ERCOT said Aug. 21 that the Public Utility Commission of Texas approved the requested exceptions on Aug. 20. ERCOT now intends to notify transmission and distribution providers of each large load’s conditional classification by Aug. 31.

The decision changes the timing and sequence of the interconnection review. It does not permanently bar new data centers, decide the fate of individual projects or authorize any project to connect or energize.

What the PUCT approved

ERCOT requested three good-cause exceptions related to its new Batch Zero process for large-load interconnections. The PUCT approved all three.

First, the commission excused ERCOT from the Aug. 7, 2026 deadline for classifying Batch Zero large loads. Second, it allowed ERCOT to include projects conditionally classified as base load in the August and November 2026 quarterly stability assessments before their final classifications are complete. Third, it allowed ERCOT to notify applicants about deficient dynamic data after Aug. 7 while giving those applicants the same 24-day period to correct the information.

ERCOT said the Aug. 31 target will begin the dispute and reconciliation process under the applicable planning rules. A conditional classification is not the same as a final classification, eligibility for every technical study, approval to connect or authorization to energize. Projects must still satisfy later technical, administrative and interconnection requirements.

Why Texas ordered the verification

Gov. Greg Abbott directed the PUCT and ERCOT on Aug. 3 to verify and audit data centers advancing through the ERCOT interconnection process before additional projects move forward.

In that directive, Abbott said ERCOT was considering approximately 474 gigawatts of interconnection requests, more than five times the record peak demand for the ERCOT system. He also said approximately 90% of the new power requests were from data centers. Those figures are the governor’s estimates of requests; they are not a verified count of projects that will be built, become operational or consume that amount of electricity.

The directive asked officials to collect information about public financial assistance, including tax incentives, grants and abatements; dependence on the ERCOT grid and plans for on-site generation; projected electricity and water use; water sources and cooling technology; measures to reduce noise, light, traffic and other community effects; and project ownership and control.

ERCOT’s June-approved Batch Zero framework groups qualified large electricity users of 75 megawatts or more into a study so the grid operator can evaluate their combined effect on transmission needs and system reliability. ERCOT said in June that the first group would include the initial set of applicants entering the new process. KERA News later reported that ERCOT expected to verify information from about 250 to 300 large energy consumers in Batch Zero.

Who is affected

Large-load developers may face longer schedules and additional documentation requirements before their requests advance. Transmission and distribution providers must use the revised classifications in planning and study work, while utilities and transmission planners may need to reassess infrastructure assumptions tied to projects that are not yet fully verified.

Lenders and investors whose capital commitments depend on interconnection milestones may also have to review construction schedules, financing conditions and other project deadlines. Communities preparing for substations, transmission lines, generation or water infrastructure could see proposed development timelines change.

The verification effort also reaches beyond the largest Batch Zero applicants. KERA News reported that ERCOT planned to collect community-impact information from medium-sized electricity users seeking between 25 and 75 megawatts, including data centers and cryptocurrency miners.

The records do not establish how many projects will ultimately qualify, be denied, be built or affect customer rates. They also do not establish a quantified change in reliability or household electricity bills.

What happens next

The next near-term milestone is ERCOT’s Aug. 31, 2026 target for notifying transmission and distribution providers of conditional classifications. Applicants may then enter dispute, data-correction and reconciliation steps before later classifications and study decisions.

ERCOT’s August and November stability assessments will be able to include conditionally classified base-load projects under the PUCT-approved exception. KERA News reported that ERCOT expected the governor’s broader audit work to continue through December.

The immediate question is how many requests can demonstrate credible financing, power and water plans, ownership information and community-impact measures. The broader planning challenge is how Texas can forecast transmission and generation needs when the ERCOT queue contains far more requested load than the system has historically served.

The action applies to the ERCOT service area. Texas areas outside ERCOT are not automatically covered by the same process, and projects already approved to connect or facilities that rely entirely on their own generation may be treated differently.

Sources

• ERCOT: PUCT approval of Batch Zero deadline exceptions
• Texas governor’s Aug. 3 directive to PUCT and ERCOT
• KERA News: ERCOT audit expected by December

The Montana Public Service Commission’s action could shape later debates over reliability, generation, transmission, data-center demand and whether customers should pay for future investments. It does not approve or reject a specific power plant, set electric rates or select a final resource mix.

What regulators found

Commissioners voted 3-1 to require NorthWestern to address problems identified in an independent review by GDS Associates, according to Montana Free Press. Billings-based Commissioner Brad Molnar was suspended and was not participating in the decision.

State regulators and the GDS review identified five areas in which the filing did not provide information the commission expected. The concerns included inadequate testing of different future scenarios, insufficient explanation and documentation of the utility’s modeling, questions about whether the analysis could be reproduced and evaluated, gaps in the explanation for proposed new resources and limited information about demand-response programs that can compensate customers for reducing electricity use.

Those gaps matter because an incomplete plan can make it harder to assess whether the utility is preparing for future demand at a reasonable cost. PSC officials warned that weak analysis could increase the risk of overbuilding facilities, which could raise rates, or underpreparing for demand and creating reliability problems.

What an integrated resource plan does

An integrated resource plan, or IRP, is a long-term study of projected electricity demand and the resources that could meet it. NorthWestern describes the process as an evaluation of future scenarios involving reliability, affordability and risk, along with existing generation, transmission, fuel systems, energy efficiency and possible resources such as natural gas, renewable energy and storage.

The plan looks ahead 20 years. It is a planning document, not a construction order or final investment decision. NorthWestern’s explanation says an IRP does not approve or build specific projects, set electric rates or lock the utility into one path.

Why the review could matter to ratepayers

The PSC’s review is not a rate case. Under Montana’s process, the commission reviews whether the filing contains required information and may return it for additional work. The review itself does not immediately change what customers pay.

But the commission’s concerns could become relevant if NorthWestern later asks regulators to recover the cost of a particular project through customer rates. The PSC has said it can consider whether costs were prudent when reviewing a future cost-recovery request.

That distinction matters because projections in a draft IRP are not the same as approved investments. NorthWestern has not received authorization through this proceeding to build a particular plant or transmission project.

Data-center demand remains uncertain

The GDS review also raised questions about the effect of possible data-center growth on future electricity demand. NorthWestern has entered agreements related to serving data centers that have not been made public, according to Montana Free Press.

Public commenters have raised concerns that large new loads could lead to generation and transmission costs being spread among existing customers. Those concerns are part of the public debate, but the available records do not establish that data centers are shifting costs to Montana ratepayers or that they caused current bill increases.

NorthWestern spokesperson Jo Dee Black said additional analysis should improve understanding of costs, reliability risks and long-term tradeoffs. The company says its planning process is intended to evaluate how to meet customer needs reliably, safely and affordably.

Separate investigation into August bill spikes

The IRP review is separate from an investigation into unexpectedly high August bills. The PSC says hundreds of NorthWestern customers have contacted its consumer affairs unit about increases on their billing statements.

The agency is working with NorthWestern to investigate the issue. Customers who saw a spike can email pschelp@mt.gov and provide the account holder’s name, service address, front and back copies of the bill and any other relevant records.

The PSC says staff will contact NorthWestern about individual cases and include submitted documentation in the broader investigation. The agency has not said that the bill increases were caused by NorthWestern’s long-term power plan.

What happens next

NorthWestern must submit revisions by September 18, 2026, or ask for additional time. The PSC will then review the response and determine whether further information is needed.

For Montana residents, the next significant questions are whether the revised filing provides clearer scenario testing, more transparent and reproducible modeling, and stronger treatment of demand response. Later proceedings involving specific investments or cost recovery could determine whether particular projects and expenses are reasonable for customers to fund.

Sources

• Montana Public Service Commission: NorthWestern Energy long-term power plan review
• Montana Free Press: NorthWestern Energy’s power plan found deficient by independent review

The action, in Docket No. ER26-2592-000, allows SPP to evaluate what it calls economic topology optimization. SPP requested an October 1, 2026, effective date so it can develop, test and implement the software needed to support the process.

The change concerns wholesale grid operations across SPP’s footprint, which covers all or parts of 17 states from North Texas to North Dakota. It does not immediately change retail electricity rates for households.

How the power-flow changes would work

Transmission congestion occurs when electricity cannot move freely over a line or other system element. Grid operators traditionally manage those constraints by redispatching power plants — changing which generators produce electricity. That approach can increase production and congestion costs.

Topology optimization adds another option. Software can identify whether opening or closing high-voltage circuit breakers would change the grid’s configuration and reroute power around a crowded or overloaded transmission element. By distributing flows differently across the existing network, the approach may reduce the need for more costly redispatch in some situations.

Under SPP’s tariff filing, market participants may submit reconfiguration requests tied to outages or constraints, and SPP may also develop a reconfiguration scenario itself. The process is intended to supplement other congestion-management tools, not replace them.

Reliability reviews remain required

A proposed reconfiguration would not be implemented automatically. SPP’s filing requires valid requests to be analyzed under multiple system scenarios and to meet requirements for system reliability, regional production cost and the effect on the transmission-congestion-rights market.

SPP must then coordinate with the local transmission operators responsible for the affected facilities. Those operators would perform a local reliability assessment and tell SPP whether the change is approved or denied. SPP may reevaluate an approved configuration as system conditions change and can return the network to its prior state or make another adjustment.

