Deepwater Wind Eyeing Massachusetts’ South Coast for Major Offshore Wind Construction Activity

Kemper County power plant costs and delays highlight lignite coal gasification, syngas production, carbon capture targets, and looming rate plans as Mississippi Power navigates Public Service Commission oversight and shareholder-ratepayer risk.

Key Points

Costs exceed $7.5B with repeated delays; rate impacts loom as syngas, lignite, and carbon capture systems mature.

✅ Estimate tops $7.5B; customers could fund about $4.3B

✅ Carbon capture target: 65% CO2 via syngas from lignite

✅ Rate plans pending before the Public Service Commission

A Mississippi utility on Monday delayed making proposals for how its customers should pay for an ever-more-expensive power plant, even as the estimated cost of the facility crossed $7.5 billion.

The Kemper County power plant will be tasked with mining lignite coal a few hundred yards away from the plant. That coal is moved through a process that will convert it to syngas. The syngas is then used to drive the energy output of the plant, and the resulting electricity is then moved into the grid, where transmission projects influence regional reliability and capacity.

Thomas Fanning, CEO of parent Southern Co., told shareholders in May that Mississippi Power would file rate plans for its Kemper County power plant this month. But still unable to operate the plant steadily enough to declare it finished, Mississippi Power punted, instead asking to hold rates level for 11 months to pay off costs that have already been approved by regulators.

Mississippi Power says it now hopes to reach commercial operation in June. The plant is more than three years behind schedule, with 10 delays announced in the past 18 months. It was originally supposed to cost $2.9 billion.

The company also said monday that it will have to replace troublesome parts of the facility much sooner than expected, including units that cool the synthetic gas produced from soft lignite coal by two gasifier units, plus ash handling systems in the gasifiers.

Kemper is designed to take synthetic gas, pipe it through a chemical plant to remove carbon dioxide and other chemicals, and then burn the gas in turbines to generate electricity. It’s designed to capture 65 percent of carbon dioxide from the coal, releasing only as much of the climate-warming gas as a typical natural gas plant. It’s a key effort nationally to maintain coal as a viable fuel source, even as coal unit retirements proceed in other states.

Mississippi Power raised its estimate of Kemper’s cost by $209.4 million, with shareholders absorbing $185.9 million, while ratepayers could be asked to pay $23.5 million. Overall, customers could be asked to pay $4.3 billion. Southern shareholders have agreed to absorb $3.1 billion, which has risen by $500 million since November.

The elected three-member Public Service Commission in 2015 allowed the company to raise rates on its 188,000 customers by $126 million a year. That paid for $840 million in Kemper work, which began generating electricity in 2014 using piped-in natural gas. Some items covered by that 15 percent rate increase will be paid off in coming months, but Mississippi Power now proposes to repay costs from regulatory proceedings earlier than originally projected.

In testimony filed with the Public Service Commission, Mississippi Power Chief Financial Officer Moses Fagin said that keeping rates level would reduce whiplash to customers when rates rise later to pay for Kemper, would pay off accumulated costs more quickly and would help the company wean itself off financial support from Southern Co. while maintaining credit ratings and positioning for a possible bond rating upgrade over time.

“Cash flow is important to the company in maintaining its current ratings and beginning to rebuild its credit strength on a more independent basis apart from the extraordinary parental support that has been required in recent years to maintain financial integrity,” Fagin testified.

Spokesman Jeff Shepard said Mississippi Power is still drawing up two rate plans — one requiring a sharp, immediate rate increase, and a “rate mitigation plan” that might cushion increases amid declining returns in coal markets. He said the company isn’t sure when it will file them. Fagin suggested the Public Service Commission set a new deadline of March 2, 2018.

Related News

• Electricity Forum News

• Power Generation News

Electric Vehicle Market Growth accelerated as EV adoption hit 2 million in 2016, per IEA, led by China, Tesla momentum, policy incentives, charging infrastructure buildout, and diesel decline under Paris Agreement goals.

