Allegheny Energy settles Merrill Lynch litigation

By Knight Ridder Tribune


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Allegheny Energy Inc. has agreed to pay Merrill Lynch & Co. Inc. $50 million in exchange for the securities firm's 2 percent interest in the power company's generation business to settle a lawsuit.

The settlement ends five years of litigation between the two companies over Allegheny Energy's $490 million purchase in 2001 of Merrill's energy trading business. Allegheny Energy said Merrill will turn over its 2 percent interest in Allegheny Energy Supply LLC, in exchange for a $50 million payment. All litigation and claims associated with the case will be dismissed.

In 2001, Allegheny Energy, hoping to cash in on what then was a burgeoning energy trading business led by Enron Corp., purchased Merrill's Global Energy Markets operation, and gave the securities firm a 2 percent stake in its Allegheny Energy Supply LLC.

One year later, Merrill sued Allegheny Energy over $115 million the securities firm claimed it still was owed from the deal. Allegheny Energy countersued, alleging Merrill had misrepresented the trading operation's revenue. Allegheny Energy said Merrill wanted to sell its trading business because it was run by a manager who lied about its finances.

The manager, Daniel Gordon, helped build Merrill's trading business and later headed the unit after Allegheny Energy acquired it. He pleaded guilty to fraud in 2003 and was sentenced to 42 months in prison for embezzling $43 million while he was working at Merrill.

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Idaho gets vast majority of electricity from renewables, almost half from hydropower

Idaho Renewable Energy 2018 saw over 80% in-state utility-scale power from hydropower, wind, solar, biomass, and geothermal, per EIA, with imports declining as Snake River Plain resources and Hells Canyon hydro lead.

 

Key Points

Idaho produced over 80% in-state power from renewables in 2018, led by hydropower, wind, solar, and biomass.

✅ Hydropower supplies about half of capacity; Hells Canyon leads.

✅ Wind provides nearly 20% of capacity along the Snake River Plain.

✅ Utility-scale solar surged since 2016; biomass and geothermal add output.

 

More than 80% of Idaho’s in-state utility-scale electricity generation came from renewable resources in 2018, behind only Vermont, according to recently released data from the U.S. Energy Information Administration’s Electric Power Monthly and broader trends showing that solar and wind reached about 10% of U.S. generation in the first half of 2018.

Idaho generated 17.4 million MWh of electricity in 2018, of which 14.2 million MWh came from renewable sources, while nationally January power generation jumped 9.3% year over year according to EIA. Idaho uses a variety of renewable resources to generate electricity:

Hydroelectricity. Idaho ranked seventh in the U.S. in electricity generation from hydropower in 2018. About half of Idaho’s electricity generating capacity is at hydroelectric power plants, and utility actions such as the Idaho Power settlement could influence future resource choices, and seven of the state’s 10 largest power plants (in terms of electricity generation) are hydroelectric facilities. The largest privately owned hydroelectric generating facility in the U.S. is a three-dam complex on the Snake River in Hells Canyon, the deepest river gorge in North America.

Wind. Nearly one-fifth of Idaho’s electricity generating capacity and one-sixth of its generation comes from wind turbines. Idaho has substantial wind energy potential, and nationally the EIA expects solar and wind to be larger sources this summer, although only a small percentage of the state's land area is well-suited for wind development. All of the state’s wind farms are located in the southern half of the state along the Snake River Plain.

Solar. Almost 5% of Idaho’s electricity generating capacity and 3% of its generation come from utility-scale solar facilities, and nationally over half of new capacity in 2023 will be solar according to projections. The state had no utility-scale solar generation as recently as 2015. Between 2016 and 2017, Idaho’s utility-scale capacity doubled and generation increased from 30,000 MWh to more than 450,000 MWh. Idaho’s small-scale solar capacity also doubled since 2017, generating 33,000 MWh in 2018.

Biomass. Biomass-fueled power plants account for about 2% of the state’s utility-scale electricity generating capacity and 3% of its generation, contributing to a broader U.S. shift where 40% of electricity came from non-fossil sources in 2021. Wood waste from the state’s forests is the primary fuel for these plants.

Geothermal. Idaho is one of seven states with utility-scale geothermal electricity generation. Idaho has one 18-MW geothermal facility, located near the state’s southern border with Utah.

EIA says Idaho requires significant electricity imports, totaling about one-third of demand, to meet its electricity needs. However, Idaho’s electricity imports have decreased over time, and Georgia's recent import levels illustrate how regional dynamics can vary. Almost all of these imports are from neighboring states, as electricity imports from Canada accounted for less than 0.1% of Idaho’s total electricity supply in 2017.

 

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Nearly $1 Trillion in Investments Estimated by 2030 as Power Sector Transitions to a More Decarbonized and Flexible System

Distributed Energy Resources (DER) are surging as solar PV, battery storage, and demand response decarbonize power, cut costs, and boost grid resilience for utilities, ESCOs, and C&I customers through 2030.

