Man converts gas pickup to run on batteries

By The Jackson Sun


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Finding cheap gas is no longer a major concern for Frank Lawrence.

Instead of filling up at the pump, he's charging up his 1993 Chevrolet S-10 to run on two dozen 6-volt golf cart batteries.

For two weeks, Lawrence has driven the truck he converted to electric power on Madison County roads. Each night, the truck is plugged into an outlet in his garage and the batteries are charged for eight hours. By the morning it's juiced up and ready to run between 60 and 80 miles that day.

The transformation of the ordinary blue truck was spurred, in part, by the challenge of building his own battery-powered vehicle. But Lawrence also was motivated by the desire to save money.

"You know what you spend a week on gas, and all of a sudden your money disappears," he said. Lawrence estimates he was spending $100 a week on gas before the conversion.

The truck drives and looks, well, like a truck, he said.

"It's not an interstate machine, but it cruises at 55 (miles per hour)," Lawrence said. "I don't have a bumper sticker or anything that says electric vehicle."

This summer, Lawrence and two of his sons, Daniel and Mark, spent two months converting the truck.

The 55-year-old mechanical engineer bought diagrams and a kit with the parts from New Hampshire company Electric Vehicles of America, which specializes in conversions with the Chevy S-10.

Lawrence said tackling a conversion requires some skills and a willingness to get dirty.

"It's pretty challenging," he said. "You need some welding skills, the ability to read wiring structure diagrams and a lot of patience."

The extensive project required an overhaul of much of the original parts that make the truck run.

"It was a lot of fun and a lot of work," Lawrence said. "By the time you finish it, you stare like, 'What do I do now?'"

They removed the clutch and pedal. They also removed the original wiring harness because the sensors for the internal combustion engine were not needed.

Under the hood, a board with a controller takes the 144 volts produced by the batteries and controls the new 9-inch-diameter electric motor.

They also installed a lift kit to allow easier access to the bank of batteries underneath the bed of the truck.

Total investment for the truck and conversion was $12,000. The batteries cost $150 apiece and should last for about 20,000 miles.

Lawrence said in the long run, he's saving money because it only costs about $1 a day to charge the batteries. He typically drives the truck about 40 miles a day.

Lawrence estimates the batteries add 800 pounds onto his 2-ton vehicle. Lightweight vehicles are needed to offset the additional weight of the batteries.

Lawrence's ingenuity also has led to him tackling plumbing, wiring and other issues at the family's home, said Darleen Lawrence, his wife of 28 years.

"There's not a whole lot he can't do," she said. "I never have to hire a handyman, so I never had any doubt that he could do this.

"It was a good family experience, but I didn't get involved at all," she joked.

As a teenager, Lawrence worked construction jobs doing welding.

"I used to tear stuff up all the time," he said. "I've just always been a tinkerer — if that's what you call it. Take this apart and put it back together."

One issue limiting the number of electric cars on the road is that driving long distances requires the more expensive lithium-ion batteries, Lawrence said.

Silicon Valley manufacturer Tesla Motors is producing 100 percent electric cars that will be able to travel 244 miles daily. The 2009 version is available for a base price of $109,000, according to the company's Web site.

Lawrence doesn't mind that he lacks some of the amenities that might be in higher-priced electric cars right now.

But one problem is the electric motor is not waterproof, so checking the weather report before taking the truck out is important.

"It doesn't like water," he said. "Before you get caught in a rain storm, you should leave it at home."

He plans to install heat and air-conditioning systems in his truck once their prices drop for hybrids and electrical cars. A new paint job is in the near future as well.

"I think it would be cool to get an antique truck like one from the '40s," he said about a possible future conversion.

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Roads Need More Electricity: They Will Make It Themselves

Electrically Smart Roads integrate solar road surfaces, inductive charging, IoT sensors, AI analytics, and V2X to power lighting, deicing, and monitoring, reducing grid dependence while enabling dynamic EV charging and real-time traffic management.

 

Key Points

Electrically smart roads generate power, sense conditions, and charge EVs using solar, IoT, AI, and dynamic infrastructure.

✅ Solar surfaces, verges, and gantries generate on-site electricity

✅ Inductive lanes enable dynamic EV charging at highway speeds

✅ Embedded IoT sensors and AI deliver real-time traffic insights

 

As more and more capabilities are added to roads instead of simply covering a country with extra roads, they are starting to make their own electricity, notably as solar road surface but then with added silent wind turbines, photovoltaic verges and barriers and more.