Key Points

EV adoption rose to 2 million in 2016, driven by policy, China, and charging buildout, yet still only 0.2% of cars.

✅ 2M EVs on roads in 2016; 60% YoY growth

✅ China led with >40% of global EV sales

✅ Policies target 30% share by 2030 via EVI

The number of electric vehicles on the road rocketed to 2 million in 2016 as the age of electric cars accelerates after being virtually non-existent just five years ago, according to the International Energy Agency.

Registered plug-in and battery-powered vehicles on roads worldwide rose 60% from the year before, according to the Global EV Outlook 2017 report from the Paris-based IEA. Despite the rapid growth, electric vehicles still represent just 0.2% of total light-duty vehicles even as U.S. EV sales continue to soar into 2024, suggesting a turning point.

“China was by far the largest electric car market, accounting for more than 40% of the electric cars sold in the world and more than double the amount sold in the United States,” the IEA wrote in the report published Wednesday. “It is undeniable that the current electric car market uptake is largely influenced by the policy environment.”

A multi government program called the Electric Vehicle Initiative on Thursday will set a goal for 30% market share for battery power cars, buses, trucks and vans by 2030, aligning with projections that driving electric cars within a decade could become commonplace, according to IEA. The 10 governments in the initiative include China, France, Germany, the UK and US.

India, which isn’t part of the group, said last month that it plans to sell only electric cars by the end of the next decade. Countries and cities are looking to electric vehicles to help tackle their air pollution problems.

In order to limit global warming to below 2 degrees Celsius (3.6 degrees Fahrenheit), the target set by the landmark Paris Agreement on climate change, the world will need 600 million electric vehicles by 2040, according to the IEA.

After struggling for consumer acceptance, Tesla Inc. has made electric vehicles cool and trendy, and is pushing into the mass market as the United States approaches a tipping point for mass adoption with the new Model 3 sedan.

Consumer interest and charging infrastructure, as well as declining demand for diesel cars in the wake of Volkswagen’s emissions scandal, has spurred massive investments in plug-in cars, and across Europe the share of electric cars grew during virus lockdown months, reinforcing this momentum. An electrical vehicle “cool factor” could spur sales to 450 million by 2035, according to BP chief economist Spencer Dale.

Volkswagen, the world’s largest automaker, plans to roll out four affordable electric vehicles in the coming years as part of a goal to sell more than 2 million battery-powered vehicles a year by 2025. Mercedes-Benz accelerated the introduction of ten new electric vehicles by three years to 2022 to take on Tesla as the dominance of the combustion engine gradually fades. 

Related News

• Electricity Forum News

• EV Infrastructure News

Alberta Electricity Rate Cap shields RRO customers with a 6.8 cents/kWh price ceiling, stabilizing power bills amid capacity market transition, using carbon tax funding to offset spikes and enhance consumer protection from volatility.

Key Points

A four-year 6.8 cents/kWh ceiling on Alberta's RRO power price, backed by carbon tax to stabilize bills.

✅ Applies to RRO customers from Jun 2017 to May 2021

✅ Caps rates at 6.8 cents/kWh; lower RRO still applies

✅ Funded by carbon tax when market prices exceed cap

The Alberta government introduced a bill Tuesday, part of new electricity rules that will allow it to place a cap on regulated electricity rates for the next four years.

The move to cap consumer power rates at a maximum of 6.8 cents per kilowatt-hour for four years was announced in November 2016 by Premier Rachel Notley, although it was later scrapped by the UCP during a subsequent policy shift.

The cap is intended to protect consumers from price fluctuations from June 1, 2017, to May 31, 2021, as the province moves from a deregulated to a capacity power market amid a power market overhaul that is underway.

The price ceiling will apply to people with a regulated rate option. If the RRO is below 6.8 cents, they will still pay the lower rate.

The government isn't forecasting price fluctuations above 6.8 cents in this four-year period. If the price goes above that amount, funding would come from the carbon tax if required.