That structure matters because a switching action that reduces congestion in one operating scenario could create a problem under different conditions. The filing treats coordination with affected transmission operators as a required safeguard.

Potential savings are estimates, not guarantees

A study by NewGrid, SPP and the Brattle Group estimated that topology optimization could have produced $18 million to $44 million a year in historical real-time-market congestion savings under the applications examined. The study also found that historical system operating-limit violations could have been eliminated for 75% of the constraints analyzed.

Those figures are estimates based on historical conditions, not guaranteed savings after implementation. FERC Commissioner David Rosner separately said a comparable program in the Midcontinent Independent System Operator produced $113 million in congestion savings during 2025.

MISO’s public guidance describes a similar process in which market participants submit reconfiguration proposals, the operator studies them and reliability officials make the final implementation decision. MISO says approved changes are tied to specific studied constraints or contingencies and may be rejected or revised as system conditions change.

Better management of congestion could also reduce renewable generation curtailment when transmission constraints prevent electricity from reaching the market. That is a potential effect, not a confirmed result of SPP’s newly accepted process.

Who could be affected

The immediate participants are SPP, utilities and transmission owners, generators, market participants and local transmission operators. Renewable generators could benefit if approved reconfigurations create additional room to move power, while utilities and other market participants could see changes in wholesale production or congestion costs.

For households and small businesses, any benefit would be indirect. Wholesale savings would have to occur and then flow through utilities, state regulators and retail rate structures before they could affect electricity bills. The FERC action itself does not order a retail-rate reduction.

What the plan does not solve

Topology optimization can make more use of existing facilities, but it does not eliminate the need for new transmission construction, additional generation or long-term reliability planning. It also does not guarantee that every proposed switching action will lower costs or improve conditions.

What happens next

SPP’s requested October 1, 2026, effective date is intended to provide time for software development and testing. After the process begins, important measures will include how many proposals are studied, how often reconfigurations are approved, their reliability performance and whether they produce measurable reductions in congestion costs.

The next phase will show whether the modeled benefits translate into operating results. Until then, the FERC decision gives SPP another tool for managing power flows across its existing network, while leaving larger transmission and generation investment needs unresolved.

Sources

• Federal Energy Regulatory Commission: Rosner concurrence on SPP tariff acceptance
• Southwest Power Pool: Economic topology optimization tariff filing
• Utility Dive: FERC approves SPP topology optimization plan

The estimate was presented at a PJM Members Committee meeting on August 24 and reported by Utility Dive on August 27. It measures the effect of data-center load on PJM’s capacity market. It is not a direct surcharge on household electric bills, and it excludes data-center-related increases in energy-market and transmission costs.

What the estimate measures

PJM operates a wholesale electricity market serving all or parts of more than a dozen states and the District of Columbia. Its capacity market pays generators and other resources to remain available when electricity is needed, including during periods of high demand.

Monitoring Analytics reported that existing and forecast data-center load growth increased capacity-market revenues by a combined $29.4 billion across PJM’s last four capacity auctions. The figure is the monitor’s attribution of additional market revenue tied to higher demand; it is not a confirmed amount already paid by residential customers.

The $10.48-per-megawatt-hour figure is likewise an attribution within PJM’s wholesale market, not a calculation of what each utility customer will see on a bill. Load-serving entities, including utilities and other approved electricity suppliers, must obtain capacity through PJM’s market or through other approved arrangements. Those wholesale costs can flow into utility procurement expenses and, depending on state regulation and the utility’s rate structure, customer bills.

The effect will vary by utility territory, customer class, state rate rules and each company’s procurement strategy. Some customers may see impacts through regulated supply rates, while others may be affected through competitive contracts or later rate proceedings.

Wholesale costs rose sharply

PJM’s total wholesale power cost rose 46% year over year during the first seven months of 2026, reaching $56.7 billion, or $116.53 per megawatt-hour, according to market-monitor data cited by Utility Dive. During the comparable period in 2025, the figures were $38 billion and $79.57 per megawatt-hour.

The increase reflected higher energy and capacity costs. The market-monitor estimate does not say that data centers caused the entire 46% increase, nor does it measure the full cost of data-center growth across PJM’s wholesale system.

Reliability is part of the dispute

Monitoring Analytics identified large data-center loads as a direct cause of higher capacity prices and warned that prices could rise further without changes to PJM’s market design. The issue is also about reliability: grid planners must add new demand without allowing load growth to outpace available generation and transmission.

PJM’s actual reserve margin on June 1, 2026, was 18.4%, below the 18.6% target cited in the market-monitor report. A reserve margin measures available generating capacity above expected demand. The comparison does not by itself establish an outage or reliability emergency, but it illustrates the challenge of adding large loads while maintaining operating headroom.

What happens next

On June 18, 2026, the Federal Energy Regulatory Commission issued orders directing all six regional grid operators under its jurisdiction to justify or reform tariffs governing data centers and other large energy users. FERC said the orders address issues including cost allocation, co-located generation and generation adequacy.

The orders are regulatory actions requiring further review or tariff changes, not a completed nationwide solution. The next major questions are whether PJM’s proposed changes for large-load integration and reliability are accepted, modified or rejected by FERC, and how regulators allocate costs between data centers and other customers.

For households, the immediate takeaway is narrower than the headline number may suggest: $10.48 per megawatt-hour is a PJM wholesale capacity-market estimate, not a fixed increase on every electric bill. The broader consumer impact will depend on how utilities procure power, how state regulators review costs and whether future market rules require large new customers to bear more of the expenses associated with their demand.

Sources

• Monitoring Analytics — 2026 Quarterly State of the Market Report for PJM: January through June, Section 5: Capacity
• Utility Dive — Data center load made up 9% of PJM wholesale costs so far in 2026
• Federal Energy Regulatory Commission — Large Load Integration Orders

Gov. Gavin Newsom and legislative leaders had not released final public bill text as of Friday, Aug. 28, 2026. Lawmakers faced a Friday deadline to publish bills before voting, and the regular legislative session ends at midnight Monday, Aug. 31. Until a bill is published, passed by both chambers and signed or otherwise enacted, the proposals do not change California insurance, utility or wildfire-liability law.

What Newsom is proposing

A central proposal would eliminate or restrict insurance subrogation after a utility-caused wildfire. Subrogation allows an insurer that has paid a homeowner’s claim to seek reimbursement from the company responsible for the damage.

Newsom’s stated goals are to prioritize and accelerate payments to survivors, reduce litigation, protect utility financial stability and limit pressure on electricity rates. His broader package has included limits on attorney fees, restrictions on hedge-fund purchases of wildfire claims and changes to how claims are prioritized.

Negotiating documents and reports have described possible limits on pain-and-suffering and other non-economic damages. They also have raised restrictions on how much local governments could recover for destroyed roads, public buildings and other infrastructure. Those provisions remain disputed and could change or disappear before any bill is introduced.

Why insurers object

Insurance executives say eliminating or limiting subrogation would transfer billions of dollars in wildfire costs from utilities to insurers and, ultimately, their customers. The Personal Insurance Federation of California has warned that premiums could rise by as much as 50% in areas facing severe wildfire risk.

That figure is an industry estimate, not a statewide forecast or an approved rate change. Any effect on premiums or coverage availability would depend on the final law, insurers’ costs, regulatory approvals and the location and risk of a property.

California homeowners would not automatically see an immediate increase. The practical question is whether insurers would be left with more losses they cannot recover from utilities and respond by seeking higher rates, reducing exposure or declining to write some policies.

How the Wildfire Fund fits in

California’s existing Wildfire Fund was created in 2019 to help protect participating utilities from financial instability after eligible wildfires caused by their equipment. The participating utilities are Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric.

The fund has approximately $21 billion in claim-paying capitalization, divided roughly equally between utility shareholders and ratepayers. Shareholders supplied about $10.5 billion, while ratepayer contributions are collected through monthly non-bypassable charges on eligible utility bills. The fund explainer reported more than $12 billion in liquid assets under management as of January 2025.

The fund does not pay private residents directly. It reimburses eligible participating utilities for covered claims under statutory conditions. Participation also requires utilities to meet safety and wildfire-mitigation requirements, including approved wildfire mitigation plans and safety certifications.

The California Senate’s background paper identifies the fund, subrogation claims and the distribution of wildfire liability as policy questions that lawmakers have continued to examine rather than settled answers.

Why survivors and lawmakers are pushing back

Wildfire survivors, local governments, consumer advocates and some lawmakers argue that the proposed limits could reduce accountability or leave communities with more uncompensated damage. Assembly and Senate negotiators have opposed or questioned provisions involving non-economic damages, insurance reimbursement and local-government recovery.

The Eaton Fire is the immediate backdrop. Earlier this month, state and Los Angeles fire officials found Southern California Edison responsible for the January 2025 fire’s ignition. The blaze killed 19 people and destroyed about 9,400 structures. That investigative finding is distinct from final court judgments, settlements and other legal resolutions involving individual claims.

Reports on the negotiations say any new rules would apply only to future wildfires, not automatically rewrite existing Eaton Fire claims. Survivors and local governments could face different consequences depending on final rules governing damages, claims priority and reimbursement.

