The Energy Information Administration said August 11 that it expects working gas in storage to reach 3,985 billion cubic feet in October. That is a forecast for the end of October, not a final inventory result.

What the latest storage report shows

EIA‘s weekly report released August 27 showed 3,184 Bcf of working gas in Lower 48 storage as of Friday, August 21. The total increased 15 Bcf from the previous week.

The August 21 inventory was 167 Bcf, or 5.5%, above the five-year average of 3,017 Bcf. It was also 30 Bcf below the amount in storage at the same point last year. The figures describe conditions on August 21; the report was published six days later.

Storage generally rises during the warmer months as companies inject gas ahead of winter demand. A larger cushion gives utilities and market participants more flexibility if homes and businesses need more fuel during a cold spell.

Why supplies are running high

EIA attributed the projected buildup to stronger natural-gas production and temporarily lower demand for gas used as feedgas at liquefied natural gas export facilities.

Maintenance at Freeport LNG reduced feedgas demand on the Gulf Coast, helping more gas remain in storage, particularly in the South Central region. EIA said the maintenance was expected to continue into late August while U.S. LNG exports continue to grow over the longer term.

EIA’s August Short-Term Energy Outlook forecasts the Henry Hub spot price will average $2.87 per million British thermal units in the third quarter of 2026. Under the agency’s base case, prices are expected to remain below $3 per MMBtu in the coming months because of robust production and high inventories.

Why a lower wholesale price may not lower your bill

Henry Hub is a major U.S. wholesale pricing benchmark. It is not the price every household pays.

A residential natural-gas bill typically combines the cost of the gas commodity with delivery charges, customer charges, taxes and other approved fees. Utilities may purchase gas ahead of the month when customers use it, and some use procurement or balancing plans intended to limit sudden changes in the gas-cost portion of a bill.

Local pipeline capacity and regional supply conditions can also matter. A national storage surplus does not eliminate the possibility of higher prices in a constrained local market during a period of heavy demand. Utility rate cases and gas-cost adjustments can further change what customers pay.

Weather and household usage remain central. A colder winter can increase consumption enough to offset a lower gas price. A warmer winter can reduce a bill even if the price of gas is unchanged. Two households in different service territories may therefore see different results under the same national supply outlook.

What households should expect

The storage forecast is a sign that the national market may have more supply flexibility heading into winter. That can reduce the risk of a sharp wholesale price spike if cold weather increases demand, but it is not a promise of lower monthly bills.

Actual costs will depend on how cold the winter is, how much gas a household uses, where it is located, when its utility buys gas and how much of the final bill comes from delivery and other regulated charges.

What to watch next

The next signals include additional weekly storage reports, the next EIA Short-Term Energy Outlook scheduled for September 9, winter weather forecasts and changes in LNG facility operations. Customers should also watch utility notices about gas-cost adjustments, rate cases or changes to delivery charges.

For natural-gas-heated households, the practical bottom line is mixed: the national supply picture looks supportive heading into winter, but any savings will depend on local market conditions, utility rates, weather and household usage.

Sources

• EIA August 11 storage outlook
• EIA weekly storage report

In its Gas Market Report for the third quarter of 2026, published July 7, the IEA said the conflict significantly disrupted global gas-market balances. The disruption has increased price volatility and pushed back the anticipated market-balancing effect of a wave of new LNG supply.

The outlook comes as buyers in Asia face tighter supply and higher LNG prices. The IEA estimates that Asian natural-gas demand fell 0.5% year over year in the first half of 2026, equivalent to nearly 5 billion cubic meters. The figure is preliminary and covers the first six months of the year, rather than representing a final full-year result.

A major shipping route was disrupted

LNG flows through the Strait of Hormuz were disrupted after the conflict began at the end of February 2026. Before the disruption, the route carried almost 20% of global LNG supply, according to the IEA.

The strait connects Gulf exporters, including Qatar and the United Arab Emirates, with buyers in international markets. Disruption on a route of that scale affects the availability and pricing of LNG well beyond the immediate region, particularly in markets that rely on seaborne gas shipments.

The IEA said higher LNG prices are encouraging some switching from gas to coal in Asia. That response reflects the pressure created when gas becomes more expensive or less readily available, although the report’s forecast does not reduce the global demand outlook to a single cause. Tighter supply fundamentals and market responses also shape the projection.

