% in the region in the next decade, also due in large part to data centers. 

Another major challenge to grid reliability discussed was extreme weather. Sudduth said more energy sources and transmission would need to be developed both at the local level and across the region to ensure a reliable electricity supply.

“Pretty much since the August 2020 heat wave event, the weather patterns that we’re experiencing are different from what we’ve typically planned for in the past. A lot of the weather events are more widespread and they last a lot longer than they have in the past,” Sudduth said.

A growing number of utilities in Oregon and Washington are joining a new western regional market for buying and selling energy from one another at set prices for the day ahead, so that they can better handle demand spikes during extreme weather events, such as heat waves or ice storms. The Bonneville Power Administration – responsible for about 28% of all power consumed in the Northwest – is expected to announce soon whether it will join most other Western utilities in this Western day ahead market, or go to a competing day ahead market run by the Southwest Power Pool, based in Arkansas.

Oregon Capital Chronicle is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Oregon Capital Chronicle maintains editorial independence. Contact Editor Lynne Terry for questions: info@oregoncapitalchronicle.com. Follow Oregon Capital Chronicle on Facebook and X.

An array of critics came out swinging in January when Duke Energy first filed its plans in North Carolina for one of the largest fossil fuel investments in the country.  

But as the months have dragged on in the development of the company’s biennial carbon-reduction plan, some notable detractors have relented. 

Just before expert witness testimony was set to begin in Raleigh late last month, the state-sanctioned ratepayer advocate, Public Staff, and Walmart endorsed a settlement with Duke on its blueprint, which includes building 9 gigawatts of new natural gas plants that the utility says could be converted to run on hydrogen in the future.

A few days later, the Carolinas Clean Energy Business Association, a consortium of solar and wind developers, announced it had signed on too.  

The agreement, which contains some small concessions from the utility, led to low-key hearings that ended in less than two weeks. It makes it more likely that Duke will get what it wants from regulators by year’s end, including a greenlight, if not final approval, for three large new natural gas plants in the near term.

Chris Carmody, executive director of the Carolinas Clean Energy Business Association, says the proposed compromise also helps lock in forward progress on solar energy and batteries, however incremental. 

“It’s a more aggressive solar spend. It’s a more aggressive storage spend,” he said. “Certainly, we would like to see more. But first of all, we like to see it going in the right direction.” 

Clean energy advocates believe Duke’s push for new gas plants will harm the climate, since the plants’ associated releases of planet-warming methane will cancel out any benefits of reduced carbon pollution from smokestacks. At the same time, they say the investments could become useless by midcentury or sooner, before their book life is over, saddling ratepayers with costs that bring no benefits.

“There’s not much in it for their customers except unnecessary risk, cost, and more pollution,” Will Scott, southeast climate and clean energy director for the Environmental Defense Fund, wrote in a blog last month. 

But Duke’s gas bubble has proved hard to burst. For one, the company’s predictions of massive future demand from new data centers are based in part on confidential business dealings that are challenging to rebut from the outside. 

Unlike two years ago, when Duke proposed its first carbon reduction plan, no groups produced an independent model showing how Duke could meet demand without building new gas. 

“We can talk about costs, or market conditions,” said Carmody. But, he said, “we did not do any modeling.”

Public Staff ran its own numbers and has urged more caution on new gas plants than Duke proposes. But the agency is unwavering that at least some are needed.

New Biden administration rules haven’t yet proved the death knell for gas that some expected. Duke is suing to overturn the rule, but it insists that building new plants that will run at half capacity is the most economical plan for compliance.

And even as Duke is proffering more gas, it’s also undeniably proposing more solar.

Clean energy backers still object to annual constraints on solar development the utility says are necessary. But the limits have increased from less than 1,000 megawatts per year in 2022 to over 1,300 megawatts. And the settlement would result in another 240 megawatts of solar than Duke had first proposed.

“It’s an iterative improvement,” said Carmody. 