Funding may come from carbon tax

"We're taking a number of steps to keep prices low," said Energy Minister Marg McCuaig-Boyd. "But in the event that prices were to spike, the cap would automatically prevent the energy rate from going over 6.8 cents to give Albertans even more peace of mind." 

The government isn't forecasting price fluctuations above 6.8 cents in this four-year period. If the price goes above that amount, funding would come from the carbon tax.

McCuaig-Boyd said this would be an appropriate use for the carbon tax as the cap helps Albertans move to a greener energy system and change how the province produces and pays for electricity without relying as much on coal-fired electricity. 

The government estimates the program will cost $10 million a month for each cent the rate goes above 6.8 cents per kilowatt-hour. If rates remain below that amount, the program may not cost anything.

Wildrose electricity and renewables critic Don MacInytre said the move shows the government expects retail electricity rates will double over the next four years. 

MacIntyre argued a rate cap simply shifts increasing electricity costs away from consumers to the Alberta government. But ultimately everyone pays. 

"It's simply a shift of a burden from the ratepayer to the taxpayer, which is essentially the same person," he said. 

The City of Medicine Hat runs its own electrical system without a regulated rate option. The government will talk with the city to see if it is interested in taking part in the price cap protection.

About 60 per cent of eligible Albertans or one million households use the regulated rate option in their electricity contracts.

The current regulated rate option averages less than three cents per kilowatt-hour.

Related News

• Electricity Forum News

• Energy Policy News

California Natural Gas Plant Rethink signals a shift toward clean energy, renewables, distributed solar, battery storage, and grid modernization as LADWP and regulators pause repowering plans amid an electricity oversupply and rising ratepayer costs.

Key Points

California pauses new gas plants to assess renewables, storage, and grid solutions for reliability.

✅ LADWP delays $2.2B gas repowers to study clean alternatives

✅ CEC weighs halting Oxnard plant amid grid oversupply

✅ Distributed solar, batteries, demand response boost reliability

California energy officials are, for the first time, rethinking plans to build expensive natural gas power plants in the face of an electricity glut and growing use of cleaner and cheaper energy alternatives.

The Los Angeles Department of Water and Power announced Tuesday that it has put a hold on a $2.2-billion plan to rebuild several old natural gas power plants while it studies clean energy alternatives to meet electricity demands. And the California Energy Commission may decide as early as Thursday to halt a natural gas project in Ventura County.

The scrutiny comes after an investigation found that the state is operating with an oversupply of electricity, driven largely by the construction of gas-fueled generating plants, leading to higher rates as regulators consider a rate overhaul to clean the grid. The state’s power plants are on track to be able to produce at least 21% more electricity than needed by 2020, according to the Times report.

Californians are footing a $40-billion annual bill while using less electricity, paying $6.8 billion more than they did in 2008 when power use in the state was at its all-time high. Electricity consumption has since fallen and remained largely flat.

Utilities in California have been on a years-long building binge, adding new natural gas plants even as the nation’s electricity system has undergone significant change, including consumer choice reforms that are reshaping the market.

Where utilities once delivered all electrical services from huge power plants along miles of transmission lines, the industry now must consider power delivered to the electric grid not only from its own sources, but also from solar systems and batteries at homes and businesses.

At the same time, utilities have been aggressively upgrading or rebuilding their aging natural gas plants — a move critics have said is unnecessary because consumers are using less power and clean energy technology is making those plants obsolete.

The DWP and energy commission moves involve as many as seven natural gas plant projects proposed for Southern California, despite warnings about a looming shortage if capacity is retired too fast, from Oxnard to Carlsbad, at a cost of more than $6 billion.

Reiko Kerr, the DWP’s senior assistant general manager of power systems, said given the changes in the energy world, the assessment is necessary to protect ratepayer dollars and the environment.

“The whole utility paradigm has shifted,” Kerr said in an interview. “We really are doing our ratepayers a disservice by not considering all viable options.

“We’re just looking at everything,” she said. “What can help us solve this reliability, renewable and greenhouse gas challenge that we all have?”