That toll gate, street light and traffic monitoring system all need electricity. Later, roads that deice and charge vehicles at speed will need huge amounts of electricity. For now, electricity for road systems is provided by very expensive infrastructure to the grid, and grid flexibility for EVs remains a concern, except for a few solar/ wind street lights in China and Korea for example. However, as more and more capabilities are added to roads instead of simply covering a country with extra roads, they are starting to make their own electricity, notably as solar road surface but then with added silent wind turbines, photovoltaic verges and barriers and more. There is also highly speculative work in the USA and UK on garnering power from road surface movement using piezoelectrics and electrodynamics and even its heat. 

#google#

China plans to create an intelligent transport system by 2030. The country hopes to build smart roads that will not only be able to charge electric cars as they drive but also monitor temperature, traffic flow and weight load using artificial intelligence. Indeed, like France, the Netherlands and the USA, where U.S. EV charging capacity is under scrutiny, it already has trials of extended lengths of solar road which cost no more than regular roads. In an alternative approach, vehicles go under tunnels of solar panels that also support lighting, light-emitting signage and monitoring equipment using the electricity made where it is needed. See the IDTechEx Research report, Electrically Smart Roads 2018-2028 for more.

Raghu Das, CEO of IDTechEx says, "The spiral vertical axis wind turbines VAWT in Asia rarely rotate because they are too low but much higher versions are planned on large UK roadside vehicle charging centres that should work well. H shaped VAWT is also gaining traction - much slower and quieter than the propeller shape which vibrates and keeps you awake at night in an urban area.

The price gap between the ubiquitous polycrystalline silicon solar cell and the much more efficient single crystal silicon is narrowing. That means that road furniture such as bus shelters and smart gantries will likely go for more solar rather than adding wind power in many cases, a shift mirrored by connected solar tech in homes, because wind power needs a lot of maintenance and its price is not dropping as rapidly."

The IDTechEx Research report, Off Grid Electric Vehicle Charging: Zero Emission 2018-2028 analyses that aspect, while vehicle-to-grid strategies may complement grid resources. The prototype of a smart road is already in place on an expressway outside of Jinan, providing better traffic updates as well as more accurate mapping. Verizon's IoT division has launched a project around intelligent asphalt, which it thinks has the potential to significantly reduce fossil fuel emissions and save time by reducing up to 44% of traffic backups. It has partnered with Sacramento, California, to test this theory.

"By embedding sensors into the pavement as well as installing cameras on traffic lights, we will be able to study and analyze the flow of traffic. Then, we will take all of that data and use it to optimize the timing of lights so that traffic flows easier and travel times are shorter," explains Sean Harrington, vice president of Verizon Smart Communities.

Colorado's Department of Transportation has recently announced its intention to be the first state to pilot smart roads by striking a five-year deal with a smart road company to test the technology. Like planned auto-deicing roads elsewhere, the aim of this project is, first and foremost, to save lives. The technology will detect when a car suddenly leaves a road and send emergency assistance to the area. The IDTechEx Research report Electrically Smart Roads 2018-2028 describes how others work on real time structural monitoring of roads and embedded interactive lighting and road surface signage.

"Smart pavement can make that determination and send that information directly into a vehicle," Peter Kozinski, director of CDOT's RoadX division, tells the Denver Post. "Data is the new asphalt of transportation."   Sensors, processors and other technology are embedded in the Colorado road to extend capability beyond accidents and reach into better road maintenance. Fast adoption relies on the ability to rapidly install sensor-laden pavement or lay concrete slabs. Attention therefore turns to fast adaptation of existing roads. Indeed, even for the heavy coil arrays used for dynamic vehicle charging, even as state power grids face new challenges, in Israel there are machines that can retrofit into the road surface at a remarkable two kilometres of cut and insert in a day.

"It's hard to imagine that these things are inexpensive, with all the electronics in them," Charles Schwartz, a professor of civil and environmental engineering at the University of Maryland, tells the Denver Post concerning the vehicle sensing project, "but CDOT is a fairly sophisticated agency, and this is an interesting pilot project. We can learn a lot, even if the test is only partially successful."