What’s more, the settlement opens a discussion with Duke about the scores of 5-megawatt solar projects across the state whose initial contracts will soon expire. A proposal for how to refit them could come in April of next year. 

“This is a really important issue to our members,” said Carmody.  “These are projects that could be repowered. They could be upgraded with storage. They could have significantly more efficient solar technology than was on them 15 or 20 years ago.” 

Still, Carmody said his group tried to word the settlement in a way that left room for clean energy advocates to continue to advocate for less gas and steeper emissions cuts sooner — and that’s certainly their plan. 

“Three power plants that will be really expensive to build and then operate for only a few years is just a ridiculous proposal,” the settlement notwithstanding, said Maggie Shober, research director for the Southern Alliance for Clean Energy. 

“We remain hopeful that there’s a lot that the [commission] can do in this carbon plan proceeding and in their final order, to move us forward on a clean energy trajectory.”

Nick Jimenez, senior attorney for the Southern Environmental Law Center, acknowledges the settlement stacks the deck somewhat against his clients. 

“Historically, the commission approves a lot of settlements,” he said. “It likes to see parties settle, especially when Duke and the Public Staff are involved.”

This article first appeared on Energy News Network and is republished here under a Creative Commons license.

Vineyard Wind said it has obtained federal approval to resume construction of the wind farm – work that was suspended following the partial collapse of a previously installed turbine blade on July 13.

A press release issued at 7 a.m. Tuesday morning said the Bureau of Safety and Environmental Enforcement had given the developers of the wind farm permission to resume the installation of towers and nacelles (which sit atop the tower and convert wind energy into electricity), but a suspension remains in effect for turbine blades and power generation.

Vineyard Wind is a 62-turbine project and only 24 had been completed at the time of the accident. Work is resuming on the remaining 38 turbines but blades cannot be installed nor power produced under the terms of the revised suspension order. Of the 24 completed turbines, 11 were generating electricity at the time of the incident and 13, including the one that broke, were undergoing testing.

In a joint press release, Vineyard Wind and GE Vernova, the manufacturer of the wind turbines, said a barge departed the New Bedford Marine Commerce Terminal Tuesday morning for the wind farm carrying turbine components, including several tower sections and one nacelle.

“The vessel will also carry a rack of three blades solely for the purpose of ensuring safe and balanced composition for the transport,” the press release said, adding that the blades will not be installed and will be returned to New Bedford later in the week.  

The press release said the Bureau of Safety and Environmental Enforcement revised its suspension order after examining records and a structural load analysis conducted by a third party. The federal agency had no mention of a revised suspension order on its website Tuesday morning.

Vineyard Wind and GE Vernova also said “a substantial amount” of what remained of the damaged blade was cut away on Sunday and Monday.

“During the operations, Vineyard Wind and GE Vernova mobilized maritime crews on multiple vessels nearby to secure as much debris as possible for immediate containment and removal as well as land-based crews managing debris recovery,” the press release said. ”Vineyard Wind and GE Vernova are currently assessing next steps to complete any additional cutting necessary at the earliest opportunity, secure and remove the debris on the turbine platform, remove the blade root, and address the debris on the seabed.”

The blade incident at Vineyard Wind, a joint venture of Avangrid and Vineyard Offshore, has been a major setback for the first industrial scale wind farm in the United States. Foam and fiberglass from the turbine has washed up on Nantucket and other beaches on the Cape and Martha’s Vineyard and raised questions about wind energy at a time when the industry is trying to ramp up production.

A preliminary investigation by GE Vernova has suggested the blade breakdown was caused by a “manufacturing deviation” – specifically insufficient bonding of the blade materials. The company has indicated no problems with the design of the Haliade-X blade, which is 853 feet tall.

It was unclear when Nantucket officials were notified about the resumption of construction of the wind farm. Updates posted on the town website indicated the Select Board was aware of the efforts beginning on Sunday to remove more of the damaged turbine blade.

During an executive session on Thursday, the Select Board met to discuss “strategy with respect to potential litigation in connection with Vineyard Wind,” according to the agenda.