State and local governments have felt a heightened sense of urgency to deal with climate change after President Trump decided last week to withdraw the United States from the Paris climate accord.

California already has mandated that at least 50% of the state’s electricity come from clean energy sources by 2030. Senate leader Kevin de León (D-Los Angeles) wants to increase that to 100% by 2045.

Building or overhauling natural gas plants throughout Southern California, environmentalists argue, isn’t helping achieve those goals, even as some contend the state can't keep the lights on without gas during the transition.

The DWP’s move to delay plans for the fossil fuel plants, which seemed all but set to be built, came as a surprise to clean-energy advocates, who hailed the decision.

“This is a great first step toward smart energy investments that save customers money, ensure the lights stay on and protect our health and environment,” Graciela Geyer of the Sierra Club said.

The environmental group said that if the utility had moved ahead with the $2.2-billion investment in repowering natural gas plants, it “would have blown an irreparable hole in the city and the state’s hopes to achieve 100% generation” from clean energy sources.

Angela Johnson Meszaros, attorney at EarthJustice, said in a statement: "As our city struggles with the worst smog we’ve seen in years, we appreciate that LADWP is taking some much-needed time to reassess its plans to build fossil fuel power plants. We look forward to the day that LADWP announces that we are going to power our city with 100% clean energy.”

The gas-fired generating units slated for demolition and rebuilding are at the Scattergood, Haynes and Harbor electricity plants, which range from 34 to 67 years old.

As a group, the three plants have generated less than 20% of their combined capacity since 2001. The Harbor facility has operated on the low end at just 7%, while Haynes ran on the high end at 22%.

“The old model, the old legacy clunkers, won’t get us into the future we want,” DWP’s Kerr said.

DWP staff members told the utility’s’ commissioners Tuesday that their analysis of possible alternatives would be completed no later than early 2018.

Separately, the California Energy Commission this week is evaluating whether to halt a natural gas project in Ventura County after the state’s electric grid operator offered to conduct a study of clean energy alternatives to the roughly $250-million project on Mandalay Bay in Oxnard.

An energy commission committee has been deliberating since a hearing Monday during which Southern California Edison and the project’s developer, NRG Energy, argued that a study is simply a delay tactic that probably would kill a project needed to ensure reliable electric service and to avoid blackouts during peak demand.

The California Independent System Operator, which runs the state’s electric grid, told the energy commission that it would take three to four weeks to conduct its study on alternatives to the Oxnard natural gas project.

“Here we have an actual offer by the ISO to do such an analysis,” Ellison Folk, a lawyer representing the city of Oxnard, told the energy commission as she pushed for the study. “Its view that this is an analysis worth doing is something worth taking seriously.”

Energy commission members reviewing the study proposal are scheduled to meet again Thursday to consider the offer.

The board of governors for the California Independent System Operator made the unusual offer at its May 1 meeting to conduct a eleventh-hour study of clean-energy alternatives to building a new natural gas plant.

“If we’re going to be moving forward with a gas plant at this time, in this juncture, in the context of everything that’s going on, not evaluating other alternatives that are viable, noncombustion alternatives, is a missed opportunity,” Angelina Galetiva. a commission board member, said during the May 1 meeting.

Related News

• Electricity Forum News

• Energy Policy News

Cobalt Supply Chain for EV Batteries faces shortages as lithium-ion demand surges; Tesla gigafactories, ethical sourcing, Idaho cobalt mining, and DRC risks intensify pricing, logistics, and procurement challenges for manufacturers and investors.

Key Points

A network supplying cobalt for lithium-ion cathodes, strained by EV demand, ethical sourcing pressures, and DRC risk.

✅ EV growth outpaces cobalt supply, widening deficits

✅ DRC reliance drives ESG scrutiny and sourcing shifts

✅ Idaho projects and stockpiling reshape U.S. supply

A perfect storm is brewing in the 21st Century battery market.

More specifically, it's about what goes into those batteries - and it's not just lithium.