What happens next

Lawmakers must publish a bill before they can vote on it. Any measure would then need to pass both legislative chambers before the Aug. 31 session deadline and take effect under California’s enactment rules. No new statewide insurance or wildfire-liability law was confirmed in force as of Aug. 28.

Residents should watch for a published bill, committee action and final votes before assuming their insurance, utility bills or legal rights will change. The main policy question remains who will absorb future utility-caused wildfire losses: utilities and shareholders, insurers and policyholders, ratepayers through utility bills, taxpayers or some combination.

Current insurance protection for some wildfire survivors

Separately, California law provides a mandatory one-year moratorium on wildfire-related cancellations and non-renewals for qualifying residential policyholders in ZIP codes within or adjacent to certain declared fire perimeters. The protection lasts one year from the date of the governor’s emergency declaration and applies to covered policyholders who suffer less than a total loss, while people with a total loss receive additional protections.

The Department of Insurance works with Cal Fire and the Governor’s Office of Emergency Services to identify affected ZIP codes. The department’s current list includes an Aug. 6, 2026 declaration for the Gann Fire in Calaveras County, along with declarations for earlier fires including the 2025 Eaton Fire.

Homeowners who receive a wildfire-related cancellation or non-renewal notice should check whether their ZIP code is covered and contact the California Department of Insurance if an insurer refuses to reinstate a policy protected by the moratorium.

Sources

• Los Angeles Times: Insurance executives warn Newsom plan would raise premiums
• KPBS/CalMatters: Lawmakers reject key parts of Newsom’s wildfire plan
• California Senate background paper on utility wildfire liability
• California Wildfire Fund media explainer
• California Department of Insurance: Mandatory one-year moratorium on non-renewals

The PUC is reviewing a general rate case and a separate Phase-In Plan Rate request tied to the Lange II generating project. The proposals could affect approximately 75,000 Black Hills Energy customers in South Dakota. The dollar figures are company estimates for a residential customer using about 650 kilowatt-hours per month; actual bills would depend on final commission decisions, customer usage and rate class.

General rate case seeks $50.6 million annually

Black Hills Energy filed its general rate case, docket EL26-003, on February 19, 2026. The company is seeking approximately $50.6 million in additional annual revenue, representing a proposed overall increase of about 25.1%.

For a typical residential customer using 650 kilowatt-hours per month, the company says the request would add $25.13 to the monthly bill. The July 28 PUC agenda also identifies approximately 75,000 potentially affected customers.

Docket EL26-003 remains pending. The commission’s July 28 agenda described the company’s request and customer estimate; it did not approve the proposed rates.

Separate Lange II request could add $19.70

In a separate proceeding, docket EL26-024, Black Hills Energy filed an application on August 5 to amend its Phase-In Plan Rate. The company is seeking approximately $39.5 million annually through the proposed rate mechanism.

The request would recover actual and forecasted costs associated with Lange II. According to the company’s application, the project is a generating plant with 97.4 megawatts of net capacity, located northwest of Rapid City on 160 acres owned by Black Hills Energy.

Black Hills Energy estimates the phase-in request would add another $19.70 per month for a typical residential customer using about 650 kilowatt-hours. The company has requested a December 1, 2026, effective date. That date is proposed, not confirmed, and docket EL26-024 remains pending.

How the potential bill estimate is calculated

The two proposed additions total $44.83 per month:

• $25.13 from the general rate case
• $19.70 from the Lange II Phase-In Plan Rate request
• $44.83 in combined proposed additions

The company’s bill-impact materials use a current-rate residential bill of $98.96 for the 650-kilowatt-hour comparison in the general rate case. Adding the proposed $25.13 general-rate increase produces a $124.08 bill under the proposed general rates. Adding the separate $19.70 Lange II phase-in amount to that figure produces an estimated combined bill of about $143.79.

That calculation is not a universal bill amount. It applies to the usage and customer assumptions in the company’s filings, and it assumes both requests are approved at the stated levels. Higher- or lower-use households, commercial customers and other rate classes could see different impacts.

What happens next

The PUC will review the filings, testimony, cost information and customer impacts. Intervenors, including large commercial customers and other affected parties, may participate in the proceedings and examine or challenge the requests.

On August 25, the commission’s agenda described the Lange II request and asked whether the proposed tariff revisions should be approved. The docket later showed an August 26 procedural order assessing a filing fee and authorizing consulting contracts; those actions did not approve the proposed rate.

For the Lange II case, Black Hills Energy has asked for authority to begin collecting the proposed phase-in rate on an interim basis if the project is in service and the commission has not issued a final order by December 1. The application says any interim collection would be subject to refunds while the PUC completes its review.

Customers should not assume that the full proposed increase will appear on future bills. The final amounts, timing and customer-class impacts will depend on commission decisions in EL26-003 and EL26-024. Residents can follow those dockets and future PUC orders for revised estimates, decisions and effective dates.

Sources

• South Dakota PUC docket EL26-003: Black Hills Energy general rate case
• South Dakota Searchlight: Average Black Hills Energy customer faces potential $45 increase

The plan applies to Rhode Island Energy electric and natural-gas accounts. Electric customers are scheduled to receive a fixed account credit on bills rendered from October 2026 through September 2027. Gas customers are scheduled to receive credits beginning in December 2026, but part of the gas allocation will first be used to offset deferred gas-cost balances.

What electric customers will see

All Rhode Island Energy electric accounts are included in the plan approved by the PUC on August 21, 2026. Rhode Island Energy estimates the fixed credit at approximately $14 per month for 12 months.

The electric credits are scheduled to begin with bills rendered in October 2026 and continue through September 2027. They expire beginning with bills rendered in October 2027.

The credit will be applied to the account. It is not a new state-funded rebate or a universal cash payment. A customer’s total bill can still vary because of electricity usage, supply costs, taxes and other charges, so the credit should not be read as a guarantee that every bill will fall by exactly $14.

How the gas credits will work

All Rhode Island Energy gas accounts are included in the gas portion of the plan. Credits are scheduled to begin with bills rendered in December 2026 and continue through April 2027.

The PUC required a two-step process. First, Rhode Island Energy must offset amounts owed by gas customers on deferred gas-cost balances as of the end of October 2026. The remaining credit balance will then be distributed through a uniform monthly bill credit.

Rhode Island Energy estimates the monthly gas credit at approximately $51. The final amount depends on the required calculations, the deferred-cost offset and later reconciliation, so customers should not assume that every gas bill will fall by exactly $51. The gas credits expire beginning with bills rendered in May 2027.

Why the credits are being issued

The credits are tied to PPL Corporation’s 2022 acquisition of Narragansett Electric, now doing business as Rhode Island Energy. The hold-harmless commitment was intended to protect Rhode Island customers from certain accumulated deferred income-tax effects associated with the acquisition.

The PUC denied Rhode Island Energy’s acceleration proposal as filed but authorized a modified version. The commission required separate electric and gas calculations and specified a customer-centered discount-rate methodology. The Attorney General’s Office said on August 27 that the calculation produced an additional approximately $21.3 million in credits, bringing the total value to approximately $170 million.

Rhode Island Energy announced on August 25 that it would move forward with the modified plan. The company must still complete the required calculations, billing work and reconciliation under the PUC’s conditions.

How the PUC changed the rate case

The decision also limited Rhode Island Energy’s request to raise electric and gas base distribution rates.

The PUC denied the proposed second rate-year increase, allowing only a one-year increase under the rate case. It also rejected the company’s request to raise its return on equity to 10.75% and retained the current 9.275% return. The commission adopted a capital structure with 52% equity and 48% debt, instead of the company’s proposed 57% equity ratio.

Those decisions affect the utility’s approved revenue requirements, but they do not make the temporary credits permanent rate reductions. The credits end after their specified billing periods.

What remains to be finalized

The August 21 record is a draft-minutes document memorializing the PUC’s votes. It is not a substitute for describing later compliance work as already completed. Rhode Island Energy must submit the required compliance materials and implement the credit plan in accordance with the commission’s conditions.

The PUC required Rhode Island Energy to file a comprehensive Customer Information System investment plan in a new docket by November 1, 2026. The plan must address billing-related problems, proposed time-of-use-rate planning, future bill formatting and performance measures for accurate application of approved tariffs.

The commission also directed Rhode Island Energy to file an extra-large electric-load tariff by December 31, 2026. The filing is intended to address large customers such as data centers and prevent them from adversely affecting grid reliability, shifting costs to existing customers or causing undue rate shock. The PUC said the company should initially consider a minimum demand threshold of 20 megawatts or explain why another threshold is appropriate.

What customers should do now

Electric customers should watch bills rendered beginning in October 2026 for the fixed account credit. Gas customers should look for credits beginning in December 2026, after the deferred gas-cost offset is calculated. The credits are temporary and separate from other energy-assistance programs.

Sources

• Rhode Island PUC draft minutes, August 21, 2026
• Rhode Island Attorney General summary of PUC decision, August 27, 2026
• Rhode Island Energy customer-credit announcement, August 25, 2026
• What's Up Newp report on PUC decision

The California Public Utilities Commission adopted Resolution SED-13 and the related Administrative Consent Order at its Aug. 13, 2026, conference. Under the agreement, PG&E will provide $21 million to the state General Fund and up to $1 million for an independent review of its Transmission Centralized Inspection Review Team, known as CIRT.