 

Key Points

DER are small-scale, grid-connected assets like solar PV, storage, and demand response that deliver flexible power.

✅ Investments in DER to rise 75% by 2030; $846B in assets, $285B in storage.

✅ Residential solar PV: 49.3% of spend; C&I solar PV: 38.9% by 2030.

✅ Drivers: favorable policy, falling costs, high demand charges, decarbonization.

 

Frost & Sullivan's recent analysis, Growth Opportunities in Distributed Energy, Forecast to 2030, finds that the rate of annual investment in distributed energy resources (DER) will increase by 75% by 2030, with the market set for a decade of high growth. Favorable regulations, declining project and technology costs, and high electricity and demand charges are key factors driving investments in DER across the globe, with rising European demand boosting US solar equipment makers prospects in export markets. The COVID-19 pandemic will reduce investment levels in the short term, but the market will recover. Throughout the decade, $846 billion will be invested in DER, supported by a further $285 billion that will be invested in battery storage, with record solar and storage growth anticipated as installations and investments accelerate.

"The DER business model will play an increasingly pivotal role in the global power mix, as highlighted by BNEF's 2050 outlook and as part of a wider effort to decarbonize the sector," said Maria Benintende, Senior Energy Analyst at Frost & Sullivan. "Additionally, solar photovoltaic (PV) will dominate throughout the decade. Residential solar PV will account for 49.3% of total investment ($419 billion), though policy moves like a potential Solar ITC extension could pressure the US wind market, with commercial and industrial solar PV accounting for a further 38.9% ($330 billion)."

Benintende added: "In developing economies, DER offers a chance to bridge the electricity supply gap that still exists in a number of country markets. Further, in developed markets, DER is a key part of the transition to a cleaner and more resilient energy system, consistent with IRENA's renewables decarbonization findings across the energy sector."

DER offers significant revenue growth prospects for all key market participants, including:

  • Technology original equipment manufacturers (OEMs): Offer flexible after-sales support, including digital solutions such as asset integrity and optimization services for their installed base.
  • System integrators and installers: Target household customers and provide efficient and trustworthy solutions with flexible financial models.
  • Energy service companies (ESCOs): ESCOs should focus on adding DER deployments, in line with US decarbonization pathways and policy goals, to expand and enhance their traditional role of providing energy savings and demand-side management services to customers.

Utility companies: Deployment of DER can create new revenue streams for utility companies, from real-time and flexibility markets, and rapid solar PV growth in China illustrates how momentum in renewables can shape utility strategies.
Growth Opportunities in Distributed Energy, Forecast to 2030 is the latest addition to Frost & Sullivan's Energy and Environment research and analyses available through the Frost & Sullivan Leadership Council, which helps organizations identify a continuous flow of growth opportunities to succeed in an unpredictable future.

 

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Disruptions in the U.S. coal, nuclear power industries strain the economy and invite brownouts

Electric power market crisis highlights grid reliability risks as coal and nuclear retire amid subsidies, mandates, and cheap natural gas; intermittent wind and solar raise blackout concerns, resilience costs, and pricing distortions across regulated markets.

 

Key Points

Reliability and cost risks as coal and nuclear retire; subsidies distort prices; intermittent renewables strain grid.

✅ Coal and nuclear retirements reduce baseload capacity

✅ Subsidies and mandates distort market pricing signals

✅ Intermittent renewables increase blackout and grid risk

 

Is anyone paying any attention to the crisis that is going on in our electric power markets?

Over the past six months at least four major nuclear power plants have been slated for shutdown, including the last one in operation in California. Meanwhile, dozens of coal plants have been shuttered as well — despite low prices and cleaner coal. Some of our major coal companies may go into bankruptcy.

This is a dangerous game we are playing here with our most valuable resource — outside of clean air and water. Traditionally, we've received almost half our electric power nationwide from coal and nuclear power, and for good reason. They are cheap sources of power and they are highly resilient and reliable.

The disruption to coal and nuclear power wouldn't be disturbing if this were happening as a result of market forces. That's only partially the case.

#google#

The amazing shale oil and gas revolution is providing Americans with cheap gas for home heating and power generation. Hooray. The price of natural gas has fallen by nearly two-thirds over the last decade and this has put enormous price pressure on other forms of power generation.

But this is not a free-market story of Schumpeterian creative destruction. If it were, then wind and solar power would have been shutdown years ago. They can't possibly compete on a level playing field with $3 natural gas.

In most markets solar and wind power survive purely because the states mandate that as much as 30 percent of residential and commercial power come from these sources. The utilities have to buy it regardless of price, even as electricity demand is flat in many regions. What a sweet deal. The California state legislature just mandated that every new home spend $10,000 on solar panels on the roof.