The other element that makes up 35 percent of the lithium-ion batteries mass produced at Tesla's Nevada gigafactory and at a dozen of other behemoths slated to come on line, is cobalt. And it's already in dramatically short supply. A part of the answer to the cobalt deficit is 100 percent American, and this little-known miner is sitting on a prime Idaho cobalt project that is one of only two that looks likely to come online in the U.S. and it's right in Tesla's backyard.

High-Energy Batteries Need More Cobalt Than Lithium 

If you've been focusing your investment on lithium supplies lately you've been missing the even bigger story. EV batteries need about 200 grams of refined cobalt per kilowatt of battery capacity. Power walls need more than twice that. Between March 2016 and April 2017, the cost of the cobalt in that mix nearly tripled. But it isn't just the price that's got manufacturers worried. It's the shortage of availability. Keeping gigafactories stocked with enough cobalt to run at capacity is the challenge of the decade.

Tesla, now with a $50-billion market cap, launched a $5-billion battery gigafactory in Nevada in January. By the end of 2017, it will have doubled the entire global battery production capacity. By next year, it will be producing more batteries than the rest of the world combined.

It is estimated that Tesla's gigafactory alone will need anywhere between 7,000 and 17,500 tonnes of refined cobalt every year.

Tesla used to buy its finished battery cells from Panasonic, which in turn got its processed cathode powders from a Japanese company, Sumitomo was processing its own cobalt in the Philippines. However, that facility is already running at capacity and couldn't even begin to handle Tesla's gigafactory demand. In other words, Tesla's supply chain is no longer secure. And that's just Tesla.

The EV market is fifteen times larger than it was five years ago. The market has experienced a comppound annual growth rate of over 72 percent from 2011-2016, with new sources like Alberta's lithium-laced oil fields drawing investment alongside cobalt. This year, analysts expect it to gain another 25-26 percent. Last year, global EV production grew 41 percent, and sales are up more than 60 per cent year to year.

In addition,the Iron Creek project isn't a new exploration property. It has already seen major historic exploratory work, including 30,000 feet of diamond drilling. Iron Creek has historic (non 43-101 compliant) indications of 1.3 million tons grading 0.59 percent of cobalt with encouraging indications of up to 10 million tons. The 'closeology' is also brilliant. It's right next to the only advanced cobalt project in the U.S., which has a resource of 3 million-plus tonnes of cobalt.

As the battery market hits fever pitch and the supply-chain bottlenecks become unbearable, homegrown exploration is the key-first-movers and first investors will be the biggest beneficiaries.

A Very Precarious Supply Chain 

Supply is already in deficit, and we're also looking at an anticipated 500 percent increase in demand, making EV battery recycling an increasingly important complement to mining. Analysts at Macquarie Research project deficits of 885 tonnes of this resource next year, 3,205 in 2019 and 5,340 in 2020.

Not only is demand set to wildly outstrip supply very soon, but current supply (50 percent) comes primarily from the Democratic Republic of Congo (DRC). Buyers are coming under increasing pressure to look elsewhere for cobalt as the U.S. moves to work with allies to secure EV metals through diversified supply chains. The DRC has a horrendous record when it comes to labor practices and human rights.

Ask Apple Inc.  The tech giant recently announced it would stop buying unethical DRC cobalt for its iPhones - and as such, it has been forced to look for new suppliers.

The perfect storm continues: Some 95 percent of the world's cobalt is produced as a byproduct of copper and nickel mining, where concerns about ethical sourcing have put a spotlight on Canada's role in sustainable nickel practices worldwide. This means that cobalt supply is dependent on copper and nickel mining, and if those commodities are uneconomic to mine, there are no cobalt by-product results.

Not only is US Cobalt one of the first movers on the All-American ethical cobalt scene, but it's also financed to advance its Idaho Cobalt Belt project, and hopes to prove up 10 million tonnes of cobalt resource.

The Dream Team Behind Pure American Cobalt 

The CEO of US Cobalt, Wayne Tisdale, is a legend in spotting emerging trends with impeccable timing and has created billions in shareholder value. He's already done it with uranium, gold and oil and gas, and his most recent homerun was in lithium, with Pure Energy. When it launched in 2012, lithium was selling for about $5,000 per tonne. Within 18 months, it had increased 450 percent.