The settlement resolves the CPUC enforcement matter. It is not a direct compensation program for residents whose homes or property were damaged by the fire.

How the $22 million will be used

The $21 million General Fund payment is funded by PG&E shareholders. The CPUC records do not direct that money to Mosquito Fire survivors, property owners or firefighters, and the approved documents do not establish a direct effect on customer rates.

The separate, shareholder-funded commitment of up to $1 million will pay for an independent third-party review of CIRT. The review will examine the team’s policies, procedures, documentation, organizational structure, effectiveness, efficiency and compliance with the CPUC’s General Order 95 safety requirements.

CPUC staff will approve the contractor and the scope of work. The Safety and Enforcement Division also retains authority to pursue separate enforcement related to CIRT after the review is completed.

What the investigation documented

The Mosquito Fire began in September 2022 near Oxbow Reservoir in Placer County, in an area involving PG&E’s Middle Fork No. 1, Oxbow Tap and Weimar No. 1 60-kilovolt transmission circuits.

The CPUC investigation report says the fire burned 76,788 acres, destroyed 78 structures and damaged 13 others. It estimates more than $135.9 million in property damage involving PG&E and third parties. The report records no fatalities and says local media reported two firefighter injuries.

SED’s investigation identified 12 alleged violations of CPUC requirements involving repairs, loose tie wires, switch maintenance, vegetation clearance, evidence preservation, overhead-line safety and late initial notification under Resolution E-4184.

The report says investigators reviewed 13 transmission poles in the Oxbow Junction area and identified 12 violations of General Order 95 requirements. It also says PG&E filed its initial report on Sept. 8, 2022, rather than by Sept. 7, as required by Resolution E-4184.

PG&E disputed several allegations

The settlement does not represent an uncontested finding on every allegation. The CPUC resolution says PG&E agreed to certain alleged violations and agreed not to contest another, while disputing allegations involving loose tie wires, evidence preservation, switch maintenance, vegetation clearance and the timing of the incident report.

In its response, PG&E said some tie wires were not loose and argued that its operation of switches served the purpose of required function testing. The company also said vegetation within the required clearance area was minimal and separated by a rock outcrop.

PG&E acknowledged that a contractor did not complete a pole-clearance work order and that the removal of a pole and attached equipment without prior notification resulted from internal miscoordination. The company said it has since changed vegetation-management systems and procedures, added another maintenance cycle and adopted requirements for field personnel to be present before certain transmission switches are re-energized in high-fire-threat areas.

The settlement does not determine what ignited the fire

The CPUC investigation expressly says the Safety and Enforcement Division does not determine fire cause. The U.S. Forest Service is identified as the lead authority for determining the cause of the Mosquito Fire, and the CPUC report says it could be revised if the Forest Service releases additional findings.

That distinction matters because the settlement addresses alleged safety and regulatory violations by PG&E. It does not state that PG&E equipment caused or ignited the fire.

What happens next

The immediate next step is the selection of the independent reviewer and approval of the review’s scope by CPUC staff. The resulting report could produce recommendations about CIRT’s structure, responsibilities and practices.

For California residents, the case provides another example of how the state uses shareholder-funded penalties and required corrective work in utility wildfire oversight. It also sets a practical limit on what this action delivers: the $21 million payment goes to the General Fund, not directly to people who suffered losses in the 2022 fire.

Sources

• CPUC Resolution SED-13 approving the Mosquito Fire administrative consent order
• Los Angeles Times report on the proposed PG&E Mosquito Fire settlement

Enstar officials said July 28 that gas deliverability is becoming less reliable as local production and storage margins tighten. The warning affects residents, businesses and public agencies in Anchorage, the Mat-Su Valley and the Kenai Peninsula, where an interconnected gas system supports home heating and much of the region’s electric generation.

The warning concerns winter 2026-27 planning and possible future conditions. No rolling blackout, household gas shutoff or current service interruption was reported in the cited coverage, and no new household rate has been approved based on Enstar’s warning.

Why energy costs could rise

Enstar President and CEO John Sims said the utility’s current weighted average gas cost is about $10.80 per thousand cubic feet. He said imported liquefied natural gas could cost roughly $22 per thousand cubic feet.

Those are utility-provided estimates of gas commodity costs, not complete household bill amounts or approved customer rates. If Enstar must purchase more expensive supplies, however, the added cost could put upward pressure on heating bills. Higher energy expenses could also affect businesses, public agencies and municipal budgets.

Enstar serves more than 150,000 Southcentral customers and has said Cook Inlet is no longer a dependable long-term source by itself. The utility is seeking available production and evaluating additional supply, storage and import options.

Why electric utilities are involved

Southcentral’s major utilities rely on an interconnected, pressurized natural gas system. Enstar’s network serves Anchorage, the Mat-Su Valley, the Kenai Peninsula and Whittier, while gas from the system also fuels power plants operated by utilities including Chugach Electric Association, Matanuska Electric Association and Homer Electric Association.

That interconnection means a utility can have sufficient gas under its own contracts but still face regional problems if pressure in the shared system falls. The amount of exposure varies by utility because contracts, fuel mixes, storage access and backup generation differ.

Storage matters because gas can remain underground while still being difficult to deliver if the system lacks enough pressure. Cook Inlet Natural Gas Storage Alaska, known as CINGSA, is one of the region’s most important storage facilities. Utilities have said a cold spring drew down storage, while limited Cook Inlet production has slowed the refill process.

What a difficult winter could look like

Utilities are planning a sequence of responses rather than reporting that emergency measures are underway. They could first ask customers to conserve during peak demand, including lowering thermostats or reducing electricity use.

Utilities could also share gas supplies or shift some electric generation from natural gas to diesel. Chugach and MEA have backup-generation options, while Homer Electric has fewer alternatives because of its reliance on gas-fired power, according to reporting on the regional planning.

MEA’s Energy Watch program uses Green, Yellow and Red alert levels to communicate conservation requests. Its contingency plan divides members into nine groups for temporary rolling service interruptions if an energy emergency leaves too little fuel for generation. Under the plan, an affected group could experience an outage of about 30 to 45 minutes roughly once every five hours.

MEA says activation is extremely unlikely because of its backup systems. The rolling-interruption plan is an emergency preparation, not a current outage schedule.

Enstar storage proposal remains disputed

The supply warning comes as Enstar challenges a decision involving a proposed storage project in Kenai. In a July 8 order, the Regulatory Commission of Alaska denied Enstar’s request for an advance determination that the proposed Kenai Loop Pool project would be a prudent investment and closed the docket.

The proposed project would convert a depleted reservoir leased and operated by AIX Energy into a gas-storage facility. Enstar estimated the project would cost about $240 million, potentially the largest capital investment in the utility’s history.

According to reporting on the order, the commission cited unresolved questions about whether the reservoir was technically capable of serving as storage, competing applications involving the site, the timing of Enstar’s need for additional capacity, financing and the potential effect on customers. The denial was not a final finding that the proposed purchase or storage project itself would be imprudent.

Enstar filed a reconsideration petition July 24. The commission has 30 days to respond; if it takes no action, the petition is automatically denied, according to Alaska Public Media’s report on the filing. The petition remained active as of August 15, 2026.

What residents should watch next

The immediate question is whether utilities can maintain adequate supply and pressure through the coming winter without buying substantially more expensive fuel or asking customers to conserve during peak periods.

Residents should monitor Enstar, their electric cooperative or municipal utility for any official Energy Watch or conservation alert during extreme cold. Households and businesses will not all face the same exposure because utility contracts, fuel mixes, storage access and backup generation are different across Southcentral Alaska.

The longer-term options remain unsettled. Enstar is pursuing reconsideration of the storage decision and evaluating other supply choices, including imported LNG. A possible Alaska LNG project would require additional regulatory, financing and construction steps and is not a confirmed near-term solution.

Sources

• Alaska Public Media: Southcentral Alaska gas utility says bills likely to rise amid supply shortage
• Matanuska Electric Association: Energy Watch Program
• Alaska's News Source: Alaska regulators deny Enstar’s request for advance approval of Kenai gas storage project

The apparent contradiction comes from how electricity is priced, delivered and used. Wholesale power is only one part of a residential bill, and hotter conditions can increase the amount of electricity a household consumes even when the market price for power falls.

What the latest federal forecast says

The U.S. Energy Information Administration released its latest Short-Term Energy Outlook on August 11, 2026. The forecast was completed August 6. EIA projects the average U.S. residential electricity price at 18.3 cents per kilowatt-hour in 2026, compared with 17.3 cents in 2025.

That is a national retail-price measure, not the same thing as the wholesale price paid in regional electricity markets. It also is an annual forecast, so it should not be read as the exact rate every household will pay during the summer.

The Federal Energy Regulatory Commission’s 2026 Summer Energy Market and Electric Reliability Assessment projects load-weighted wholesale electricity prices at benchmark trading hubs to average about $46.81 per megawatt-hour during summer 2026, down 5% from summer 2025.

Wholesale and retail prices are not the same

Wholesale electricity is bought and sold among generators, power marketers and utilities. A household bill generally combines the cost of electricity with transmission and distribution charges, utility infrastructure costs, fuel adjustments, taxes, fixed fees and other charges approved through state or federal regulatory processes.

