Duke execs expect slow growth for now

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Duke Energy executives expect a slow economic recovery in 2010 and succeeding years, they told analysts in New York.

"We see the growth in (electrical) demand over the next five years being very, very anemic," CEO Jim Rogers said. Duke is the nation's third-largest, investor-owned utility.

Duke reported that its 2009 earnings were hurt by a 14 percent drop in sales to industries, although fourth-quarter sales stabilized.

"I would describe (industries') mood as cautiously optimistic in 2010," chief financial officer Lynn Good told a meeting of analysts, "although a significant rebound is not expected soon."

Customers are likely to see rising electric rates despite projections of a slow recovery, Duke said.

The company will spend $6 billion on four power plants now under construction, and expects to build more as old plants are shut down. New environmental rules are likely to cost another $5 billion.

Duke won approval last year for overall rate increases in the Carolinas. New rate requests in both states are likely in 2011, it said, with new rates in effect in 2012.

Duke expects earnings to grow 4 to 5 percent this year. Adjusted for one-time charges, earnings per share would grow of $1.25 to $1.30 a share, compared to $1.22 in 2009.

This year's revenue will grow $460 million from rate cases settled in the Carolinas and Midwest.

But high unemployment in its five-state territory — the Carolinas, Ohio, Kentucky and Indiana — will likely lead to essentially flat residential and commercial growth, executives said.

Good said it is "prudent to plan the year assuming 2010 will look like 2009."

As the recession lingers, Duke is pouring billions of dollars into new power plants.

A $2.4 billion expansion of the Cliffside power plant west of Charlotte, and construction of a new, $2.3 billion coal-fired plant in Edwardsport, Ind., are both about half finished.

New natural gas-fired units will be completed at its N.C. Buck and Dan River plants by 2011 and 2012.

Duke is seeking partners to build a new nuclear plant near Gaffney, S.C., but has pushed the expected completion date to 2021.

It's also considering a nuclear plant in Ohio, and will spend $1 billion to modernize its grid over the next five years.

A key priority, executives said, will be to more quickly recover its construction costs.

In North Carolina, that means persuading legislators to change the way Duke could recoup financing costs of a nuclear plant under construction. Duke wants to be able to recover those costs without filing a general rate case.

Duke said it expects tighter environmental rules for air pollutants, coal ash and carbon dioxide. Rogers, however, said he does not expect Congress to regulate greenhouse gases this year.

The more stringent rules are likely to cost the company $5 billion over a period of years. That's how much Duke spent to clean up its coal plants over the past decade.

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N.B. Power hits pause on large new electricity customers during crypto review

N.B. Power Crypto Mining Moratorium underscores electricity demand risks from bitcoin mining, straining the energy grid and industrial load capacity in New Brunswick, as a cabinet order prioritizes grid reliability, utility planning, and allocation.

 

Key Points

Official pause on new large-scale crypto mining to protect N.B. Power grid capacity, stability, and reliable supply.

✅ Cabinet order halts new large-scale crypto load requests

✅ Review targets grid reliability, planning, and capacity

✅ Non-crypto industrial customers exempt from prolonged pause

 

N.B. Power says a freeze on servicing new, large-scale industrial customers in the province remains in place over concerns that the cryptocurrency sector's heavy electricity use could be more than the utility can handle.

The Higgs government quietly endorsed the moratorium in a cabinet order in March 2022 and ordered a review of how the sector might affect the reliable electricity supply and broader electricity future planning in the province.

The cabinet order, filed with the Energy and Utilities Board, said N.B. Power had "policy, technical and operational concerns about [its] capacity to service the anticipated additional load demand" from energy-intensive customers such as crypto mines.

It said the utility had received "several new large-scale, short-notice service requests" to supply electricity to crypto mining companies that could put "significant pressure" on the existing electricity supply.

The order, signed by Premier Blaine Higgs, said non-crypto companies shouldn't be subject to the pause for any longer than required for the review, amid shifts in regional plans like the Atlantic Loop that are altering timelines. Ws.

The freeze was ordered months after Taal Distributed Information Technologies Inc. announced plans to establish a 50-megawatt bitcoin mining operation and transaction processing facility in Grand Falls.

A town official said this week that the deal never went ahead.

24 hours a day
The Taal facility would have joined a 70-megawatt bitcoin mine in Grand Falls operated by Hive Blockchain Technologies.

Hive's Bitcoin mine comprises four large warehouses containing thousands of computers running 24 hours a day to earn cryptocurrency units.