 

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B.C. Diverting Critical Minerals, Energy from U.S

Canadian Softwood Lumber Tariffs challenge British Columbia's forestry sector, strain U.S.-Canada trade, and risk redirecting critical minerals and energy resources, threatening North American supply chains, manufacturing, and energy security across integrated markets.

 

Key Points

Duties imposed by the U.S. on Canadian lumber, affecting BC forestry, trade flows, and North American energy security.

✅ U.S. duties strain BC forestry and cross-border supply chains

✅ Risks redirecting critical minerals and energy exports

✅ Tariff rollback could bolster North American energy security

 

British Columbia Premier David Eby has raised concerns that U.S. tariffs on Canadian softwood lumber are prompting the province to redirect its critical minerals and energy resources, while B.C. challenges Alberta's electricity export restrictions domestically, away from the United States. In a recent interview, Eby emphasized the broader implications of these tariffs, suggesting they could undermine North American energy security and put electricity exports at risk across the border.

Since 2017, the U.S. Department of Commerce has imposed tariffs on Canadian softwood lumber imports, alleging that Canadian producers benefit from unfair subsidies. These duties have been a persistent source of tension between the two nations, coinciding with Canadian support for energy and mineral tariffs and significantly impacting British Columbia's forestry sector—a cornerstone of the province's economy.

Premier Eby highlighted that the financial strain imposed by these tariffs not only jeopardizes the Canadian forestry industry but also has unintended repercussions for the United States. He pointed out that the economic challenges faced by Canadian producers might lead them to seek alternative markets for their critical minerals and energy resources, as tariff threats boost support for Canadian energy projects domestically, thereby reducing the supply to the U.S. British Columbia is endowed with an abundance of critical minerals essential for various industries, including technology and defense.

The potential redirection of these resources could have significant consequences for American industries that depend on a stable and affordable supply of critical minerals and energy. Eby suggested that the tariffs might incentivize Canadian producers to explore other international markets, even as experts advise against cutting Quebec's energy exports amid the tariff dispute, diminishing the availability of these vital resources to the U.S.

In light of these concerns, Premier Eby has advocated for a reassessment of the tariffs, urging a more cooperative approach between Canada and the United States. He contends that eliminating the tariffs would be mutually beneficial, aligning with views that Biden is better for Canada's energy sector and cross-border collaboration, ensuring a consistent supply of critical resources and fostering economic growth in both countries.

The issue of U.S. tariffs on Canadian softwood lumber remains complex and contentious, with far-reaching implications for trade relations and resource distribution between the two nations. As discussions continue, stakeholders on both sides of the border are closely monitoring the situation, noting that Ford has threatened to cut U.S. electricity exports amid trade tensions, recognizing the importance of collaboration in addressing shared economic and security challenges.

 

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During this Pandemic, Save Money - How To Better Understand Your Electricity Bill

Commercial Electric Tariffs explain utility rate structures, peak demand charges, kWh vs kW pricing, time-of-use periods, voltage, delivery, capacity ratchets, and riders, guiding facility managers in tariff analysis for accurate energy savings.

 

Key Points

Commercial electric tariffs define utility pricing for energy, demand, delivery, time-of-use periods, riders, and ratchet charges.

✅ Separate kWh charges from kW peak demand fees.

✅ Verify time-of-use windows and demand interval length.

✅ Review riders, capacity ratchets, and minimum demand clauses.

 

Especially during these tough economic times, as major changes to electric bills are debated in some states, facility executives who don’t understand how their power is priced have been disappointed when their energy projects failed to produce expected dollar savings. Here’s how not to be one of them.

Your electric rate is spelled out in a document called a “tariff” that can be downloaded from your utility’s web page. A tariff should clearly spell out the costs for each component that is part of your rate, reflecting cost allocation practices in your region. Don’t be surprised to learn that it contains a bunch of them. Unlike residential electric rates, commercial electric bills are not based solely on the quantity of kilowatt-hours (kWh) consumed in a billing period (in the United States, that’s a month). Instead, different rates may apply to how your power is supplied, how it is delivered via electricity delivery charges, when it was consumed, its voltage, how fast it was used (in kW), and other factors.