The forecast depends on a reopening

The IEA’s full-year outlook is based on a defined recovery scenario. It assumes that the Strait of Hormuz fully reopens during the third quarter of 2026 and that operations at undamaged regional facilities are fully restored by early in the fourth quarter.

Under that scenario, LNG deliveries from Qatar and the UAE are expected to increase progressively from July through October. Those are forecast assumptions, not confirmation that the strait has reopened or that regional facilities have been fully restored.

The timing of that recovery is central to the market outlook. A slower reopening or a longer restoration period would leave the supply disruption in place for longer than assumed in the IEA’s forecast. The report identifies the reopening and restoration timetable as part of the conditions behind its projection.

New U.S. projects do not immediately rebalance the market

The longer-term supply picture includes additional U.S. LNG capacity. Three major U.S. LNG projects reached final investment decisions since March, a sign of continued investment in future supply.

Those decisions do not mean the projects are already producing or exporting gas. The IEA said the conflict has delayed the expected market-balancing effect of the broader global LNG supply wave, meaning new projects are not eliminating the near-term impact of the Hormuz disruption.

The agency also said 2026 gas supply is forecast to remain broadly unchanged from 2025 as producers in North America, Africa and Australia increase output. That additional production is part of the market’s response, but it has not been enough to prevent the IEA from forecasting a contraction in global gas demand this year.

The next major markers for the outlook are the assumed third-quarter reopening of the Strait of Hormuz, the restoration of undamaged regional facilities by early in the fourth quarter and the planned July-to-October increase in LNG deliveries from Qatar and the UAE.

The proceeding remains pending. The commission approved a modified District SAFE plan on March 4, 2026, authorizing $150 million over three years, but later granted reconsideration requests from the Office of the People’s Counsel, the District government and the Sierra Club. No final post-hearing decision retaining, changing or rejecting the plan has been identified as of August 1.

What is at stake

Washington Gas originally asked the commission to approve $215 million over three years for accelerated replacement of aging and leak-prone gas infrastructure. The company proposed recovering eligible costs through surcharges on customers’ gas bills.

Schwalb’s July 24 request says the commission should reject the plan because regulators need stronger cost controls, better prioritization of the highest-risk pipe and a clearer analysis of the District’s climate and electrification policies. Those are positions advanced by the attorney general and other parties, not final findings by the commission.

What the commission approved in March

On March 4, the commission approved a modified version of District SAFE for July 2026 through June 2029. The commission’s program page says the modified authorization is capped at $150 million over three years, about 30% below Washington Gas’s original request.

The modified plan includes annual spending caps, a risk-scoring process intended to prioritize the most dangerous and leak-prone pipes, and requirements that Washington Gas consider alternatives to replacement before seeking approval for particular projects. The commission also included cost-recovery conditions intended to limit ratepayer exposure.

The plan’s rollout, originally scheduled to begin July 1, was temporarily paused while the commission considered the requests for reconsideration and prepared for the new evidentiary hearing. The pause did not itself impose a new customer charge or authorize additional construction.

Why the case was reconsidered

In Order No. 22855, the commission granted the reconsideration requests and identified material factual disputes that could affect the outcome. The order specifically cited the basis for increased pipeline-replacement costs, whether District SAFE achieves the highest risk reduction for each dollar spent, and how greenhouse-gas reductions should be calculated.

The order also describes disputes over the plan’s use of the JANA risk model, non-pipeline alternatives, cost controls and surcharge recovery. The July 27-28 hearing gave the parties an opportunity to present evidence and cross-examine witnesses on the issues that remained in dispute.

The District’s objections

In its post-hearing brief, the District government asked the commission to reject District SAFE. The filing argues that the plan is too expensive, does not sufficiently focus work on the highest-risk pipe and does not adequately account for electrification, climate policy or the risk that some gas infrastructure could become underused.

The District’s filing also presents analyses asserting that replacement could take many decades at the proposed pace and cost billions of dollars if extended across the system. Those estimates and conclusions are part of the District’s arguments and supporting evidence; they are not final commission determinations.

Washington Gas’s stated rationale is that replacing aging, leak-prone infrastructure can improve gas-system safety and reliability. The PSC’s modified plan attempts to retain that safety objective while adding risk prioritization, cost controls and consideration of alternatives.