The combined annual electricity consumption of the two mines would exceed what could be produced by the small modular nuclear reactor being designed by ARC Clean Energy Canada of Saint John, even as Nova Scotia advances efforts to harness the Bay of Fundy's powerful tides for clean power.

Put another way, the two mines would gobble up more than three months' electricity from N.B. Power's coal-fired Belledune generating station under current operations.

 

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Site C dam could still be cancelled at '11th hour' if First Nations successful in court

Site C Dam Court Ruling could halt hydroelectric project near Fort St. John, as First Nations cite Treaty 8 rights in B.C. Supreme Court against BC Hydro, reservoir flooding, and Peace River Valley impacts.

 

Key Points

Potential B.C. Supreme Court stop to Site C, grounded in Treaty 8 rights claims by First Nations against BC Hydro.

✅ Trial expected in 2022 before planned 2023 reservoir flooding

✅ Treaty 8 rights and Peace River Valley impacts at issue

✅ Talks ongoing among B.C., BC Hydro, West Moberly, Prophet River

 

The Site C dam could still be stopped by an "eleventh hour" court ruling, according to the lawyer representing B.C. First Nations opposed to the massive hydroelectric project near Fort St. John.

The B.C. government, BC Hydro and West Moberly and Prophet River First Nations were in B.C. Supreme Court Feb. 28 to set a 120-day trial, expected to begin in March 2022.

That date means a ruling would come prior to the scheduled flooding of the dam's reservoir area in 2023 said Tim Thielmann, legal counsel for the West Moberly First Nation.

"The court has left itself the opportunity for an eleventh hour cancellation of the project," he said.

 

Construction continues

At the core of the case is First Nations arguments the multi-billion dollar BC Hydro dam will cause irreparable harm to its territory and way of life — even as drought strains hydro production elsewhere — rights protected under Treaty 8.

The West Moberly have previously warned it believes Site C constitutes a $1 billion treaty violation.

​In 2018, the First Nations lost a bid for an injunction order, meaning construction of the dam is continuing despite warnings that delays could cost $600 million to the project.

First Nations 'deeply frustrated' after B.C. Supreme Court dismisses Site C injunction

The judge in the case said the ruling was made because if the First Nations lost the challenge, the project would be needlessly put into disarray.

 

Province, Nations enter talks to avoid litigation

Also this week the B.C. government announced it has entered into talks with BC Hydro and the two First Nations in an attempt to avoid the court process altogether, amid broader energy debates such as bridging the Alberta-B.C. electricity gap for climate goals.

Thielmann said the details of the talk are confidential, but his clients are willing to pursue all avenues in order to stop the dam from moving forward.

"They are trying to save what little is left [of the Peace River Valley]", he said.

Tim Thielmann of Sage Legal is representing the West Moberly First Nation in its lawsuit aimed at stopping Site C. (Sage Legal)

In the meantime, the parties will continue to prepare for the 2022 court dates.

The latest figure on the cost of the dam is $10.7 billion, in a billions-over-budget project that the premier says will proceed. When complete, it would power the equivalent of 450,000 homes a year, though use of Site C's electricity remains a point of debate.

 

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Energy-insecure households in the U.S. pay 27% more for electricity than others

Community Solar for Low-Income Homes expands energy equity by delivering renewable energy access, predictable bill savings, and tax credit benefits to renters and energy-insecure households, accelerating distributed generation and storage adoption nationwide.

 

Key Points

A program model enabling renters and LMI households to subscribe to off-site solar and save on utility bills.

✅ Earn bill credits from shared solar generation.

✅ Expands access for renters and LMI subscribers.

✅ Often paired with storage and IRA tax credit adders.

 

On a square-foot basis, the issue of inequality is made worse by higher costs for energy usage in the nation. Efforts like community solar programs such as Maryland community solar are underway to boost low-income participation in the cost benefits of renewable energy.

The Energy Information Administration (EIA) shows that households that are considered energy insecure, or those that have the inability to adequately meet basic household energy costs, are paying more for electricity than their wealthier counterparts. 

On average in the United States in 2020, households were billed about $1.04 per square foot for all energy sources. For homes that did not report energy insecurity, that average was $0.98 per square foot, while homes with energy insecurity issues paid an average of $1.24 per square foot for energy. This means that U.S. residents that need the most support on their energy bills are stuck with costs 27% higher than their neighbors on square-foot-basis.

EIA said energy-insecure households have reduced or forgone basic necessities to pay energy bills, kept their houses at unsafe temperatures because of energy cost concerns, or been unable to repair heating or cooling equipment because of cost.