If a tariff’s lingo and word structure are too opaque, spend some time with a utility account rep to translate it. Many state utility commissions also have customer advocates that may assist as they explore new utility rate designs that affect customers. Alternatively, for a fee, facility managers can privately chat with an energy consultant.

Common mistakes

Many facility managers try to estimate savings based on an averaged electric rate, i.e., annual electric spend divided by annual kWh. However, in markets where electricity demand is flat, such a number may obscure the fastest rising cost component: monthly peak demand charges, measured in dollars per kW (or kilo-volt-amperes, kVA).

This charge is like a monthly speeding ticket, based solely on the highest speed you drove during that time. In some areas, peak demand charges now account for 30 to 60 percent of a facility’s annual electric spend. When projecting energy cost savings, failing to separately account for kW peak demand and kWh consumption may result in erroneous results, and a lot of questions from the C-suite.

How peak demand charges are calculated varies among utilities. Some base it on the highest average speed of use across one hour in a month, while others may use the highest average speed during a 15- or 30-minute period. Others may average several of the highest speeds within a defined time period (for example, 8 a.m. to 6 p.m. on weekdays). It is whatever your tariff says it is.

Because some power-consuming (or producing) devices, including those tied to smart home electricity networks, vary in their operation or abilities, they may save money on a few — but not all — of those rate components. If an equipment vendor calculates savings from its product by using an average electric rate, take pause. Tell the vendor to return after the proposal has been redone using tariff-based numbers.

When a vendor is the only person calculating potential savings from using a product, there’s also a built-in conflict of interest: The person profiting from an equipment sale should not also be the one calculating its expected financial return. Before signing any energy project contracts, it’s essential that someone independent of the deal reviews projected savings. That person (typically an energy or engineering consultant) should be quite familiar with your facility’s electric tariff, including any special provisions, riders, discounts, etc., that may pertain. When this doesn’t happen, savings often don’t occur as planned. 

For example, some utilities add another form of demand charge, based on the highest kW in a year. It has various names: capacity, contract demand, or the generic term “ratchet charge.” Some utilities also have a minimum ratchet charge which may be based on a percent of a facility’s annual kW peak. It ensures collection of sufficient utility revenue to cover the cost of installed transmission and distribution even when a customer significantly cuts its peak demand.

 

 

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NDP takes aim at approval of SaskPower 8 per cent rate hike

SaskPower Rate Hike 2022-2023 signals higher electricity rates in Saskatchewan as natural gas costs surge; the Rate Review Panel approved increases, affecting residential utility bills amid affordability concerns and government energy policy shifts.

 

Key Points

An 8% SaskPower electricity rate increase split 4% in Sept 2022 and 4% in Apr 2023, driven by natural gas costs.

✅ 4% increase Sept 1, 2022; +4% on Apr 1, 2023

✅ Panel-approved amid natural gas price surge and higher fuel costs

✅ Avg residential bill up about $5 per step; affordability concerns

 

The NDP Opposition is condemning the provincial government’s decision to approve the Saskatchewan Rate Review Panel’s recommendation to increase SaskPower’s rates for the first time since 2018, despite a recent 10% rebate pledge by the Sask. Party.

The Crown electrical utility’s rates will increase four per cent this fall, and another four per cent in 2023, a trajectory comparable to BC Hydro increases over two years. According to a government news release issued Thursday, the new rates will result in an average increase of approximately $5 on residential customers’ bills starting on Sept. 1, 2022, and an additional $5 on April 1, 2023.

“The decision to increase rates is not taken lightly and came after a thorough review by the independent Saskatchewan Rate Review Panel,” Minister Responsible for SaskPower Don Morgan said in a news release, amid Nova Scotia’s 14% hike this year. “World events have caused a significant rise in the price of natural gas, and with 42 per cent of Saskatchewan’s electricity coming from natural gas-fueled facilities, SaskPower requires additional revenue to maintain reliable operations.”

But NDP SaskPower critic Aleana Young says the rate hike is coming just as businesses and industries are struggling in an “affordability crisis,” even as Manitoba Hydro scales back a planned increase next year.

She called the announcement of an eight per cent increase in power bills on a summer day before the long weekend “a cowardly move” by the premier and his cabinet, amid comparable changes such as Manitoba’s 2.5% annual hikes now proposed.