A lower wholesale price may eventually affect some retail customers, but the change may not flow through immediately or completely. Utilities may buy power under contracts, recover infrastructure expenses through separate charges or adjust rates on schedules set by regulators.

Regional markets are moving in different directions

FERC’s assessment projects the largest wholesale-price declines in the Northwest, down about 41%; the Southwest, down about 22%; and the Midcontinent Independent System Operator region, down about 17%.

Three regions are projected to see increases: ERCOT, up about 11%; PJM, up about 5%; and SERC, up about 5%. Those figures describe regional wholesale markets, not the exact retail rate or total bill for every household in those areas.

FERC also projects higher electricity use during the June-to-September cooling season. Residential consumption is projected at 604 terawatt-hours, 4.1% above the average for the previous five summers. August residential consumption is projected to be 6% above that five-year average.

Why a household bill can still rise

The National Energy Assistance Directors Association and the Center for Energy Poverty and Climate estimate that average summer residential electricity expenditures will reach about $792 in 2026, up from $717 in 2025. The estimate covers June through September and represents a national average, not a prediction for every household.

Usage is a major reason. Air conditioners and heat pumps can run longer during hot weather, increasing the number of kilowatt-hours a household uses. A higher retail rate multiplied by higher usage can produce a larger bill even when wholesale prices are lower on average.

The NEADA estimate should not be treated as directly comparable to FERC’s wholesale-price forecast. NEADA and the Center for Energy Poverty and Climate estimate household expenditures, while FERC reports regional market-price projections.

What readers can check now

Households preparing for higher summer bills should review the rate per kilowatt-hour, delivery charges, fixed fees and recent usage on their utility statement. Comparing the same months across years can help show whether a change came mainly from the rate, consumption or both.

Customers can ask whether their utility offers budget billing, time-of-use pricing, payment arrangements or efficiency programs. Anyone struggling to pay should contact the utility and the state or local energy-assistance administrator early. Eligibility rules, application windows and available funding vary by state and locality.

The forecasts are not guarantees. Weather, fuel costs, regional demand and utility decisions can change the final result. But the central lesson is clear: a lower wholesale price is not the same thing as a lower household electric bill.

Sources

• U.S. Energy Information Administration, Short-Term Energy Outlook — August 11, 2026
• Federal Energy Regulatory Commission, 2026 Summer Energy Market and Electric Reliability Assessment
• NEADA and Center for Energy Poverty and Climate, Summer Residential Cooling Outlook
• Utility Dive, US wholesale power prices to decline 8% this summer: EIA

Under the approved rules, a proposed data center must be at least 1,500 feet from schools. The same 1,500-foot separation applies to religious institutions, hospitals and nursing homes, as well as residential areas.

The action establishes how the city will evaluate a potentially high-demand industrial use. It does not mean Bowling Green has approved a data center, and the sources do not identify a specific applicant or project inside the city.

What the rules address

Data centers can require substantial utility and infrastructure capacity, making their location a local land-use issue as well as an economic-development question. The Bowling Green policy sets a measurable distance between proposed facilities and several types of nearby uses.

The listed separation areas include places where people live, attend school, receive medical care, obtain nursing services or gather for religious purposes. Residential areas are included in the requirement, placing housing compatibility among the factors the city will consider when reviewing a proposal.

The regulations were described as among Kentucky’s most stringent data-center rules. That description concerns the relative strictness of the policy; the packet does not provide a comparison with specific ordinances in other Kentucky cities or counties.

Why the issue came before commissioners

The policy followed public concerns about the possible effects of data centers, including water use, electricity demand, noise and environmental impacts. Residents also raised questions about whether existing infrastructure could support such facilities.

Those concerns matter because the city’s rules will shape where a future proposal could be located and what kinds of nearby land uses must be separated from it. The requirements may also make utility capacity, noise and environmental questions part of the local discussion around any future application.

However, there is no project-specific filing in the approved source material. That means the city’s actual future water or power needs cannot be quantified from this action alone. The regulations set a framework for reviewing potential development; they do not establish the demand of a particular facility.

What is known next

The city’s official website is the primary municipal source reviewed for current announcements and policy material, but the accessible search results did not expose the final ordinance number or the full adopted text.

A June 8 public discussion identified a June 5 Bowling Green Daily News report as describing the commissioner-approved regulations and the 1,500-foot separation requirements. The discussion also referenced the public concerns about water, electricity, noise, environmental effects and infrastructure capacity.

For now, the next practical step would be any future data-center proposal submitted under the new rules. No applicant, approved project or additional city deadline is identified in the approved material.

The city’s Community Development Department lists the Building Fee Update on its official department page and identifies Aug. 1, 2026, as the effective date. The department handles building and planning responsibilities, along with historic-preservation functions.

For permit applicants, the effective date means the city’s updated fee schedule is now the relevant schedule for covered permitting activity. The available city material does not identify the individual fee amounts or percentage changes, so the size and direction of specific changes cannot be stated from the approved information.

What the fee update means for applicants

Building fees are part of the cost of moving a construction or development project through the city’s permitting process. The update therefore matters most directly to people and organizations applying for building permits in Bozeman.

The city’s published information does not establish that every building fee increased, and it does not specify that the update applies to every permit type. Those details would require the individual fee schedule or additional city documentation.

That distinction is important for applicants estimating project costs. The confirmed change is the effective date of the updated schedule, not a citywide percentage increase or a uniform change across all permits.

Broader construction context

The fee update arrives alongside a significant city construction program announced earlier in 2026. The City of Bozeman said its 2026 construction season includes 14 transportation and utility projects.

The announced program totals $28,830,898. The city identified its Transportation & Engineering and Utilities departments as the agencies announcing the projects, placing the fee change within a broader period of public-works activity involving roads, transportation infrastructure and utilities.

The infrastructure announcement is context for the construction activity occurring across city government; it is not a new August action. The approved information does not provide project-by-project completion dates, schedules or status updates, so the 14 projects should not be described as completed or confirmed to be on schedule.

What happens next

The immediate next step for applicants is to use the updated schedule for applicable permit work now that its Aug. 1 effective date has arrived. The city’s Community Development Department remains the official source identified for the fee update and its building and planning functions.

For the public, the two developments show separate sides of Bozeman’s construction environment: private applicants face a current regulatory change when pursuing building permits, while the city has announced a multimillion-dollar transportation and utility program for the 2026 construction season.

More precise conclusions about the cost impact will depend on the individual fee amounts, any percentage changes and which permit categories are covered. Those details are not included in the approved city information.

The proposed ordinance was presented to Augusta’s Public Services Committee on July 14, 2026. It remains a draft and has not been approved, finalized or enacted as law, according to Augusta government materials.

The review follows earlier Augusta Commission discussions about a temporary moratorium on new data-center development. The approved materials confirm those discussions but do not establish the duration or exact legal status of any moratorium extension.

What the proposed ordinance covers

The draft would create Augusta’s first comprehensive local framework for data-center development. It addresses both where the facilities could be built and how they would operate after construction.

Among the proposed subjects are the zoning districts that could accommodate data centers, required setbacks, buffering, site design and landscaping. The draft also includes standards for noise and lighting, issues that can affect nearby property owners and the compatibility of large industrial or technology-related facilities with surrounding areas.

Other sections address utility capacity and coordination, emergency access, stormwater management and ongoing compliance monitoring. Those provisions place utility planning, public safety access and environmental site management inside the same regulatory discussion as zoning and land use.

The proposal does not, by itself, approve a particular facility. The available materials do not identify an approved or rejected data-center project in Augusta.

Three scheduled review points

Augusta’s publicized review schedule included three meetings in July. The Planning Commission was scheduled to review the draft on July 6, followed by the Public Services Committee presentation on July 14 and Augusta Commission consideration on July 21.

The city invited residents, property owners, businesses and other community stakeholders to review the proposal and submit comments. That gives people who could be affected by future siting, construction or facility operations a formal opportunity to weigh in before any final action.

The city identifies Augusta Planning & Development, the Augusta Planning Commission and the Augusta Commission as participants in the ordinance process. Relevant government meetings are identified at Augusta’s municipal building, 535 Telfair Street.

What is known about the next step

The scheduled next step after the July 6 Planning Commission and July 14 committee reviews was Commission consideration on July 21. The approved materials do not confirm that the Commission adopted the ordinance at that meeting.

A separate Aug. 5 report from WRDW News 12 said Augusta leaders extended a moratorium on new data centers after discussing how to proceed with regulations. The approved packet does not establish the vote, duration or exact wording of that reported extension, so those details should not be treated as confirmed here.

For now, the clear local development is the continued review of a proposed regulatory framework. If adopted, the ordinance could shape future decisions involving land use, neighborhood separation, utility coordination, noise, lighting, emergency access, stormwater and compliance. Until Augusta documents final action, however, the proposal remains under consideration rather than an enacted set of data-center rules.

The proposal would establish city land-use rules for data-center development, but it does not approve a specific data-center project. The council also could amend the draft, defer a decision or reject the ordinance instead of adopting it Aug. 10.

What the council is considering

The ordinance concerns the Fayetteville Unified Development Ordinance, the city’s framework for land-use regulation. Its potential effect is broader than a single development application because it could shape where and under what conditions data centers are developed in Fayetteville.