His next bet is on cobalt.

Tisdale and his team at Intrepid Financial have, in recent years, created $2.7 billion in value by building and financing 5 companies in completely different industries:

• Rainy River (gold) was worth $1.2 billion at its peak
• Xemplar (uranium) hit $1 billion at its peak
• Ryland Oil (oil and gas) sold for $114 million
• Webtech Wireless (tech) was worth $300 million at its peak
• Pure Energy (lithium) is worth $65 million (and counting)

The bottom line? There is no other commodity on the market right now that we need more.

Just watch what the hedge funds are doing with cobalt because it's unprecedented. The run on physical cobalt started in February in the least expected corner: Major hedge funds started buying up physical cobalt and hoarding it in order to gain exposure, resulting in a major supply shortage for the blue metal. Swiss-based Pala Investments and China's Shanghai Chaos have already hoarded 17 percent of last year's global production. At today's prices that's worth around $280 million. At tomorrow's prices, it will be worth a lot more.

When hedge funds start stockpiling physical cobalt, it sends its traditional buyers into a panic to secure new shipments. Since November, cobalt prices have rallied more than 100 percent, and this is only the beginning. As the cobalt supply problem grows, and EV giants and gigafactories continue to increase demand, a home-grown solution is at hand. As a first principle of investing, where there is a supply problem, there is a massive opportunity for early investors.

Related News

• Electricity Forum News

• EV Infrastructure News

Renewables Beat Brown Coal in Australia, as solar and wind surged to nearly 10,000 GWh, stabilizing the grid with battery storage during peak demand, after Hazelwood's closure, Green Energy Markets reported.

Key Points

It describes a 2017-18 summer when solar, wind, and storage generated more electricity than brown coal in Australia.

✅ Solar and wind hit nearly 10,000 GWh in summer 2017-18

✅ Brown coal fell to about 9,100 GWh after Hazelwood closure

✅ Batteries stabilized peak demand; Tesla responded in milliseconds

Renewable energy generated more electricity than brown coal during Australia’s summer for the first time in 2017-18, according to a new report by Green Energy Markets.

Continued growth in solar, as part of Australia's energy transition, pushed renewable generation in Australia to just under 10,000 gigawatt hours between December 2017 and February 2018. With the Hazelwood plant knocked out of the system last year, brown coal’s output in the same period was just over 9,100 GWh.

Renewables produced 40% more than gas over the period, and was exceeded only by black coal, reflecting trends seen in U.S. renewables surpassing coal in 2022.

#google#

The report, commissioned by GetUp, found renewables were generating particularly large amounts of electricity when it was most needed, producing 32% more than brown coal during summer between 11am and 7pm, when demand peaks.

Coal in decline: an energy industry on life support

Solar in particular was working to support the system, on average producing more than Hazelwood was capable of producing between 9am and 5pm.

A further 5,000 megawatts of large-scale renewables projects was under construction in February, supporting 17,445 jobs, while renewables became the second-most prevalent U.S. electricity source in 2020.

GetUp’s campaign director, Miriam Lyons, said the latest renewable energy index showed renewables were keeping the lights on while coal became increasingly unreliable, a trend echoed as renewables surpassed coal in the U.S. in recent years.

“Over summer renewables kept houses cool and lights on during peak demand times when people needed electricity most,” Lyons said. “Meanwhile dirty old coal plants are becoming increasingly unreliable in the heat.

“These ageing clunkers failed 36 times over summer.

“Clean energy rescued people from blackouts this summer. When the clapped-out Loy Yang coal plant tripped, South Australia’s giant Tesla battery reacted in milliseconds to keep the power on.

“It’s clear that a smart electricity grid based on a combination of renewable energy and storage is the best way to deliver clean, affordable energy for all Australians.”

Related News

• Electricity Forum News

• Renewable Energy News