This article first appeared on CommonWealth Beacon and is republished here under a Creative Commons license.

In their Q3 2024 results, the company announced an improved cash outlook, citing increasing demand for their grid and gas turbine businesses. Gas Services’ orders more than doubled year-over-year.

Specifically, Siemens Energy reports a new record for their order backlog at €120 billion ($131 billion) and revenue growth of 18.5%, with substantial growth in Grid Technologies, Transformation of Industry and Siemens Gamesa.

Commenting in a release, Siemens Energy’s president and CEO Christian Bruch attributed the positive backlog to increases in global energy consumption, which has resulted in demand and growth for their businesses.

Last year, the German government assisted with a counter-guarantee to support the company after their net loss of €4.5 billion ($5 billion) for the 2023 fiscal year, primarily due to the company’s ailing wind division, Siemens Gamesa.

For Q3 this year, the company reported a net loss of €102 million ($111.3 million).

Said Bruch: “The rapidly growing electricity market requires a wide range of our products. Especially our grid and gas turbine businesses are benefiting from this momentum.

“Importantly, with growing our order backlog, we have been able to improve its margin quality as well. Despite all the challenges, we are optimistic about the future and after the first nine months, we are well on track to meet our full-year guidance.”

Looking ahead, the company expects to achieve comparable revenue growth of 10 to 12% and free cash flow pre tax in a range of €1 billion ($1.1 billion) to €1.5 billion ($1.6 billion) for the fiscal year.

Said Bruch during a press conference call: “…quarter by quarter, we’re making headway. It’s not exciting, but it’s what we want to achieve.

“We expect that the global demand for power will continue to grow in addition to population growth and more electrification.”

Additionally, stated Bruch, new markets are opening up with the potential for growth: “New additional markets contribute to this. One topic, which is currently discussed everywhere is the power need for data centers – they make up a considerable part of our inquiries.

“And for the future, this means potential growth.”

Originally published by Power Engineering International.

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Problem: Steam turbines generate most of the world’s electricity, and approximately 42% in the US_[1]. Keeping them in operation is vital. Condensation in the low-pressure stage can result in corrosion pitting and corrosion fatigue. These failure mechanisms are two of the most common factors impacting repair and operating expenses. When cracks begin forming at the site of these mechanisms, the component, often a blade, must be replaced. Between the actual component replacement cost and the downtime required, the replacement process can cost millions of dollars. Sometimes replacement blades are new, but they’re often refurbished blades that have been weld-repaired and returned to service. This leads to the recurrence of many failures as condensation and resulting corrosion damage usually form in the same areas_[2].  

The primary way to address corrosion damage is by minimizing the chance of it forming. Martensitic stainless steels are often utilized in the production of parts because of the mild corrosion resistance offered by chromium_[3]. Coatings are commonly applied to provide further resistance. Shallow compression is provided by shot peening. Operators attempt to control the chemistry of the vapors entering the steam turbines to minimize impurities_[4]. All of these efforts offer protection, albeit with some disadvantages. Resistance through material selection is mild. Coatings wear over time and eventually require re-application. Surface damage can easily penetrate the relatively shallow layer of compression provided by shot peening. Ridding the vapors of impurities is challenging and offers no guarantee that corrosion will not still form.

Solution: Engineered compression has been proven to significantly improve the damage tolerance of many materials and components. This study examines the use of deep-engineered compression to combat corrosion pitting and corrosion fatigue in Alloy 450, a martensitic stainless steel widely employed in steam turbine blade manufacturing.

Specimen Design

Fatigue specimens were specially designed to test the benefits of compressive residual stress in 4-point bending. Samples were finished machined using low stress grinding (LSG). To simulate surface damage from any source (handling, FOD, corrosion pitting, or erosion), a semi-elliptical surface notch with a depth of a_o = 0.01 in. (0.25 mm) and surface length of 2c_o = 0.06 in. (1.5 mm) was introduced by electrical discharge machining (EDM). EDM produces a pre-cracked recast layer that is in residual tension at the bottom of the notch, producing a large fatigue debit with a high k_f.