Well over $100 billion of subsidies to big wind and big solar were doled out over the last decade, and even with the avalanche of taxpayer subsidies and bailout funds many of these companies like Solyndra (which received $500 million in handouts) failed, underscoring why a green revolution hasn't materialized as promised.

These industries are not anywhere close to self sufficiency. In 2017 amid utility trends to watch the wind industry admitted that without a continuation of a multi-billion tax credit, the wind turbines would stop turning.

This combines with the left's war on coal through regulations that have destroyed coal plants in many areas. (Thank goodness for the exports of coal or the industry would be in much bigger trouble.)

Bottom line: Our power market is a Soviet central planner's dream come true and it is extinguishing our coal and nuclear industries.

 

Why should anyone care?

First, because government subsidies, regulations and mandates make electric power more expensive. Natural gas prices have fallen by two-thirds, but electric power costs have still risen in most areas — thanks to the renewable mandates.

More importantly, the electric power market isn't accurately pricing in the value of resilience and reliability. What is the value of making sure the lights don't go off? What is the cost to the economy and human health if we have rolling brownouts and blackouts because the aging U.S. grid doesn't have enough juice during peak demand.

Politicians, utilities and federal regulators are shortsightedly killing our coal and nuclear capacities without considering the risk of future energy shortages and power disruptions. Once a nuclear plant is shutdown, you can't just fire it back up again when you need it.

Wind and solar are notoriously unreliable. Most places where wind power is used, coal plants are needed to back up the system during peak energy use and when the wind isn't blowing.

The first choice to fix energy markets is to finally end the tangled web of layers and layers of taxpayer subsidies and mandates and let the market choose. Alas, that's nearly impossible given the political clout of big wind and solar.

The second best solution is for the regulators and utilities to take into account the grid reliability and safety of our energy. Would people be willing to pay a little more for their power to ensure against brownouts? I sure would. The cost of having too little energy far exceeds the cost of having too much.

A glass of water costs pennies, but if you're in a desert dying of thirst, that water may be worth thousands of dollars.

I'll admit I'm not sure what the best solution is to the power plant closures. But if we have major towns and cities in the country without electric power for stretches of time because of green energy fixation, Americans are going to be mighty angry and our economy will take a major hit.

When our manufacturers, schools, hospitals, the internet and iPhones shut down, we're not going to think wind and solar power are so chic.

If the lights start to go out five or 10 years from now, we will look back at what is happening today and wonder how we could have been so darn stupid.

 

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Calgary's electricity use soars in frigid February, Enmax says

Calgary Winter Energy Usage Surge highlights soaring electricity demand, added megawatt-hours, and grid reliability challenges driven by extreme cold, heating loads, and climate change, with summer air conditioning also shifting seasonal peaks.

 

Key Points

A spike in Calgary's power use from extreme cold, adding 22k MWh and testing reliability as heating demand rises.

✅ +22,000 MWh vs Feb 2018 amid fourth-coldest February

✅ Heating loads spike; summer A/C now drives peak demand

✅ Grid reliability monitored; more solar and green resources ahead

 

February was so cold in Calgary that the city used enough extra energy to power 3,400 homes for a whole year, echoing record-breaking demand in B.C. in 2021 during severe cold.

Enmax Power Corporation, the primary electricity utility in the city, says the city 's energy consumption was up 22,000 megawatt hours last month compared with Februray 2018.

"We've seen through this cold period our system has held up very well. It's been very reliable," Enmax vice-president Andre van Dijk told the Calgary Eyeopener on Friday. "You know, in the absence of a windstorm combined with cold temperatures and that sort of thing, the system has actually held up pretty well."

The past month was the fourth coldest in Calgary's history, and similar conditions have pushed all-time high demand in B.C. in recent years across the West. The average temperature for last month was –18.1 C. The long-term average for February is –5.4 C.

 

Watching use, predicting issues

The electricity company monitors demand and load on a daily basis, always trying to predict issues before they happen, van Dijk said, and utilities have introduced winter payment plans to help customers manage bills during prolonged cold.

One of the issues they're watching is climate change, and how extreme temperatures and weather affect both the grid's reliability, as seen when Quebec shattered consumption records during cold snaps, and the public's energy use.

The colder it gets, the higher you turn up the heat. The hotter it is, the more you use air conditioning.

He also noted that using fuels then contributes to climate change, creating a cycle.

​"We are seeing variations in temperature and we've seen large weather events across the continent, across the world, in fact, that impact electrical systems, whether that's flooding, as we've experienced here, or high winds, tornadoes," van Dijk said.

"Climate change and changing weather patterns have definitely had had an impact on us as an electrical industry."

In 2012, he said, Calgary switched from using the most power during winter to using the most during summer, in large part due to air conditioning, he said.