What residents could see

The immediate issue for gas customers is not a new District SAFE surcharge already appearing on bills. Any future bill effect would depend on the commission’s final action and on which costs, if any, it permits Washington Gas to recover from customers.

If replacement work ultimately proceeds, affected neighborhoods could experience construction, noise, temporary service interruptions and traffic impacts. The PSC says Washington Gas must provide notice to residents in areas affected by pipeline work.

The case also raises longer-term questions about the District’s gas system: how much customers should pay for infrastructure safety, whether replacement is the most cost-effective response to particular risks, how methane and other greenhouse-gas effects should be measured, and how new investment fits with the District’s electrification and climate goals.

What happens next

The commission must consider the hearing record and subsequent filings before deciding whether to retain, modify or reject District SAFE. Order No. 22855 sets August 11, 2026, as the deadline for post-hearing briefs and says the evidentiary record will close then.

Until the commission issues its next decision, the $150 million authorization from March should not be treated as a final post-reconsideration resolution, and Washington Gas’s original $215 million request should not be described as approved.

Sources

• D.C. PSC Washington Gas Pipeline Replacement Program
• D.C. PSC Order No. 22855
• District of Columbia Government post-hearing brief
• Axios Washington D.C. hearing report

In Order No. 92541, issued July 27, 2026, the commission authorized Washington Gas Light to collect $38.134 million more in annual revenue through Maryland distribution rates. The approved rates apply to service rendered on or after July 27.

The commission estimated that an average residential heating customer will pay about $4.01 more per month. That is an estimate for a typical customer, not a guaranteed increase for every household.

What the commission approved

Washington Gas filed the Maryland rate case on Dec. 29, 2025, seeking an $82.5 million increase in annual base-rate revenue. The utility’s proposed rate design would have increased an average residential customer’s total bill by about 5.3%, according to the commission’s prehearing record.

The order says Washington Gas later identified corrections that would have put its requested revenue increase at approximately $88.1 million. The commission approved $38.134 million instead, finding that the larger increase was not supported by the record.

The approved amount concerns regulated delivery service. It does not mean every part of a customer’s gas bill will rise by the same amount. Washington Gas bills also include gas-supply charges, usage-based charges and other adjustments that can change separately.

Who is affected

The decision applies to approximately 518,000 Washington Gas residential, commercial and industrial customers in Calvert, Charles, Frederick, Montgomery, Prince George’s and St. Mary’s counties.

It is not a rate increase for every Maryland gas customer. The order covers Washington Gas’s Maryland service territory; other utilities serving different parts of the state have separate rates and proceedings.

Customers who use more gas, including during colder weather, may see a different dollar impact than the commission’s average residential heating customer. The final bill will also depend on gas-supply prices and other charges shown on the account.

Infrastructure and tax provisions were limited

The commission rejected $3.2 million tied to certain STRIDE infrastructure costs that Washington Gas sought to move into base rates. STRIDE is Maryland’s Strategic Infrastructure Development and Enhancement program for utility infrastructure replacement.

The commission said Washington Gas had not adequately documented its consideration of cost-effective non-pipeline alternatives, as required by prior commission directives and Maryland law. The order allowed the company to maintain the disallowed capital in the STRIDE surcharge and did not prevent Washington Gas from seeking recovery of those costs in the future.

The commission also shortened the repayment period for non-protected excess deferred income taxes, known as EDIT, from 25 years to five years. That change returns the tax benefit to ratepayers more quickly than the longer schedule.

Commissioners denied Washington Gas’s request to recover costs associated with its Network Geothermal Pilot at this time. The order said the proposal was not ripe for recovery and required substantial revisions before further consideration.

What happens next

The commission initiated a Phase II proceeding to address additional rate-design issues involving commercial and industrial customer classes and to consider whether certain costs must be removed from rates under the Utility RELIEF Act, enacted by the Maryland General Assembly.

Phase II is not a completed decision. The commission said additional information and stakeholder input are needed before it resolves those issues, which could lead to later changes involving rate design or cost recovery.

For residential Washington Gas customers, the immediate change is the higher delivery charge effective July 27. The commission’s $4.01 estimate provides a general guide, while actual bills will vary with household use, weather, gas-supply prices and other bill adjustments.