“Not to mention the Sask. Party plans to hike natural gas rates by 17% just days from now,” said Young in a news release issued Friday, as Manitoba rate hearings get underway nearby. “If Scott Moe thinks his choices — to not provide Saskatchewan families any affordability relief, to hike taxes and fees, then compound those costs with utility rate hikes — are defensible, he should have the courage to get out of his closed-door meetings and explain himself to the people of this province.”

The province noted natural gas is the largest generation source in SaskPower’s fleet. As federal regulations require the elimination of conventional coal generation in Canada by 2030, SaskPower’s reliance on natural gas generation is expected to grow, with experts in Alberta warning of soaring gas and power prices in the region. Fuel and Purchased Power expense increases are largely driven by increased natural gas prices, and SaskPower’s fuel and purchased power expense is expected to increase from $715 million in 2020-21 to $1.069 billion in 2023-24. This represents a 50 per cent increase in fuel and purchased power expense over three years.

“In the four years since our last increase SaskPower has worked to find internal efficiencies, but at this time we require additional funding to continue to provide reliable and sustainable power,” SaskPower president & CEO Rupen Pandya said in the release “We will continue to be transparent about our rate strategy and the need for regular, moderate increases.”

 

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California's Next Electricity Headache Is a Looming Shortage

California Electricity Reserve Mandate requires 3.3 GW of new capacity to bolster grid reliability amid solar power volatility, peak demand, and wildfire-driven blackouts, as CPUC directs PG&E, Edison, and Sempra to procure resource adequacy.

 

Key Points

A CPUC order for utilities to add 3.3 GW of reserves, safeguarding grid reliability during variable renewables and peaks

✅ 3.3 GW procurement to meet resource adequacy targets

✅ Focus on grid reliability during peak evening demand

✅ Prioritizes renewables, storage; limits new fossil builds

 

As if California doesn’t have enough problems with its electric service, now state regulators warn the state may be short on power supplies by 2021 if utilities don’t start lining up new resources now.

In the hopes of heading off a shortfall as America goes electric, the California Public Utilities Commission has ordered the state’s electricity providers to secure 3.3 additional gigawatts of reserve supplies. That’s enough to power roughly 2.5 million homes. Half of it must be in place by 2021 and the rest by August 2023.

The move comes as California is already struggling to accommodate increasingly large amounts of solar power that regularly send electricity prices plunging below zero and force other generators offline so the region’s grid doesn’t overload. The state is also still reeling from a series of deliberate mass blackouts that utilities imposed last month to keep their power lines from sparking wildfires amid strong winds. And its largest power company, PG&E Corp., went bankrupt in January.

Now as natural gas-fired power plants retire under the state’s climate policies, officials are warning the state could run short on electricity on hot evenings, when solar production fades and commuters get home and crank up their air conditioners. “We have fewer resources that can be quickly turned on that can meet those peaks,” utilities commission member Liane Randolph said Thursday before the panel approved the order to beef up reserves.

The 3.3 gigawatts that utilities must line up is in addition to a state rule requiring them to sign contracts for 15% more electricity than they expect to need. Some critics question the need for added supplies, particularly after the state went on a plant-building boom in the 2000s.

But California’s grid managers say the risk of a shortfall is real and could be as high as 4.7 gigawatts, especially during heat waves that test the grid again. Mark Rothleder, with the California Independent System Operator, said the 15% cushion is a holdover from the days before big solar and wind farms made the grid more volatile. Now it may need to be increased, he said.

“We’re not in that world anymore,” said Rothleder, the operator’s vice president of state regulatory affairs. “The complexity of the system and the resources we have now are much different.”

The state’s three major utilities, PG&E, Edison International and Sempra Energy, will be largely responsible for securing new supplies. The commission banned fossil fuels from being used at any new power generators built to meet the requirement — though it left the door open for expansions at existing ones.

Some analysts argue California is exporting its energy policies to Western states, making electricity more costly and less reliable.

PG&E said in an emailed statement that it was pleased the commission didn’t adopt an earlier proposal to require 4 gigawatts of additional resources. Edison similarly said it was “supportive.” Sempra didn’t immediately respond with comment.

 

Extending Deadlines

The pending plant closures are being hastened by a 2020 deadline requiring California’s coastal generators to stop using aging seawater-cooling systems. Some gas-fired power plants have said they’ll simply close instead of installing costly new cooling systems. So the commission on Thursday also asked California water regulators to extend the deadline for five plants.