"Temperature is a strong influencer of energy consumption and of our demand," van Dijk said.

Christmas tree lights have also become primarily LED, van Dijk said, which cuts down on a big energy draw in the winter.

He said he expects more solar and other green resources will be added into the electrical system in the future to mitigate how much the increasingly levels of energy use impact climate change, and to help moderate electricity costs in Alberta over time.

 

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Europe's stunted hydro & nuclear output may hobble recovery drive

Europe 2023 Energy Shortfall underscores how weak hydro and nuclear offset record solar and wind, tightening grids as natural gas supplies shrink and demand rebounds, heightening risks of electricity shortages across key economies.

 

Key Points

A regional gap as weak hydro and nuclear offset record solar and wind, straining supply as gas stays tight.

✅ Hydro and nuclear output fell sharply in early 2023

✅ Record solar and wind could not offset the deficit

✅ Industrial demand rebound pressures limited gas supplies

 

Shortfalls in Europe's hydro and nuclear output have more than offset record electricity generation from wind and solar power sites over the first quarter of 2023, leaving the region vulnerable to acute energy shortages for the second straight year.

European countries fast-tracked renewable energy capacity development in 2022 in the wake of Russia's invasion of Ukraine last February, which upended natural gas flows to the region and sent power prices soaring.

Europe lifted renewable energy supply capacity by a record 57,290 megawatts in 2022, or by nearly 9%, according to the International Energy Agency (IRENA), amid a scramble to replace imported Russian gas with cleaner, home-grown energy.

However, steep drops in both hydro and nuclear output - two key sources of non-emitting energy - mean Europe's power producers have limited ways to lift overall electricity generation, as the region is losing nuclear power at a critical moment, just as the region's economies start to reboot after last year's energy shock.

POWER PLATEAU
Europe's total electricity generation over the first quarter of 2023 hit 1,213 terawatt hours, or roughly 6.4% less than during the same period in 2022, according to data from think tank Ember.

At the same time, European power hits records during extreme heat as plants struggle to cool, exacerbating supply risks.

As Europe's total electricity demand levels were in post-COVID-19 expansion mode in early 2022 before Russia's so-called special operation sent power costs to record highs amid debates over how electricity is priced in Europe, it makes sense that overall electricity use was comparatively stunted in early 2023.

However, efforts are now underway to revive activity at scores of European factories, industrial plants and production lines that were shuttered or curtailed in 2022, so Europe's collective electricity consumption totals are set to trend steadily higher over the remainder of 2023.

With Russian natural gas unavailable in the previous quantities due to sanctions and supply issues, Europe's power producers will need to deploy alternative energy sources, including renewables poised to eclipse coal globally, to feed that increase in power demand.

And following the large jump in renewable capacity brought online in 2022, utilities can deploy more low-emissions energy than ever before across Europe's electricity grids.

 

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E.ON to Commission 2500 Digital Transformer Stations

E.ON Digital Transformer Stations modernize distribution grids with smart grid monitoring, voltage control, and remote switching, enabling bidirectional power flow, renewables integration, and rapid fault isolation from centralized grid control centres.

 

Key Points

Remotely monitored grid nodes enhancing smart grid stability and speedier fault response.

✅ Real-time voltage and current data along feeders and laterals

✅ Remote switching cuts outage duration and truck rolls

✅ Supports renewables and bidirectional power flows

 

E.ON plans to commission 2500 digital transformer stations in the service areas of its four German distribution grid operators - Avacon, Bayernwerk, E.DIS and Hansewerk - by the end of 2019. Starting this year, E.ON will solely install digital transformer stations in Germany, aligning with 2019 grid edge trends seen across the sector. This way, the digital grid is quite naturally being integrated into E.ON's distribution grids.

With these transformer stations as the centrepiece of the smart grid, it is possible to monitor and control using synchrophasors in the power grid from the grid control centre. This helps to maintain a more balanced utilisation of the grid and, with increasing complexity, ensures continued security of supply.

Until now, the current and voltage parameters required for safe grid operation could usually only be determined at the beginning of a power line, where there is usually a grid substation in place. Controlling current flow and voltage in the downstream system was physically impossible.

In the future, grids will have to function in both directions: they will bring electricity to the customer while at the same time collecting and transmitting more and more green electricity via HVDC technology where appropriate. This requires physical data to be made available along the entire route. To ensure security of supply, voltage fluctuations must be kept within narrowly defined limits and the current flow must not exceed the specified value, while reducing line losses with superconducting cables remains an important consideration. To manage this challenge, it is necessary to install digital technology.

The possibility of remotely controlling grids also reduces downtimes in the event of faults and supports a smarter electricity infrastructure approach. With the new technology, our grid operators can quickly and easily access the stations of the affected line. The grid control centres can thus limit and eliminate faults on individual line sections within a very short space of time.

 

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