Sources

• Maryland PSC Order No. 92541
• Maryland Office of People's Counsel Washington Gas consumer information

The State Land Office’s July 14, 2026, letter rejects the company’s request to reconsider an earlier denial. The decision covers two proposed rights-of-way for the Green Chili Lateral pipeline, a related Green Chili Meter Station business lease and associated access across state trust lands.

The ruling blocks the proposed state-land route and related lease, creating a permitting obstacle for Project Jupiter. It does not cancel the broader data center proposal or resolve the project’s separate air-quality permit.

Why the State Land Office rejected the request

Garcia Richard’s letter says the proposed uses would not be in the best interests of New Mexico’s state land trust, which supports public schools, hospitals, universities and other state institutions. The commissioner’s decision letter says the State Land Office has discretion to deny a lease or right-of-way even when an applicant has submitted paperwork and paid filing fees.

The letter says the two rights-of-way would generate one-time payments of about $11,282.20 and $20,624.65 over a 35-year period under the State Land Office’s fee schedule. It says the proposed business lease for the meter station would produce annual payments of $43,406 over its five-year term.

Garcia Richard concluded that the projected revenue was limited compared with what the letter described as environmental and resource burdens. Those concerns include Project Jupiter’s expected demands on water and other natural resources, greenhouse-gas emissions, and effects on surrounding communities and state trust lands.

The State Land Office’s announcement said the agency was weighing its responsibility to generate income for beneficiary institutions while protecting trust lands for future generations.

What the denial affects

The rejected applications cover about 0.6 miles of the proposed 17-mile Green Chili pipeline route on state trust land. The pipeline is intended to supply natural gas to infrastructure associated with Project Jupiter in southern New Mexico.

The decision applies to the state-land segment, the proposed meter station and the related business lease. It does not decide whether Project Jupiter can proceed on other land, and it does not determine whether state environmental regulators will approve the project’s air-quality permit.

Project Jupiter’s current power proposal involves a fuel-cell-based microgrid. Documents filed with the New Mexico Environment Department describe a system that relies on natural-gas pipeline infrastructure. The State Land Office decision removes one proposed route and connection point, but the available records do not establish that it makes the larger project impossible.

What happens next

Energy Transfer has 30 days from the July 14 letter to file a petition for an administrative contest under State Land Office rules. Any contest would be a separate proceeding. The July 14 letter is the agency’s current decision, not a final resolution of a future administrative challenge.

A separate regulatory decision is also pending. The New Mexico Environment Department has scheduled a public hearing on the Project Jupiter air-quality permit for 9 a.m. on Oct. 19 at the Sunland Park Multi-Generational Center. The department’s scheduling order says the hearing will continue as necessary.

Source New Mexico reported that the Environment Department has until Nov. 23 to decide whether to issue the permit. That air-quality proceeding remains separate from the State Land Office’s pipeline decision.

The permit application was submitted by Yucca Growth Infrastructure for a microgrid intended to supply power to the proposed data center campus. Approval, denial or modification of that permit remains with the Environment Department.

The accountability question for New Mexico

The dispute highlights a recurring public question about state trust land: how should officials weigh lease and right-of-way revenue against water use, emissions, infrastructure demands and other resource costs?

New Mexico’s Land Office has a dual responsibility to generate income for designated beneficiaries while managing trust lands for the long term. In this case, the commissioner determined that the financial return described in the letter did not justify the project-related burdens identified by the agency.

For residents, the next meaningful decision points are Energy Transfer’s possible administrative contest and the October air-quality hearing. Until those proceedings occur, Project Jupiter remains a proposed development with unresolved permits and approvals—not a canceled project, a fully approved project or a project rejected statewide.

Sources

• Commissioner Garcia Richard’s July 14 decision letter
• Project Jupiter air-quality hearing scheduling order
• Source New Mexico report on the October air-quality hearing

What DIMP already requires (and what PHMSA is pushing to improve)

DIMP is part of the federal pipeline-safety framework for gas distribution systems under 49 CFR part 192, subpart P. Operators must run risk evaluations as part of DIMP, and they must also re-evaluate their DIMP at an interval based on system complexity and threat types—but not less than every five years.

In this advisory bulletin, PHMSA focuses on whether operators’ risk evaluations and related integrity decisions actually work in practice—especially for complex conditions that can compound risk.