In 2020, households with income less than $10,000 a year were billed an average of $1.31 per square foot for energy, while households making $100,000 or more were billed an average of $0.96 per square foot, said EIA. Renters paid considerably more ($1.28 per square foot) than owners ($0.98 per square foot). There were also considerable differences between regions, with New England solar growth sparking grid upgrade debates, ethnic groups and races, and insulation levels, as seen below.

The energy transition toward renewables like solar has offered price stability, amid record solar and storage growth nationwide, but thus far energy-insecure communities have relatively been left behind. A recent Berkeley Lab report, Residential Solar-Adopter Income and Demographic Trends, indicates that even though the rate of solar adoption among low-income residents is increasing (from 5% in 2010 to 11% in 2021), that segment of energy consumers remains under-represented among solar adopters, relative to its share of the population.


Community solar efforts

As such, the United States is targeting communities most impacted by energy costs that have not benefitted from the transition, highlighting “Energy Communities” that are eligible for an additional 10% tax credit through funds made possible by the Inflation Reduction Act.

Additionally, a push for community solar development is taking place nationwide to extend access to affordable solar energy to renters and other residents that aren’t able to leverage finances to invest in predictable, low-cost residential solar systems. The Biden Administration set a goal this year to sign up 5 million community solar households, achieving $1 billion in bill savings by 2025. The community solar model only represents about 8% of the total distributed solar capacity in the nation. This target would entail a jump from 3 GW installed capacity to 20 GW by the target year. The Department of Energy estimates community solar subscribers save an average of 20% on their bills.

California this year passed AB 2316, the Community Renewable Energy Act takes aim at four acute problems in the state’s power market: reliability amid rising outage risks, rates, climate and equity. The law creates a community renewable energy program, including community solar-plus-storage, supported by cheaper batteries, to overcome access barriers for nearly half of Californians who rent or have low incomes. Community solar typically involves customers subscribing to an off-site solar facility, receiving a utility bill credit for the power it generates.

“Community renewable energy is a proven powerful tool to help close California’s clean energy gap, bringing much needed relief to millions struggling with high housing costs and utility debt,” said Alexis Sutterman, energy equity program manager at the California Environmental Justice Alliance.

The program has energy equity baked into its structure, working to make sure Californians of all income levels participate in the benefits of the energy transition. Not only does it open solar access to renters, the law ensures that at least 51% of subscribers are low-income customers, which is expected to make projects eligible for a 10% tax credit adder under the IRA.

“The money’s on the table now,” said Jeff Cramer, president and chief executive of the Coalition for Community Solar Access. “While there are groups pushing for solar access for all, and states with strong legislation, there are other pockets of interest in surprising places in the United States. For example, Louisiana has no policy for community solar or support for low-income residents going solar but the city of New Orleans has its own utility commission with a community solar program. In Nebraska, forward-looking co-operatives have created community solar projects.

Community solar markets are active in 22 states, with more expected to come online in the future as states pursue 100% clean energy targets across the country. However, the market is expected to require strong community outreach efforts to foster trust and gain subscribers.

“There is a distrust of community solar initially in LMI communities as many have been burned before by retail energy false promises,” said Eric LaMora, executive director, community solar, Nautilus Solar on a panel at the Solar Energy Industries Association Finance, Tax, and Buyers seminar. “People are suspicious but there really are no hooks with community solar.”

LMI residents are leery to provide tax records or much documents at all in order to sign up for community solar, LaMora said. “We were surprised to see less of a default rate with LMI residents. We attribute this to the fact that they see significant savings on their electric bill, making it easier to pay each month,” he said.

 

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Powering Towards Net Zero: The UK Grid's Transformation Challenge

UK Electricity Grid Investment underpins net zero, reinforcing transmission and distribution networks to integrate wind, solar, EV charging, and heat pumps, while Ofgem balances investor returns, debt risks, price controls, resilience, and consumer bills.

 

Key Points

Capital to reinforce grids for net zero, integrating wind, solar, EVs and heat pumps while balancing returns and bills.

✅ 170bn-210bn GBP by 2050 to reinforce cables, pylons, capacity.

✅ Ofgem to add investability metric while protecting consumers.

✅ Integrates wind, solar, EVs, heat pumps; manages grid resilience.

 

Prime Minister Sunak's recent upgrade to his home's electricity grid, designed to power his heated swimming pool, serves as a microcosm of a much larger challenge facing the UK: transforming the nation's entire electricity network for net zero emissions, amid Europe's electrification push across the continent.

This transition requires a monumental £170bn-£210bn investment by 2050, earmarked for reinforcing and expanding onshore cables and pylons that deliver electricity from power stations to homes and businesses. This overhaul is crucial to accommodate the planned switch from fossil fuels to clean energy sources - wind and solar farms - powering homes with electric cars, as EV demand on the grid rises, and heat pumps.