CityView NC reported that the Aug. 10 hearing will address the current draft and that the council could vote on adoption during the hearing. The City of Fayetteville’s official meeting calendar also lists the city’s council schedule, including an Aug. 3 work session and related council meetings.

The available source material does not include the full final draft text or the exact language of any vote. That means the specific requirements the ordinance might impose cannot be summarized here without going beyond the approved records.

Why the issue matters locally

Data centers can affect several areas of city policy at once, making the ordinance relevant to land use, utilities and environmental oversight. The rules could also influence how future economic-development proposals are evaluated in Fayetteville.

Public opposition and debate have focused on potential environmental and utility effects, according to CityView NC. Those concerns are part of the public discussion around the ordinance; they are not a finding that a particular data center has caused harm or that the draft will produce a specific result.

The immediate decision before the council is therefore about regulation, not project approval. No source in the approved packet says Fayetteville has approved or rejected a data center, and the draft should not be described as a moratorium unless adopted language expressly creates one.

What happens next

The public hearing is scheduled for Monday, Aug. 10. The council may consider adoption after hearing from the public and discussing the draft, but the timing and outcome remain uncertain.

If the council adopts the ordinance, it would become a city land-use regulation governing future data-center proposals under the terms of the adopted measure. If members amend, defer or reject it, the Aug. 10 meeting would not produce final adoption of the current draft.

For Fayetteville residents, developers and utility stakeholders, the hearing is the next documented step in a debate over how the city should handle a type of development with implications for land, infrastructure and environmental review. The council’s action will determine whether the current draft moves into effect, changes before adoption or remains unresolved.

The city’s RFP No. 27-006SB, issued July 20, covers approximately 15,000 linear feet of water-distribution mains under the Grand Quadrant Waterline Replacement project. The city has not awarded a design contract or a construction contract through this solicitation.

Consultant proposals are due Aug. 25

Interested firms must RSVP by 4 p.m. Wednesday, August 5, for the mandatory meeting. The meeting is scheduled for 10 a.m. Thursday, August 6, through Microsoft Teams. Proposals must be submitted electronically by 2 p.m. Tuesday, August 25, through the city’s PlanetBids vendor portal.

The RFP also lists Aug. 11 as the deadline for written consultant questions and Aug. 17 as the date the city expects to issue responses. The tentative schedule calls for proposal evaluation to be completed Sept. 9, possible consultant interviews Sept. 16, negotiations beginning Sept. 28 and consultant selection on or about Oct. 5. Those dates are subject to change through the procurement process.

If a consultant is selected, the RFP anticipates City Council consideration on Nov. 4 and a possible notice to proceed on Nov. 9. Issuing the RFP does not require the city to make an award.

City cites pipe age and size, not a hydraulic problem

The RFP describes the affected mains as either smaller than Corona’s current 8-inch design standard or beyond their expected useful life. It also states that the city has identified no hydraulic concerns in the downtown area.

Instead, the document cites compliance with requirements of the California State Water Resources Control Board’s Division of Drinking Water as a reason for pursuing replacement work. The RFP does not describe the existing lines as unsafe or failing.

Design work would prepare for a later construction decision

The requested consultant services include surveying, utility-conflict analysis, design memoranda, construction documents, pavement-restoration planning, and support for bidding and construction administration.

The city’s capital-improvement records identify the broader project as a downtown Grand Quadrant utility project. An earlier capital plan described the parent project as combining Grand Quadrant waterline work, with individual child projects to be requested as they become ready for construction. That record placed the project in the design phase rather than the construction phase.

The current RFP estimates future construction at approximately $12 million. That is a planning estimate for a possible later construction phase, not the price of an awarded design contract, an awarded construction contract or a confirmed final project cost.

According to the RFP, the city anticipates bidding and awarding a future construction contract in September 2027, followed by a targeted 12-month construction period ending in September 2028. Those are projected milestones, not guaranteed dates, and they depend on later design, funding, approvals and contracting decisions.

Specific street and traffic impacts are not yet established

Residents and downtown businesses could eventually see utility and pavement work if the project advances, but the current RFP does not establish specific streets, properties, closures, water outages, customer impacts or construction dates.

The city reserves the right to accept or reject proposals, withdraw or cancel the RFP, postpone the process or decide not to award a contract. Later city action will determine whether design services proceed and whether any waterline construction is ultimately authorized.

Sources

• Grand Quadrant Waterline Replacement RFP, RFP No. 27-006SB
• City of Corona FY 2024-2033 Capital Improvement Project Summary

NERC must submit both the proposed reliability standards and related changes to its Rules of Procedure by December 31, 2026. The action, taken in FERC Docket RD26-7-000, addresses reliability risks associated with rapidly growing large electricity users, including artificial-intelligence and cryptocurrency data centers.

Why computational loads raise a reliability issue

The concern is not only how much electricity these facilities consume. Large computational loads can also change their demand very quickly. A facility may reduce or shift power use within seconds, creating a sudden imbalance that grid operators must manage through generation, transmission and voltage or frequency controls.

NERC’s large-load work identifies rapidly expanding computational facilities as a growing operational issue and points to customer-initiated load reductions and oscillations that can occur on very short time scales.

A separate July 22 event in the PJM Interconnection region illustrated why sudden load changes are receiving attention. Reuters reported that more than 3 gigawatts of data-center demand abruptly went offline after a transmission-line outage in northern Virginia. PJM reported a change in grid frequency but said the event did not affect reliability. The event occurred after FERC’s July 16 action and was not identified as the reason for that order.

What FERC ordered

FERC directed NERC to develop and file new or modified reliability standards addressing risks tied to integrating computational loads into the Bulk-Power System. The commission also directed NERC to propose revisions to its Rules of Procedure, including criteria for determining which computational-load entities should be included in the applicable registry.

That registry question matters because the July action does not automatically make every data center a NERC-registered entity. The criteria still have to be developed, filed and reviewed.

FERC’s public meeting page says its summaries are general synopses and are not substitutes for the individual Commission orders. FERC’s July 16 action notice separately confirms that the commission acted on the computational-load item under Docket RD26-7-000.

What does not change immediately

The July 16 action is a directive to develop and file standards. It is not a final nationwide operating rule that immediately imposes a complete new compliance regime on all AI data centers.

After NERC files its proposals, FERC will review them. The commission could approve, reject or require changes to the filings before any new standards take effect.

Why utilities and customers should watch

Future standards could affect how large computational facilities connect to the grid, what operating information they provide, how they coordinate with utilities and how they respond during reliability events.

Utilities and regional grid operators may need to account for both sustained demand growth and fast changes in demand when planning transmission, generation and system controls. Data-center developers could face additional technical studies, communications requirements or operating obligations if later proposals are approved.

Cost allocation is another issue to watch. The July action itself does not create an immediate nationwide increase in household electric bills. Later standards, interconnection decisions, transmission planning and rate proceedings could raise questions about which costs are assigned to large new customers and which are shared more broadly, but those outcomes remain unresolved.

What happens next

NERC’s first major deadline is December 31, 2026, for the proposed reliability standards and Rules of Procedure revisions. NERC’s broader large-load work also identifies a March 2027 milestone for an additional action plan. FERC review and possible revisions would follow.

For now, the practical takeaway is narrower: federal regulators are moving computational loads into the formal reliability discussion, but the detailed rules governing AI-era data centers have not yet been finalized.

Sources

• FERC July 2026 Commission Meeting Summary
• NERC Large Loads Action Plan
• Associated Press report on AI data-center grid connections
• Reuters report on the July 22 PJM disturbance

That date is the current extension date, not a guarantee that restrictions will end. Authorities may change the rules sooner if water-supply conditions improve or worsen.

What Tampa residents can do

Properties inside Tampa city limits must follow the address-based watering schedule. Residents should use the City of Tampa’s watering-day lookup to find the day assigned to their house number.

For properties under one acre, lawn and landscape irrigation is allowed only once on the assigned day, either from midnight to 4 a.m. or from 8 p.m. to 11:59 p.m. Watering is prohibited between 4 a.m. and 8 p.m.

Tampa’s schedule assigns Mondays to addresses ending in 0 or 1, Tuesdays to 2 or 3, Wednesdays to 4 or 5, Thursdays to 6 or 7, and Fridays to 8 or 9. Mixed or unaddressed properties are also assigned Friday.

The schedule applies to properties using city water or well water. Rules outside Tampa city limits, including elsewhere in Hillsborough County, may differ.

Hand watering and microirrigation

Hand watering and microirrigation of non-lawn plants such as flower beds, shrubs, palms, trees and groundcover are allowed on any day, but only from midnight to 8 a.m. or from 6 p.m. to 11:59 p.m. Those activities are prohibited between 8 a.m. and 6 p.m.

Hand watering of lawns is different: It remains restricted to the property’s assigned watering day and permitted watering hours.

Car washing and pressure washing

Residential car washing at home is limited to the assigned watering day. The city also requires a hose with an automatic shutoff nozzle.

Annual pressure washing for aesthetic purposes is prohibited under the current restrictions. Pressure washing may still be allowed for preparation before painting or sealing and for certain necessary maintenance, such as removing hazardous mold or mildew that cannot be removed by dry methods.