The Sierra Club, meanwhile, called on regulators to turn away from fossil fuels altogether, saying their decision Thursday “sets California back on its progress toward a clean energy future.”

The move to push back the deadline also faces opposition from neighboring towns. Redondo Beach Mayor Bill Brand, whose city is home to one of the plants in line for an extension, told the commission it wasn’t necessary, since California utilities already have plenty of electricity reserves.

“It’s just piling on to that reserve margin,” Brand said.

 

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Tories 'taking the heart out of Manitoba Hydro' by promoting subsidiaries, scrapping low-cost pledges: NDP

Manitoba Hydro Privatization Debate centers on subsidiaries, Crown corporation governance, clean energy priorities, and electricity rates, as board terms shift oversight and transparency, sparking concerns about sell-offs and government control.

 

Key Points

A dispute over Hydro's governance, subsidiaries, electricity rates, and clean energy amid fears of partial privatization.

✅ Rewritten terms allow subsidiaries and shift board duties.

✅ Low rates and clean energy mandates softened in guidance.

✅ Govt cites Hydro Act; NDP warns of sell-off risks.

 

The board of Manitoba Hydro is being reminded it can divvy up some of the utility's work to subsidiaries — which the NDP is decrying as a step toward privatization. 

A sentence seemingly granting the board permission to create subsidiaries was included in the board's new terms of reference, which the NDP raised during question period Wednesday. 

The document also eliminated references asking Manitoba Hydro to keep electricity rates low, even as rate hike hearings proceed, and supply power in an environmentally-friendly fashion.

NDP raises spectre of Manitoba Hydro's privatization with new CEO
"They're essentially taking the heart out of Manitoba Hydro," NDP leader Wab Kinew said.

Cheap, clean energy is the basis by which the Crown corporation was formed, even as scaled-back rate increases are planned for next year, he said. 

"That's the whole reason we created this utility in the first place."

Another addition to the board's guidelines include stating the corporation is responsible to the government minister, who must be "proactively informed" when significant issues arise. 

The provincial government, however, says the rewritten terms of reference was the directive of the Manitoba Hydro board and not itself.

CBC's requests to the government for an interview were directed to Manitoba Hydro.

In an interview, Manitoba Hydro spokesperson Scott Powell said the energy utility has undergone no legislative changes, and is still governed by the Manitoba Hydro Act. 

The terms of reference were altered to align the board's duties with the new act overseeing Crown corporations, Powell said.

"Whether you have one or two words different in the terms of reference, the essence of the company hasn't changed."

While the new terms of reference no longer instructs the corporation to ensure an "environmentally responsible supply of energy for Manitobans," it encourages the board to "promote economy and efficiency in all phases of power generation and distribution."

On the cost to ratepayers, the updated directions asks the utility to deliver "safe, reliable energy services at a fair price," a standard clarified by a recent appeal court ruling on First Nations rates, but the board is not specifically instructed with keeping electricity rates low. 

Kinew contends the added sentence on subsidiaries permits Hydro to be broken off and sold for parts, although the terms of reference does not specify if any subsidiary would be wholly owned by Hydro or contracted to a private company.

Powell said Manitoba Hydro has been permitted to create subsidiaries since 1997, and nothing has changed since.

Kinew warned about Hydro's privatization last week when Jay Grewal was announced as Hydro's incoming CEO and president.

She was employed with B.C. Hydro when then-premier Gordon Campbell — hired by the Manitoba government to investigate costly overruns on two electricity megaprojects — sold off segments of the utility.

She then became managing director of Accenture, a global management consulting firm, which acquired several B.C. Hydro departments.

During question period Wednesday, Pallister disputed that Manitoba Hydro is bound to be sold.

He slammed the NDP's "Americanization strategy" of producing more electricity than it is capable of selling, which has saddled ratepayers with billions in debt and prompted proposed 2.5% annual increases in coming years. 

The makeup of the Hydro board has undergone a complete turnover in under a year, a contrast to Ontario's Hydro One shakeup vow during that period.

Nine of the 10 members resigned en masse this March over an impasse with the Pallister government. The lone holdover, Cliff Graydon, was dismissed from his post last month after the Progressive Conservatives removed him from caucus. 

 

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