The UK government's Climate Change Committee warns of potentially doubled electricity demand by 2050, the target date for net zero, even though managing EV charging can ease local peaks. This translates to a significant financial burden for companies like National Grid, SSE, and Scottish Power who own the main transmission networks and some regional distribution networks.

Balancing investor needs for returns and ensuring affordable energy bills for consumers presents a delicate tightrope act for regulators like Ofgem. The National Audit Office criticized Ofgem in 2020 for allowing network owners excessive returns, prompting concerns about potential bill hikes, especially after lessons from 2021 reshaped market dynamics.

Think-tank Common Wealth reported that distribution networks paid out a staggering £3.6bn to their owners between 2017 and 2021, raising questions about the balance between profitability and affordability, amid UK EV affordability concerns among consumers.

However, Ofgem acknowledges the need for substantial investment to finance network upgrades, repairs, and the clean energy transition. To this end, they are considering incorporating an "investability" metric, recognizing how big battery rule changes can erode confidence elsewhere, in the next price controls for transmission networks, ensuring these entities remain attractive for equity fundraising without overburdening consumers.

This proposal, while welcomed by the industry, has drawn criticism from consumer advocacy groups like Citizens Advice, who fear it could contribute to unfairly high bills. With energy bills already hitting record highs, public trust in the net-zero transition hinges on ensuring affordability.

High debt levels and potential credit rating downgrades further complicate the picture, potentially impacting companies' ability to raise investment funds. Ofgem is exploring measures to address this, such as stricter debt structure reporting requirements for regional distribution companies.

Lawrence Slade, CEO of the Energy Networks Association, emphasizes the critical role of investment in achieving net zero. He highlights the need for "bold" policies and regulations that balance ambitious goals with investor confidence and ensure efficient resource allocation, drawing on B.C.'s power supply challenges as a cautionary example.

The challenge lies in striking a delicate balance between attracting investment, ensuring network resilience, and maintaining affordable energy bills. As Andy Manning from Citizens Advice warns, "Without public confidence, net zero won't be delivered."

The UK's journey to net zero hinges on navigating this complex landscape. By carefully calibrating regulations, fostering investor confidence, and prioritizing affordability, the country can ensure its electricity grid is not just robust enough to power heated swimming pools, but also a thriving green economy for all.

 

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SaskPower reports $205M income in 2019-20, tables annual report

SaskPower 2019-20 Annual Report highlights $205M net income, grid capacity upgrades, emissions reduction progress, Chinook Power Station natural gas baseload, and wind and solar renewable energy to support Saskatchewan's Growth Plan and Prairie Resilience.

 

Key Points

SaskPower's 2019-20 results: $205M income, grid upgrades, emissions cuts, and new gas baseload with wind and solar.

✅ $205M net income, up $8M year-over-year

✅ Chinook Power Station adds stable natural gas baseload

✅ Increased grid capacity enables more wind and solar

 

SaskPower presented its annual report on Monday, with a net income of $205 million in 2019-20, even as Manitoba Hydro's financial pressures highlight regional market dynamics.

This figure shows an increase of $8 million from 2018-19, despite record provincial power demand that tested the grid.

“Reliable, sustainable and cost-effective electricity is crucial to achieving the economic goals laid out in the Government of Saskatchewan’s Growth Plan and the emissions reductions targets outlined in Prairie Resilience, our made-in-Saskatchewan climate change strategy,” Minister Responsible for SaskPower Dustin Duncan said.

In the last year, SaskPower has repaired and upgraded old infrastructure, invested in growth projects and increased grid capacity, including plans to buy more electricity from Manitoba Hydro to support reliability and benefiting from new turbine investments across the region.

The utility is also exploring procurement partnerships, including a plan to purchase power from Flying Dust First Nation to diversify supply.

“During the past year, we continued to move toward our target to reduce carbon dioxide emissions 40 per cent from 2005 levels by 2030, as part of efforts to double renewable electricity by 2030 across Saskatchewan,” SaskPower President and CEO Mike Marsh said. “The newly commissioned natural gas-fired Chinook Power Station will provide a stable source of baseload power while enabling the ongoing addition of intermittent renewable generation capacity, and exploring geothermal power alongside wind and solar generation.”

 

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California electricity pricing changes pose an existential threat to residential rooftop solar

California Rooftop Solar Rate Reforms propose shifting net metering to fixed access fees, peak-demand charges, and time-of-use pricing, aligning grid costs, distributed generation incentives, and retail rates for efficient, least-cost electricity and fair cost recovery.