Processing

Low plasticity burnishing (LPB®) was selected to impart the engineered compression due to the depth and stability of compression, as well as the ease of application. Process parameters were developed to impart a depth and magnitude of compression on the order of 0.04 in. (1 mm), sufficient to mitigate the simulated damage. Figure 1 shows a set of eight fatigue specimens in the process of being low plasticity burnished on the four-axis manipulator in a CNC milling machine.

Testing

Active corrosion fatigue tests were conducted in an acidic salt solution containing 3.5 wt% NaCl (pH = 3.5). At the start of cyclic loading, filter papers soaked with the solution were wrapped around the gauge section of the fatigue test specimen and sealed with a polyethylene film to avoid evaporation. There was no exposure to the corrosive solution before the fatigue tests. LPB and LSG baseline samples were tested with and without EDM damage. A few LPB samples were tested with increased damage levels of 2x to analyze the treatment’s effectiveness with deeper damage.

X-ray diffraction residual stress measurements were made to characterize the residual stress distribution from LPB. The results of these measurements are shown in Figure 2. Maximum compression is nominally -140 ksi (-965 MPa) at the surface, decreasing to zero over a depth of about 0.035 in. (0.89 mm). The corrosion fatigue performance in acidic NaCl solution is shown in Figure 3. The LSG baseline condition is compared with LPB with and without the EDM notch. With no notch, the baseline fatigue strength at 10⁷ cycles is nominally 100 ksi (689 MPa). The 0.01 in. (0.25 mm) deep EDM notch decreases the baseline fatigue strength to approximately 10% of its original value. The fatigue lives at higher stresses show a corresponding decrease of over an order of magnitude resulting from the notch. Unnotched LPB processed samples have a fatigue strength of about 160 ksi (1100 MPa). The notch had a marginal effect on the LPB fatigue strength, reducing it to 125 ksi (862 MPa), well above the fatigue strength of the undamaged baseline specimens. LPB-treated samples containing the 2x damage depth had fatigue lives comparable to undamaged LSG specimens within the limits of experimental scatter.

Conclusion

LPB imparted highly beneficial compressive residual stresses on the surface, sufficient to withstand pitting and/or surface damage up to a depth of nominally 0.02 in. (0.51 mm). LPB resulted in more than a 50% increase in corrosion fatigue strength without surface damage and a 12x increase in strength with 0.01 in. (0.25 mm) deep damage. The depth and magnitude of surface compression are responsible for improving fatigue strength.

The application of LPB effectively enhances corrosion damage tolerance, as shown by the improved fatigue strength even in the presence of simulated damage. The process has been used successfully in many power applications since the early 2000s. Implementing engineered compression with LPB significantly improves the durability and performance of steam turbine components, ultimately reducing costs associated with maintenance and downtime.

References

[1] US Energy Information Administration, “How Electricity is Generated.” https://www.eia.gov/energyexplained/electricity/how-electricity-is-generated.php October, 2023.

[2] R. Ravindranath, N. Jayaraman & P. Prevey, “Fatigue life Extension of Steam Turbine Alloys Using Low Plasticity Burnishing (LPB).” Proceedings of ASME Turbo Expo 2010: Power for Land, Sea and Air. Glasgow, UK, June 14-18, 2010.

[3] A. Rivaz, S.H. Mousavi Anijdan, M. Moazami-Goudarzi, “Failure Analysis and Damage Causes of a Steam Turbine Blade of 410 Martensitic Stainless Steel After 165,000 H of Working.” Engineering Failure Analysis, Volume 113, 2020.

[4] Zhou, S, Turnbull, A, “Steam Turbine Operating Conditions, Chemistry of Condensates, and Environment Assisted Cracking – A Critical Review.” NPL Report MATC (A) 95, May, 2002.