The three effectiveness gaps PHMSA highlights

PHMSA says operators should strengthen DIMP implementation by addressing:

• High-risk infrastructure: risk evaluations should identify where genuinely high-risk conditions exist, not rely on overly simplified assumptions.
• Interactive threats: threats can combine. PHMSA emphasizes the need to consider how factors that affect likelihood and consequences can intensify each other.
• Leak-management effectiveness: leak management needs to be treated as effective protection, not just a documented program. PHMSA links this to how operators evaluate and respond to leaks over time.

PHMSA illustrates the stakes by pointing to incidents, including a February 23, 2018 Atmos Energy incident in Dallas, Texas, and a separate set of January 2024 investigation findings discussed in the notice.

Risk-model choice: PHMSA encourages probabilistic approaches

A core theme is risk-model selection. PHMSA urges operators to use the most appropriate risk models for their systems within integrity management programs, and it asks for “full consideration” of probabilistic risk models as part of that selection.

Is this a new rule or a compliance deadline?

No. PHMSA frames the document as advisory guidance issued alongside a Federal Register notice. The guidance is meant to clarify existing legal obligations and improve implementation; it is not presented as a new regulation that automatically changes enforceable requirements.

Who is affected—and what households should watch next

This notice is directed at gas distribution owners/operators. In the near term, the practical “watch next” for readers is whether local utilities update internal DIMP risk-evaluation practices and supporting leak-management procedures—particularly for interactive threats and for measuring whether leak management is genuinely effective.

• What you may notice indirectly: refinements in how companies prioritize leak detection/investigation work, and how crews plan responses for non-typical soil and other conditions that can affect leak investigation effectiveness.
• What to do as a resident: follow your utility’s instructions for gas safety, and if you suspect a leak, use the utility/emergency steps you’re given locally (rather than waiting).

What to watch from PHMSA afterward

The bulletin reinforces existing DIMP expectations while signaling where PHMSA believes implementation needs to improve. Readers can watch for whether operators adjust how they run and update DIMP risk evaluations and whether PHMSA follows up with additional guidance tied to the same effectiveness themes.

Sources

• PHMSA (Pipeline Safety) — Guidance page: Enhancing the Effectiveness of Distribution Integrity Management Programs (advisory bulletin)
• Federal Register — Pipeline Safety: Guidance for Enhancing the Effectiveness of Distribution Integrity Management Programs (2026-14071)
• GovInfo — Federal Register PDF text for 2026-14071 (PHMSA-2026-2443)

Ordinance 2026-084: Council would adopt the 2027 tax budget

The revised agenda lists Ordinance 2026-084 to “adopt the tax budget of the City of Twinsburg… for the fiscal year beginning January 1, 2027” and submit it to the county auditor—with the ordinance also listed as declaring an emergency.

The agenda page doesn’t include tax-rate or budget totals. The practical takeaway for taxpayers is to watch for the final vote and any posted effective-date language, since the budget sets the city’s financial plan heading into 2027.

Ordinance 2026-100: Natural gas aggregation continuation with opt-out provisions

Also on the revised agenda is Ordinance 2026-100, which would authorize actions needed to support the continuation of a governmental natural gas aggregation program with opt-out provisions under Ohio law, and direct the mayor to execute a supplier agreement.

If you’re served by a utility eligible for aggregation opt-out programs, the statewide Consumers’ Counsel explains how opt-out plans usually work: most are opt-out programs, meaning households are enrolled unless they take steps to opt out after receiving required notices.

• Consumers are generally expected to respond promptly to avoid automatic enrollment—typically within 14–21 days of receipt of a notice that explains how to opt out.
• Consumers also have seven days from the enrollment notice’s postmark to contact the utility to rescind without penalty.

For Twinsburg households, the “what to do” is simple: watch for the opt-out paperwork that accompanies aggregation renewals and follow the instructions on timing and how to respond.

Ordinance 2026-085: Possible updates to point-of-sale exterior inspection rules

If you’re planning to sell, Ordinance 2026-085 is the agenda item most likely to affect your home-sale checklist. The revised agenda lists it as amending Chapter 1365 regarding the city’s point-of-sale exterior inspection program.

Twinsburg’s resident-facing overview describes an exterior only point-of-sale inspection for all residential and commercial properties, conducted using standards based on the International Property Maintenance Code. The city also advises scheduling early: allow 5–7 business days for an inspection or re-inspection so any issues can be addressed or scheduled before closing.