 

Key Points

Policies replacing net metering with fixed fees, demand charges, and time-of-use rates to align costs and incentives.

✅ Large fixed access charge funds grid infrastructure

✅ Peak-demand pricing reflects capacity costs at system peak

✅ Time-varying rates align marginal costs and emissions

 

The California Public Service Commission has proposed revamping electricity rates for residential customers who produce electricity through their rooftop solar panels. In a recent New York Times op‐​ed, former Governor Arnold Schwarzenegger argued the changes pose an existential threat to residential rooftop solar. Interest groups favoring rooftop solar portray the current pricing system, often called net metering, in populist terms: “Net metering is the one opportunity for the little guy to get relief, and they want to put the kibosh on it.” And conventional news coverage suggests that because rooftop solar is an obvious good development and nefarious interests, incumbent utilities and their unionized employees, support the reform, well‐​meaning people should oppose it. A more thoughtful analysis would inquire about the characteristics and prices of a system that supplies electricity at least cost.

Currently, under net metering customers are billed for their net electricity use plus a minimum fixed charge each month. When their consumption exceeds their home production, they are billed for their net use from the electricity distribution system (the grid) at retail rates. When their production exceeds their consumption and the excess is supplied to the grid, residential consumers also are reimbursed at retail rates. During a billing period, if a consumer’s production equaled their consumption their electric bill would only be the monthly fixed charge.

Net metering would be fine if all the fixed costs of the electric distribution and transmission systems were included in the fixed monthly charge, but they are not. Between 66 and 77 percent of the expenses of California private utilities do not change when a customer increases or decreases consumption, but those expenses are recovered largely through charges per kWh of use rather than a large monthly fixed charge. Said differently, for every kWh that a PG&E solar household exported into the grid in 2019, it saved more than 26 cents, on average, while the utility’s costs only declined by about 8 cents or less including an estimate of the pollution costs of the system’s fossil fuel generators. The 18‐​cent difference pays for costs that don’t change with variation in a household’s consumptions, like much of the transmission and distribution system, energy efficiency programs, subsidies for low‐​income customers, and other fixed costs. Rooftop solar is so popular in California because its installation under a net metering system avoids the 18 cents, creating a solar cost shift onto non-solar customers. Rooftop solar is not the answer to all our environmental needs. It is simply a form of arbitrage around paying for the grid’s fixed costs.

What should electricity tariffs look like? This article in Regulation argues that efficient charges for electricity would consist of three components: a large fixed charge for the distribution and transmission lines, meter reading, vegetation trimming, etc.; a peak‐​demand charge related to your demand when the system’s peak demand occurs to pay for fixed capacity costs associated with peak use; and a charge for electricity use that reflects the time‐ and location‐​varying cost of additional electricity supply.

Actual utility tariffs do not reflect this ideal because of political concerns about the effects of large fixed monthly charges on low‐​income customers and the optics of explaining to customers that they must pay 50 or 60 dollars a month for access even if their use is zero. Instead, the current pricing system “taxes” electricity use to pay for fixed costs. And solar net metering is simply a way to avoid the tax. The proposed California rate reforms would explicitly impose a fixed monthly charge on rooftop solar systems that are also connected to the grid, a change that could bring major changes to your electric bill statewide, and would thus end the fixed‐​cost avoidance. Any distributional concerns that arise because of the effect of much larger fixed charges on lower‐​income customers could be managed through explicit tax deductions that are proportional to income.

The current rooftop solar subsidies in California also should end because they have perverse incentive effects on fossil fuel generators, even as the state exports its energy policies to neighbors. Solar output has increased so much in California that when it ends with every sunset, natural gas generated electricity has to increase very rapidly. But the natural gas generators whose output can be increased rapidly have more pollution and higher marginal costs than those natural gas plants (so called combined cycle plants) whose output is steadier. The rapid increase in California solar capacity has had the perverse effect of changing the composition of natural gas generators toward more costly and polluting units.

The reforms would not end the role of solar power. They would just shift production from high‐​cost rooftop to lower‐​cost centralized solar production, a transition cited in analyses of why electricity prices are soaring in California, whose average costs are comparable with electricity production in natural gas generators. And they would end the excessive subsidies to solar that have negatively altered the composition of natural gas generators.

Getting prices right does not generate citizen interest as much as the misguided notion that rooftop solar will save the world, and recent efforts to overturn income-based utility charges show how politicized the debate remains. But getting prices right would allow the decentralized choices of consumers and investors to achieve their goals at least cost.

 

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