About the Author: As Research Engineer for both the Surface Integrity and Process Optimization (SIPO) laboratory and the Corrosion Characterization laboratory at Lambda Research, Kyle Brandenburg is part of a team responsible for providing materials testing solutions to clients. Additionally, the SIPO and Corrosion labs conduct in-house research and testing pertaining to the surface enhancement and optimization of materials and components. Laboratory capabilities include high and low cycle fatigue studies, DC electrochemical corrosion testing, stress corrosion cracking, and supporting capabilities like hardness testing, heat treating, SEM and metallographic analysis, and shot peening.

kbrandenburg@lambdatechs.com

www.lambdatechs.com

With coal plants retiring, the intermittent availability of renewable solar and wind energy, and data centers and artificial intelligence capabilities expanding, it’s clear that the U.S. is in need of reliable energy sources. Utilities face the complex challenge of firming capacity to continue to provide consistent services. 

Dispatchable, reliable power is crucial, but several obstacles complicate the issue, including the limited availability for procurement of gas turbines and gas engine-driven compressors; limitations of regional gas capacity; unpredictability of weather that can affect the availability of renewable energy sources, and the lengths of permitting processes. Understanding where greater energy capability is needed and what solutions might be available is the first step. There are a variety of options available to help firm capacity.

Compressor Stations

Compressor stations are facilities located along natural gas pipelines that compress the gas to maintain pressure and provide for continuous gas flow at the required delivery points. Increasing the number of compressor stations, or upgrading existing ones, can enhance the capacity and reliability of a natural gas network system. This is particularly useful in regions where the gas supply might be constrained.

While new compressor stations and pipelines face many regulatory hurdles, such stations offer a reliable solution to improve natural gas delivery. The increased capacity that comes with using compressor stations can help meet rising power demands without the need for entirely new pipelines.

Dual Fuel

Dual fuel systems allow power plants to switch between natural gas and an alternative fuel, typically diesel or oil. This flexibility can be invaluable during times of gas supply constraints or price spikes. A dual fuel system provides an immediate backup fuel source, allowing for continuous power generation.

Such systems enhance reliability and operational flexibility, reduce the risk of power outages and enable effective management of fuel costs. The systems may also require additional storage and handling facilities for the secondary fuel, which can drive up costs related to implementing the solution.

LNG Peak Shavers

LNG peak shavers are facilities that store liquefied natural gas (LNG) and can quickly vaporize and inject it into a natural gas pipeline during peak demand periods. These facilities produce LNG during periods of low natural gas demand, such as the summer months, allowing utilities to manage the cost of gas and power for customers. LNG peak shavers provide a buffer during periods of high demand, keeping the gas supply steady even when demand spikes unexpectedly.

The benefits that LNG can provide with a continuous gas supply during peak periods and enhanced system stability are hard to ignore. LNG can be stored and vaporized in a stand-alone facility, either connected to a pipeline or directly feeding an existing power generation station. If stored and vaporized in a stand-alone facility, the LNG is delivered via trucks rather than produced on-site.

Hydrogen

Hydrogen can be used as a fuel for power generation, either blended with natural gas or used in dedicated hydrogen turbines. Hydrogen is often a clean energy source that can significantly reduce greenhouse gas emissions. Hydrogen also can come from various sources, including renewable solutions, providing a versatile and sustainable option.

Hydrogen currently has high production costs and requires significant infrastructure development before operations can begin. However, the solution offers the hope for greater energy security through the diversification of fuel sources and the possibility of long-term energy sustainability.

Meeting the Demand

Firming generation in the face of changing power demands and shifting energy landscapes requires innovative solutions and strategic planning. Compressor stations, dual fuel systems, LNG peak shavers and hydrogen each offer unique benefits and challenges. By carefully considering these options, utilities can enhance stability and reliability while meeting the growing energy needs of the future.

Originally published by Burns & McDonnell.

About the Author: Sara O’Dell, PE, is an associate project engineer with nearly 20 years of engineer-procure-construct (EPC) project execution experience, spending the last 15 years working on LNG projects using both liquefaction and regasification processes for onshore and floating installations.