As always, don’t assume the process won’t change—once Council takes final action, the ordinance text (and any posted updates) will clarify what documentation or steps, if any, are adjusted for the exterior inspection program.

Fees baseline: $50 point-of-sale certificate permit and $25 abandoned-property registration

The revised agenda also lists two ordinance items that could change fees tied to home-sale/property maintenance compliance.

Point-of-sale certificate permit fee: Twinsburg code lists a $50 fee for the certificate permit associated with this Chapter 1365 point-of-sale exterior inspection process.

Abandoned residential property registration fee: For abandoned residential property registration, code currently sets a $25 fee.

Ordinance 2026-086: Council would amend fees for abandoned residential property registration

Finally, Ordinance 2026-086 is listed as amending Section 1367.08 regarding the fees for registering an abandoned residential property.

The baseline code fee is $25, so if Council adopts a fee adjustment, it would directly affect the cost of compliance for property owners covered by the abandoned-property registration requirements.

What to watch next

• Taxes: whether Ordinance 2026-084 is adopted and what that means for the city’s 2027 budget plan.
• Natural gas opt-out: whether Ordinance 2026-100 advances and—most importantly—whether households receive opt-out notices with a stated response window.
• Home-sale timing and paperwork: whether Ordinance 2026-085 changes any step in the exterior point-of-sale inspection process.
• Abandoned-property fees: whether Ordinance 2026-086 changes the $25 registration fee in Section 1367.08.

Sources

• Twinsburg City Council agenda (revised) — July 14, 2026 (Ordinances 2026-084, 2026-100, 2026-085, 2026-086 listed for consideration)
• Twinsburg code — Chapter 1365.04 Fees (point-of-sale certificate fee baseline)
• Ohio Consumers’ Counsel — Energy Choice: Aggregation (opt-out basics)

This explainer breaks down what each document does—and what residents can reasonably expect to see as the Sept. 1 start date approaches.

Quick timeline (the key dates residents should track)

Feb. 9, 2026: Owingsville adopted Ordinance No. 2-2026, creating a natural gas distribution franchise framework and setting a 10-year term structure.

March 2, 2026: The Kentucky PSC issued an order in Case No. 2026-00043 addressing Delta’s request for a certificate authorizing Delta to bid on the franchise created by the city ordinance.

Sept. 1, 2026: The signed franchise agreement states the franchise “shall commence” on this date.

What Owingsville approved in Ordinance No. 2-2026

Ordinance No. 2-2026 establishes the franchise rules Owingsville planned to use to award a natural gas distribution franchise. Two provisions stand out for resident impact:

1) The franchise is non-exclusive. The ordinance states the franchise is not exclusive and that the city reserves the right to grant a similar franchise to another entity at any time. It also says franchise extensions to newly annexed territory would be on the same general terms, but subject to approval of applicable state regulatory authorities.

2) The ordinance sets a franchise-fee formula based on gross revenues. Under the ordinance, the franchise fee is 3% of the franchisee’s gross revenues received from natural gas distribution services generated within Owingsville’s corporate limits, with payment terms set out in the franchise agreement.

In other words: the city ordinance is where the franchise framework and the gross-revenue-based fee structure come from.

What the signed Delta franchise agreement says (and when it starts)

The signed franchise agreement memorializes the deal terms between Owingsville and Delta. Two key items for residents:

1) Non-exclusive franchise, term structure tied to the ordinance. The agreement states the city granted Delta a non-exclusive franchise for a term of ten (10) years, and that the franchise expires as provided in Ordinance No. 2-2026.

2) A specific commencement date: Sept. 1, 2026. The agreement states the franchise “shall commence September 1, 2026” and then expire as provided in the ordinance terms.

Practically, the commencement date is the moment the franchise relationship described in the documents is intended to begin.

How the PSC order fits in: the “bid authorization” step

The Kentucky PSC order in Case No. 2026-00043 addresses Delta’s application for a Certificate of Public Convenience and Necessity (CPCN) that authorizes Delta to bid on the franchise established by the City of Owingsville.

Two parts of the order matter for understanding what this step does—and does not do:

Need-and-demand check only. The PSC explains its authority is limited to determining whether there is a need and demand for the service.

No ruling on franchise-fee ratemaking treatment. The order also notes it does not make findings about the qualifications of the bidder, the validity of franchise provisions, or the manner in which any franchise fee is to be treated for rate purposes.