Regional supply remains under pressure

Tampa Bay Water reported on July 8 that the Tampa Bay region remained in a Stage 3 Regional Supply Shortage. The agency said the region had a 12-month average rainfall deficit of 14.46 inches.

At the end of June, the C.W. Bill Young Regional Reservoir held 2.28 billion gallons, or about 14.7% of its 15.5-billion-gallon capacity.

The regional shortage framework comes from the Southwest Florida Water Management District. Tampa’s city guidance provides the address-based schedule and operational instructions for properties inside Tampa.

Check before watering

Residents should verify their address-specific day and hours before running irrigation, hand-watering a lawn, or washing a vehicle at home. The current once-a-week schedule and related restrictions remain in place through October 1, 2026, unless authorities revise them earlier.

Sources

• City of Tampa: My Allowed Watering Days and Hours
• Tampa Bay Water: July 8 Supply Update

The proposal was described in a July 15, 2026 memo from the city’s planning and zoning director and appeared on Bethlehem City Council’s July 21 agenda as Bill 22-2026, under new ordinances. The measure remained proposed and had not been finally adopted as of August 5, 2026.

Special-exception review in the Industrial district

Under the draft, data centers would be permitted as a special exception in Bethlehem’s Industrial, or IN, zoning district. A qualifying project would therefore receive case-by-case review by the Zoning Hearing Board instead of automatic approval based only on the underlying zoning designation.

The proposed definition covers a facility used primarily to store, manage, process or transmit digital data. It also includes associated equipment and infrastructure such as servers, air handlers, backup generators, water-cooling and storage facilities, utility substations, security facilities and administrative offices.

Studies applicants would need to provide

The draft says required plans, studies, evaluations and mitigation strategies would have to be submitted with the zoning permit or land-development application, whichever is filed first.

An environmental impact assessment would examine, as applicable, effects on karst features, air and soil quality, surface and groundwater, wildlife, habitat and stormwater during normal and adverse conditions, including drought, extended power outages and extreme heat.

A water-utilization report would identify the water source, average and peak demand, seasonal changes, cooling-system type and efficiency, reuse or recycling measures, drought and extreme-heat assumptions, and needed system improvements. Applicants would also have to demonstrate that adequate public-water capacity exists.

Wastewater documentation would address expected characteristics, discharge volumes, discharge destinations and pretreatment needs, including domestic wastewater and wastewater associated with cooling or industrial operations. The proposal would require applicants to demonstrate adequate disposal capacity.

An energy-management plan prepared by a professional engineer would detail peak and annual electricity demand, phasing of electric load, energy sources, anticipated utility upgrades, backup power and energy efficiency. Applicants planning to connect to the electric grid would have to provide documentation from the electricity service provider that capacity is available and that the provider will serve the facility.

The proposal also calls for an electronic-waste and decommissioning plan covering servers, batteries, hazardous materials, cooling equipment and related infrastructure when equipment is replaced or a facility is retired.

Emergency response, heat and noise controls

An emergency-response plan would address fire suppression, containment, ventilation, evacuation, site access, hydrant locations, water flow, high-voltage equipment and any training needed for first responders. Applicants would also have to document the type, quantity and location of batteries, fuel and other hazardous materials stored or used on site.

A thermal-impact mitigation plan would explain how waste heat would be managed, dissipated or reused. The draft also would require a vibration study and a photometric study to demonstrate compliance with city lighting controls.

Noise standards would be supported by a pre-construction study covering mechanical equipment, air handlers, chillers, cooling towers, transformers, substations and generators. The proposed limits at the property line are 60 dBA during the day, from 7 a.m. to 10 p.m., and 55 dBA at night. Separate C-weighted limits would be 75 dBC during the day and 70 dBC at night.

The study would evaluate normal operations, peak cooling, generator testing, tonal noise, low-frequency noise and cumulative site noise. A post-construction sound study would be required no sooner than one month and no later than 12 months after the first certificate of occupancy, with additional testing possible in response to reasonable complaints or evidence of changed operations.

Wide separation and site-design standards

The draft includes a 1,000-foot separation from lots in residential zoning districts and from existing dwellings, schools, child or adult day-care centers, parks, hospitals and community recreation centers.

It also proposes a 200-foot separation from any right-of-way or from the lot line of any lot outside the Industrial district. Separately, the draft sets minimum front, side and rear yards at 80 feet and limits building height to 80 feet, including rooftop structures.

The required buffer yard would be 40 feet wide. Equipment yards, generators, substations and utility infrastructure would need secure fencing at least 8 feet high, surrounded by evergreen screening at least 6 feet high when planted and expected to reach 15 feet at maturity.

For city reviewers, the studies would establish the information needed to evaluate utility capacity, environmental effects, site design and emergency planning before a special-exception decision. For nearby residents and property owners, the proposed separation, noise, lighting, heat and emergency-response provisions would shape how any future application is evaluated.

What to watch next

The proposal’s language, timing and approval status remain subject to future council action, hearings or revisions. Residents and property owners should watch Bethlehem City Council agendas for public discussion, amendments and any final vote.

State-level activity is separate from Bethlehem’s pending local proposal. Pennsylvania Senate Bill 1359 would impose a statewide moratorium on hyperscale data-center development and permitting, according to the Pennsylvania General Assembly’s bill page. The bill was referred to the Senate Local Government Committee on June 4, 2026, and was not enacted law as of August 5, 2026.

Sources

• City of Bethlehem zoning memo and draft ordinance
• Pennsylvania General Assembly Senate Bill 1359 page

Five-year contract covers incorporated Universal City

The city selected Frontier through a competitive procurement process. The contract grants Frontier the exclusive right and duty, to the extent allowed by law, to collect and transport waste and recyclable materials from residential, commercial and industrial customers within Universal City’s incorporated limits.

The initial contract term runs from August 3, 2026, through July 31, 2031. By written agreement, the city and Frontier may add two additional two-year extension terms. The city’s request for proposals identified the same initial term and extension structure.

The City Council awarded the contract on March 17, according to Community Impact. A June 17 town hall was informational only: its official notice said no votes, decisions or other governmental actions would be taken at the meeting.

Residents should return Waste Management carts

Universal City says residents should continue using Waste Management carts until those carts are serviced and removed on their regular collection days. If trash and recycling are collected on different days, the old carts may be removed separately. Some households may briefly have both old and new carts at the curb during the transition.

Beginning August 3, Frontier will not empty Waste Management carts. Residents should use the Frontier-provided carts instead:

• Yellow lid: household trash
• Blue lid: recycling

The city has not stated that every cart exchange is complete as of August 5, so residents should follow the city’s transition instructions if an old cart remains scheduled for pickup.

Trash, recycling, brush and bulk schedules

Frontier’s service pattern includes household trash pickup twice each week, recycling pickup once each week, and brush and bulk pickup once each week. Brush and bulk collection is limited to four cubic yards per collection, which the city describes as approximately the size of a refrigerator.

Collection days may change under the new routes. Residents should enter their address in the city’s collection-day tool or use Frontier’s mobile app to check trash, recycling and bulk-and-brush schedules.

Set carts out by 7 a.m.

Universal City and Frontier instruct residents to place carts at the curb or a paved alley by 7 a.m. on collection day. The wheels should face the curb, with the handle facing the home, and carts should be at least three feet from vehicles, mailboxes, other carts and other obstructions. The city says trash must be bagged, tied and contained with the lid closed.

Recyclables should be clean, empty and loose rather than placed in plastic bags. The city’s accepted materials include aluminum beverage cans; plastic bottles numbered 1, 2, 3, 5 and 7; glass bottles and jars; steel and tin cans; paper; boxboard; and cardboard. Plastic bags, food waste, soiled paper, Styrofoam, yard waste and other listed prohibited items do not belong in the recycling cart.

Brush, hazardous waste and special items

Contractor-generated tree and landscaping debris is excluded from the city’s residential brush service. The contract also excludes brush resulting from commercial service providers, including paid tree-trimming and tree-removal companies.

For residential brush, the contract says limbs should be no longer than four feet and no more than four inches in diameter. The total weight of any stack, bag, bundle or container may not exceed 40 pounds. The city’s FAQ says no bundling is required, while Frontier’s service page says limbs must be bundled. Because the two instructions differ, residents should confirm the applicable preparation rule with Frontier before setting out brush.

Appliances containing freon, including refrigerators, require certified freon removal and an attached certification tag before collection.

Household hazardous waste must not go in either cart. Universal City’s current residential-waste page links residents to an online scheduling page for a pickup listed for August 10, 2026. Chemicals, paint, oils, corrosive or flammable materials and other hazardous items require the city’s designated handling process. Electronics and sharps may also require special handling.

Where residents can report problems

Frontier handles missed service and damaged-cart reports at 210-807-8555. Universal City directs residents with billing questions and requests for extra carts to its utility-billing department at 210-619-0713. The city says any additional-cart fee and taxes are added to the monthly utility bill; this article does not assume that the base residential rate changed.

With the new contract only two days into its initial service period, cart-exchange completion, route performance and the conflicting brush-bundling instructions remain matters for residents and the city to monitor.

Sources

• Universal City Residential Waste Services and FAQ
• Frontier Waste Solutions Universal City service page
• Community Impact report on the contract award

Invitation to Bid 26-04, identified in the bid documents as Project No. 10371.03, was posted June 19, 2026, and updated July 17. The city set July 29, 2026, at 2 p.m. as the deadline for sealed bids and the time for a public opening at the Wauchula Administration Building.

Tank and water-main work

The planned work includes construction of the elevated tank, associated piping, civil and electrical site work, restoration, horizontal directional drilling, fittings, valves, hydrants, testing and related construction activities.

The water-main portion calls for roughly 25,000 linear feet of 6-inch and 12-inch lines. The city’s current-projects page identifies the project as the Southwest Area Water Tower and Mainlines project and describes its purpose as the design and construction of a third elevated water tower and an extension of water mains in the southwest area of Hardee County.

That description places the work in the city’s municipal water-system context; it does not make Hardee County the project owner or establish that every county resident will receive service. The project’s stated objectives are to add elevated storage and extend distribution infrastructure in the southwest area.

The City of Wauchula lists an estimated project cost of $8,212,789. That is the city’s posted estimate, not an awarded contract price.

Procurement, not construction

The City Commission’s June 8, 2026, agenda listed ITB 26-04 for commission consideration before the solicitation was posted. The bid notice also required interested bidders to attend a mandatory pre-bid meeting at 1 p.m. on July 15. Bidders who did not attend the entire meeting were told their bids would be returned unopened.

The reviewed official records establish a competitive-bidding proceeding. They do not establish that construction has begun, that a contractor has been selected or that a contract has been executed. After bids are opened, the city may need to complete bid evaluation, issue an award recommendation, take commission action, execute a contract, complete required permits and set a construction schedule.

SRF financing and federal requirements

The bid notice says contracts awarded under the solicitation will be funded in part through the Florida Department of Environmental Protection’s State Revolving Fund program. The notice does not characterize the project financing as a grant.

Florida DEP says the Drinking Water State Revolving Fund provides low-interest financing to local governments and private utilities for planning, designing, building or upgrading drinking-water systems. The Wauchula solicitation also references federal requirements including Davis-Bacon and Related Acts, disadvantaged-business participation and American Iron and Steel provisions.

What it means locally

For Wauchula residents and customers in the affected municipal service area, the procurement creates a defined path toward additional elevated storage and expanded water distribution infrastructure. The practical effect will depend on the final contract, permits, construction schedule and completed work.

The city’s current-projects page was last updated March 16, 2026. Its design and permitting details therefore represent the city’s posted project information, not a later construction update. As of the reviewed records, the confirmed development is the bid solicitation—not a completed project, construction start or contractor award.

Sources

• City of Wauchula ITB 26-04
• Wauchula City Commission Agenda — June 8, 2026
• Florida DEP State Revolving Fund

The utility submitted its proposed final Integrated Grid Planning Request for Proposals on July 17, 2026, in Public Utilities Commission Docket No. 2024-0258. The filing does not approve any project, fuel choice or customer rate increase. Those decisions would require additional regulatory review.

What Hawaiian Electric is seeking

The main solicitation would seek nearly 1,650 gigawatt-hours of variable renewable energy, including solar and wind; 465 megawatts of grid-forming resources; and 111 megawatts of firm generating capacity.

Grid-forming resources are designed to help establish or support the grid’s voltage and frequency. Firm capacity refers to resources intended to provide power when variable renewable output is unavailable or insufficient. Hawaiian Electric says projects selected through the main procurement would be placed in service between 2031 and 2034.

The proposed resources are intended to work as a portfolio rather than as mutually exclusive alternatives. Renewable generation and storage could provide energy when available, while firm resources could support reliability during periods when wind and solar output is insufficient.

“Firm” or “fuel-flexible” describes the reliability role or operating flexibility of a resource. It does not determine whether a final project would use oil, natural gas, renewable fuels or another technology.

Why Oahu is central to the debate

Oahu would be the main focus of the separate firm-generation request. Hawaiian Electric says it wants expedited approval to pursue up to 500 additional megawatts of fuel-flexible capacity and plans to issue an all-fuels request for proposals by the end of 2026.

The utility says that future solicitation would include liquid and gaseous fuels and would compare options using factors such as price, fuel sourcing and environmental impacts. Hawaiian Electric has said it remains open to liquefied natural gas, but that any pathway should be tested through a transparent, competitive process overseen by the PUC.

Hawaiʻi Public Radio reported July 24 that the proposed expansion could create a competitive pathway for a separate 500-megawatt LNG plant proposed by JERA. JERA’s project remains a proposal, not an approved plant. HPR reported that JERA has discussed creating a separate regulated utility that could bring the project directly to the commission rather than through Hawaiian Electric’s existing competitive-bidding structure.

Hawaiian Electric says Oahu uses more than 70% of the electricity generated in Hawaii. HPR reported that petroleum supplies about 70% of Oahu’s electricity generation. Those figures make Oahu the largest immediate test of how the state balances reliability, fuel costs, emissions and energy security.

What it could mean for residents

Customers on Oahu, Maui and Hawaii Island are within the geographic scope of the proposed procurement. The plan could influence the islands’ generation mix, reliability planning and electricity costs for years, but it does not immediately change utility bills.

Hawaiian Electric says adding renewable generation and storage could reduce oil use and help meet growing demand as transportation and industrial processes become more electrified. Those are utility objectives, not guaranteed outcomes. Actual costs, savings, emissions effects and reliability benefits would depend on the projects ultimately selected, their contracts and the commission’s decisions.

Residents may also see competing interests in future filings. Renewable and storage projects could affect land use, local infrastructure and host communities. Firm-generation proposals could raise questions about fuel supply, environmental effects, long-term contracts and whether customers would bear construction or operating costs.

What regulators will review

The PUC’s integrated-grid-planning process combines generation, transmission and distribution planning. The commission says competitive procurements are overseen by the PUC, an independent observer and an independent engineer.

Commission review is intended to examine whether proposed resources serve the public interest, including reliability, pricing, environmental effects, community benefits and energy equity. The PUC also says resilience planning must test how different resource mixes perform during events such as natural disasters, cyberattacks and equipment failures.

What happens next

Hawaiian Electric’s IGP RFP process page says the final RFP is scheduled to be issued 15 business days after the July 17 filing unless the commission orders otherwise. That schedule concerns issuance of the solicitation; it is not approval of construction, project selection or cost recovery.

The filing remains part of the regulatory process in Docket No. 2024-0258. The utility’s proposed all-fuels RFP by the end of 2026 would create another stage for evaluating firm-generation options, including possible LNG proposals.

Residents, businesses and community groups should watch the docket for commission action on the RFP, later project selections, fuel choices, contracts and requests to recover costs from customers. As of August 5, 2026, the PUC had not approved the proposed projects, a fuel choice or a customer rate increase described in the filing.

Sources

• Hawaiian Electric procurement announcement, July 17, 2026
• Hawaiʻi Public Utilities Commission clean-energy framework
• Hawaiʻi Public Radio report, July 24, 2026

The project replaces the older Automated Meter Reading, or AMR, system with Advanced Metering Infrastructure, known as AMI. The city says AMI is designed to provide more detailed usage information, improve outage and maintenance response, and make utility billing more accurate.

Who is affected

The work applies to customers receiving City of Gastonia or Two Rivers Utilities water or electric service. Two Rivers Utilities serves Gastonia and several surrounding communities, but this article focuses on the rollout’s effect on customers connected to the Gastonia utility system.

Gastonia’s AMI guidance says implementation is expected to begin in the second quarter of 2026 and continue for the next 12 months. As of August 5, 2026, the city had not published exact installation times for each neighborhood. Customers are expected to receive notice before and after their meters are replaced.

What will happen at the property

Utility Service Co., Inc. is the prime contractor, and Keystone Utilities is the installation subcontractor. The city says contracted technicians will not need to enter a residence or business.

A brief interruption of water or electric service may occur while a meter is being changed. Customers should be prepared for a short disruption, but they should not assume a particular neighborhood will be served on a specific date until the city issues a notice.

Watch for payment scams

Technicians will not ask customers for money. The city says customers will not need to pay for the new meters. Residents and business owners should be cautious if anyone claiming to be part of the replacement work demands payment or says money is required to complete the installation.

Customers with questions about an installation or a problem after the work can call Gastonia utility customer service at 704-866-6714.

What could change on the bill

The city says installing AMI will not change a customer’s utility rate. That is separate from how much usage appears on a bill.

Because the new meters are intended to measure usage more precisely, some customers may see an increase in recorded water usage if older equipment was undercounting consumption. Gastonia does not say that every customer’s bill will increase. The city’s explanation is that improved readings may make previously unrecorded usage visible, while more detailed information could help customers monitor consumption and identify possible leaks.

Why Gastonia is making the change

The city says the existing AMR hardware and software are approaching the end of their useful life and are becoming more difficult to support and maintain. AMI is intended to improve billing accuracy, provide more detailed water and electric usage information, and help the city track service interruptions and respond to maintenance problems.

The city’s FY 2026 adopted budget says the AMI project has begun and expects all electric meters to be converted by late 2026 or early 2027. That is an overall electric-conversion forecast, not a neighborhood installation schedule.

For now, customers should watch for city notifications, plan for a possible brief service interruption during a meter changeout, and remember that legitimate meter technicians will not request payment.

Sources

• City of Gastonia Advanced Metering Infrastructure program