So, the PSC order supports the administrative authority that makes the franchise-bidding step possible—but residents should not assume it automatically settles how franchise-fee costs are reflected in customers’ delivery charges.

What residents should watch between now and Sept. 1, 2026

Because these documents separate “franchise framework” from “PSC ratemaking,” the most useful resident focus is on where changes show up and what source explains them.

1) Watch for rate/tariff activity separately from franchise-start headlines. If any bill impact occurs, it will typically be explained through utility tariff/rate processes rather than the commencement date alone.

2) If your utility bill changes, ask which part changed. Residents can look for whether changes are tied to franchise-fee mechanics, fuel or other regulatory adjustments, or separate approved rate components.

3) Read the franchise documents for the fee formula—not for the exact monthly bill amount. The ordinance and agreement describe a gross-revenue-based franchise fee structure (including the 3% language), but they are not the same thing as a customer-by-customer price sheet.

FAQ

Is this the same thing as gas delivery rates?
Not automatically. The PSC order emphasizes that it does not determine franchise-fee treatment for rate purposes, and the franchise documents set a franchise-fee framework rather than a resident-facing delivery price schedule.

When do franchise terms begin?
The signed franchise agreement states the franchise “shall commence” on September 1, 2026, with expiration tied to the ordinance’s ten-year structure.

Where can residents find the official documents?
Key primary sources are Owingsville Ordinance No. 2-2026, the signed Delta franchise agreement, and the Kentucky PSC Case No. 2026-00043 order.

Sources

• KY PSC order (Case No. 2026-00043)
• Owingsville Ordinance No. 2-2026

For North East residents, landlords, and local business customers, the practical question is less about the corporate dissolution itself and more about what comes next in customer-facing communications: who to call, where to report issues, and what language will change (if anything) on bills and service notices.

What the July 6 dissolution notice says

In the July 6 public notice, NEHL’s shareholders approved a proposal for the corporation to dissolve voluntarily, and the company’s board is now engaged in winding up and settling the affairs of the corporation. The notice is explicitly directed to creditors and claimants, which is part of the formal process for wrapping up the company.

North East PA Online published the notice language and includes NEHL’s registered office address.

Why it’s showing up now

The timing lines up with the regulated transition of NEHL’s natural-gas distribution system to National Fuel. The Pennsylvania Bulletin’s PUC notice describes the joint application and frames the service-area change as ending NEHL’s public-service provision in the Borough of North East Township and expanding National Fuel’s service to the Borough of North East in Erie County.

National Fuel, meanwhile, said it completed the acquisition of NEHL’s natural-gas distribution assets on May 1, 2026, after PUC approval dated April 16, 2026.

What National Fuel says customers should expect

National Fuel says NEHL customers will transition automatically to National Fuel with no interruption to natural-gas service. It also says customers will move to National Fuel’s gas supply cost rate, described as passing through the direct cost of natural gas with no profit to the utility.

For help, National Fuel gives two key lines:

• Account/service questions: 1-800-365-3234
• Gas emergencies: 1-800-444-3130

What to watch next: a practical checklist

• Save the official contact details. When you receive National Fuel’s transition communications, confirm the correct customer-service phone number and gas-emergency line.
• Update who can respond to emergencies. Landlords and small business operators should make sure tenants and staff know which line to call if there’s a gas emergency.
• Don’t assume a billing overhaul overnight. The NEHL dissolution notice shows the corporate winding-up step; it does not, by itself, prove exactly when billing formats, account portals, or bill timing details will change. Wait for the next official customer guidance.
• If something looks “off,” confirm with customer service. If bill wording, account references, or service instructions differ from what you’re used to, verify using National Fuel’s published contact information.

The bottom line

The July 6 NEHL dissolution notice is a formal signal that the company is being wound down after the regulated transition tied to North East. For customers, the next step is watching for National Fuel’s official customer communications—and using National Fuel’s published numbers for day-to-day questions and gas emergencies.

Sources

• North East PA Online — “NE Heat and Light Company Dissolution Notice As National Fuel Takes Over” (July 6, 2026)
• Pennsylvania Bulletin — PUC Notices: National Fuel Gas Distribution + North East Heat and Light Company joint application (includes service-territory framing)
• National Fuel — “National Fuel Completes Acquisition of North East Heat & Light” (May 1, 2026)